United States
Environmental Protection
Agency
Office of Water
Mail Code 4303
Washington, DC 20460
EPA-821-B-00-013
December 2000
Development Document for Final Effluent
Limitations Guidelines and Standards for
Synthetic-Based Drilling Fluids and other
Non-Aqueous Drilling Fluids in the Oil and
Gas Extraction Point Source Category
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Acknowledgments
This report was prepared by Mr. Carey A. Johnston and Mr. Marvin Rubin of the Engineering and
Analysis Division. Assistance was provided by Ms. Birute Vanatta of Eastern Research Group and
Mr. Gary Petrazzuolo, Ms. Lynn Petrazzuolo, and Ms. Nerija Orentas of Avanti Corporation.
References to proprietary technologies are not intended to be an endorsement by the Agency.
Questions or comments regarding this report should be addressed to:
Mr. Carey A. Johnston, Environmental Engineer
Engineering and Analysis Division (4303)
U.S. Environmental Protection Agency
1200 Pennsylvania Avenue, N.W.
Washington, DC 20460
(202)260-7186
johnston.carey@epa.gov
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CONTENTS
_Jage
CHAPTER I: INTRODUCTION
1. LEGAL AUTHORITY
2. CLEAN WATER ACT
2.1 Best Practicable Control Technology Currently Available (BPT)
2.2 Best Conventional Pollutant Control Technology (BCT)
2.3 Best Available Technology Economically Achievable (BAT)
2.4 New Source Performance Standards (NSPS)
2.5 Pretreatment Standards for Existing Sources (PSES) and Pretreatment Standards
for New Sources (PSNS)
2.6 Best Management Practices (BMPs)
3. CWA SECTION 304(m) REQUIREMENTS AND LITIGATION
4. POLLUTION PREVENTION ACT
5. PRIOR FEDERAL RULEMAKINGS AND OTHER NOTICES . .
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6. CURRENT NPDES PERMIT STATUS 1-10
7. REFERENCES 1-11
CHAPTER II: PURPOSE AND SUMMARY OF THE REGULATION
1. PURPOSE OF THIS RULEMAKING II-l
2. SUMMARY OF THE SBF GUIDELINES II-l
CHAPTER III: DEFINITION OF SBF AND ASSOCIATED WASTE STREAMS
1. INTRODUCTION III-l
2. INDUSTRY DEFINITION AND GEOGRAPHIC COVERAGE III-l
3. WASTE STREAMS REGULATED BY THE SBF GUIDELINES III-2
CHAPTER IV: INDUSTRY DESCRIPTION
1. INTRODUCTION IV-1
2. DRILLING ACTIVITIES IV-1
2.1 Exploratory Drilling IV-1
2.1.1 Drilling Rigs IV-2
2.1.2 Formation Evaluation IV-3
2.2 Development Drilling IV-3
2.2.1 Well Drilling IV-4
2.3 Drilling with Subsea Pumping IV-7
2.4 Types of Drilling Fluid IV-7
3. INDUSTRY PROFILE: HISTORIC AND PROJECTED DRILLING ACTIVITIES IV-8
4. REFERENCES IV-16
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CONTENTS
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CHAPTER V: DATA AND INFORMATION GATHERING
1. INTRODUCTION V-l
2. POLLUTANT LOADING AND NUMERIC LIMIT ANALYSES V-l
2.1 SBF Retention on Cuttings V-l
2.2 Days to Drill V-3
2.3 Well Count Projections Over Next Five Years V-3
2.4 Current and Projected OBF, WBF, and SBF Use Ratios V-4
2.5 Waste Volumes and Characteristics V-6
3. COMPLIANCE COSTS ANALYSES V-7
3.1 Equipment Installation and Downtime V-7
3.2 Current Drilling Fluid Costs V-9
3.3 Cost Savings of SBF Use as Compared with WBF Use V-9
3.4 Construction Cost Index V-10
4. NON-WATER QUALITY ENVIRONMENTAL IMPACT ANALYSES V-10
5. COMPLIANCE ANALYTICAL METHODS V-ll
6. SEABED SURVEYS V-ll
7. REFERENCES V-12
CHAPTER VI: SELECTION OF POLLUTANT PARAMETERS
1. INTRODUCTION VI-1
2. STOCK LIMITATIONS OF BASE FLUIDS VI-1
2.1 General VI-1
2.2 Base Fluid PAH Content VI-2
2.3 Base Fluid Sediment Toxicity VI-2
2.4 Base Fluid Biodegradation VI-2
2.5 Base Fluid Bioaccumulation VI-2
3. DISCHARGE LIMITATIONS VI-4
3.1 Free Oil VI-4
3.2 Formation Oil Contamination VI-4
3.3 Retention of SBF on Cuttings VI-5
3.4 Cuttings Discharge Sediment Toxicity VI-6
4. MAINTENANCE OF CURRENT REQUIREMENTS VI-7
5. REFERENCES VI-7
CHAPTER VII: DRILLING WASTES CHARACTERIZATION, CONTROL, AND
TREATMENT
1. INTRODUCTION VII-1
2. DRILLING WASTE SOURCES VII-1
2.1 Drilling Fluid Sources VII-1
2.2 Drill Cuttings Sources VII-3
3. DRILLING WASTE CHARACTERISTICS VII-4
3.1 Drilling Fluid Characteristics VII-5
3.2 Drill Cuttings Characteristics VII-7
3.3 Formation Oil Contamination VII-7
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CONTENTS
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4. DRILLING WASTE VOLUMES VII-8
4.1 Factors Affecting Drilling Waste Volumes VII-8
4.2 Estimates of Drilling Waste Volume VII-9
4.2.1 Waste SBF/OBF Drill Cuttings Volumes VII-9
4.2.2 SBF Drilling Fluid Retention-on-Cuttings (ROC) Values VII-11
4.2.3 Analysis of ROC Data and Determination of ROC Values VII-15
4.2.4 Calculation of SBF/OBF Model Well Drilling Waste Volumes VII-18
4.2.5 WBF Waste Volumes and Characteristics VII-23
5. CONTROL AND TREATMENT TECHNOLOGIES VII-27
5.1 BPT/BCT Technology VII-27
5.2 Product Substitution: SBF Base Fluid Selection VII-28
5.2.1 Currently Available Synthetic and Non-Aqueous Base Fluids VII-28
5.2.2 PAH Content of Base Fluids VII-30
5.2.3 Sediment Toxicity of Base Fluids VII-31
5.2.4 Biodegradation Rate of Base Fluids VII-37
5.2.5 Bioaccumulation VII-47
5.2.6 Product Substitution Costs VII-47
5.3 Solids Control: Waste Minimization/Pollution Prevention VII-48
5.3.1 Shale Shakers VII-50
5.3.2 High-G Shale Shakers VII-55
5.3.3 Centrifuges VII-56
5.3.4 Squeeze Presses VII-58
5.3.5 Fines Control VII-58
5.3.6 Rig Compatibility VII-59
5.3.7 Small Volume Wastes VII-61
5.4 Land-based Treatment and Disposal VII-62
5.4.1 Transportation to Land-Based Facilities VII-64
5.4.2 Land Treatment and Disposal VII-65
5.4.3 Land-Based Subsurface Injection VII-66
5.5 Onsite Subsurface Injection VII-67
5.6 SBF Discharges Not Associated with Cuttings VII-69
5.7 Additional Control Methodologies Considered VII-70
6. REFERENCES VII-70
CHAPTER VIII: COMPLIANCE COST AND POLLUTANT REDUCTION
DETERMINATION OF DRILLING FLUIDS AND DRILL CUTTINGS
1. INTRODUCTION VIII-1
2. OPTIONS CONSIDERED AND SUMMARY COSTS VIII-1
3. COMPLIANCE COST METHODOLOGY VIII-2
3.1 Drilling Activity Projections and Allocations for the Final Rule VIII-4
3.2 Model Well Characteristics VIII-5
3.3 Onsite Solids Control Technology Costs VIII-6
3.3.1 Baseline Solids Control Technology Costs VIII-6
3.3.2 BAT/NSPS Compliance Solids Control Technology Costs VIII-7
3.4 Transportation and Onshore Disposal Costs VIII-10
3.4.1 Baseline Transport and Disposal Costs VIII-10
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CONTENTS
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3.4.2 BAT/NSPS Transport and Disposal Costs VIII-13
3.5 Onsite Grinding and Injection Costs VIII-13
4. DETAILED ANALYSES OF TECHNOLOGY AND INCREMENTAL COMPLIANCE
COSTS VIII-14
4.1 BAT Baseline Operational Costs VIII-20
4.2 BAT/NSPS Option 1 Discharge Option Costs VIII-22
4.3 BAT/NSPS Option 2 Discharge Option Costs VIII-24
4.4 BAT/NSPS Option 3 Zero Discharge Option Costs VIII-25
4.5 Retention on Cuttings Incremental Costs (Including Fluid Recovery/Re-use) VIII-26
4.6 Costs (Savings) Due to Efficiencies of SBF Drilling over WBF Drilling VIII-27
4.6.1 Costs (Savings) for Operators Converting from WBF to SBF VIII-27
4.6.2 Cost Impacts to Operators Currently Using SBFs VIII-29
4.7 Net Incremental BAT Costs/Savings VIII-30
4.8 NSPS Compliance Cost Analysis VIII-31
5. POLLUTANT LOADINGS (REMOVALS) VIII-32
5.1 Input Data and Methodology VIII-33
5.1.1 SBF and OBF Pollutant Loadings (Removals) in Effluent Discharges,
Land Disposal, and Injected Waste VIII-33
5.1.2 WBF Well Loadings (Removals) VIII-37
5.2 Baseline Pollutant Loadings for Existing Sources VIII-38
5.3 BAT Option 1 Pollutant Loadings (Removals) for Existing Sources VIII-40
5.4 BAT Option 2 Pollutant Loadings (Removals) for Existing Sources VIII-41
5.5 BAT Option 3 Zero Discharge Pollutant Loadings (Removals) for
Existing Sources VIII-44
5.6 Pollutant Removals Analysis for New Sources VIII-47
6. REFERENCES VIII-51
CHAPTER IX: NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND OTHER
FACTORS
1. INTRODUCTION IX-1
2. SUMMARY OF NON-WATER QUALITY ENVIRONMENTAL IMPACTS IX-1
3. ENERGY REQUIREMENTS AND AIR EMISSIONS IX-2
3.1 Water Based Drilling Fluids IX-5
3.2 Energy Requirements IX-5
3.2.1 Drilling Rig Activity IX-5
3.2.2 Baseline Energy Requirements IX-7
3.2.3 Energy Requirements for BAT/NSPS Discharge Options IX-9
3.2.4 Energy Requirements for BAT/NSPS Option 3 Zero Discharge IX-10
3.3 Air Emissions IX-14
3.4 New Source Energy Requirements and Air Emissions IX-15
4. SOLID WASTE GENERATION IX-16
5. CONSUMPTIVE WATER USE IX-19
6. OTHER FACTORS IX-19
6.1 Impact of Marine Traffic IX-19
6.2 Safety IX-20
7. AIR EMISSIONS MONETIZED HUMAN HEALTH BENEFITS IX-21
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CONTENTS
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8. REFERENCES IX-24
CHAPTER X: OPTIONS SELECTION RATIONALE
1. INTRODUCTION X-l
2. REGULATORY OPTIONS CONSIDERED FOR SBFs NOT ASSOCIATED WITH DRILL
CUTTINGS X-l
3. REGULATORY OPTIONS CONSIDERED FOR SBFs ASSOCIATED WITH DRILL
CUTTINGS X-2
3.1 BPT Technology Options Considered and Selected X-2
3.2 BCT Technology Options Considered and Selected X-3
3.3 BAT Technology Options Considered and Selected X-3
3.3.1 Overview X-3
3.3.2 Stock Base Fluid Technical Availability and Economic Achievability X-9
3.3.3 Discharge Limitations Technical Availability and Economic Achievability ... X-l6
3.4 NSPS Technology Options Considered and Selected for Drilling Fluid
Associated with Drill Cuttings X-27
3.5 PSES and PSNS Technology Options Considered and Selected X-28
3.6 Best Management Practices (BMPs) to Demonstrate Compliance with Numeric
BAT Limitations and NSPS for Drilling Fluid Associated with Drill Cuttings X-29
4. REFERENCES X-30
CHAPTER XI: BEST MANAGEMENT PRACTICES
GLOSSARY AND ABBREVIATIONS G-l
APPENDIX VII-1: SBF/OBF Model Well Drilling Waste Volumes A-l
APPENDIX VII-2: WBF Waste Volume and Characteristics A-7
APPENDIX VTII-1: Derivation of Supply Boat Transport Days A-10
APPENDIX VIII-2: Cost (Savings) Analysis Worksheets A-16
APPENDIX VIII-3: (Deleted) A-55
APPENDIX VIII-4: Pollutant Loadings (Removals) Worksheets A-56
APPENDIX VIII-5: Pollutant Loadings (Removals) Supporting Worksheets A-91
APPENDIX IX-1: Non-Water Quality Environmental Impacts A-133
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TABLES
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IV-1 Number of Wells Drilled Annually, 1995 - 1997, by Geographic Area IV-9
IV-2 Estimated Number of Wells Drilled Annually by Drilling Fluid Used for Proposed Rule .... IV-12
IV-3 Estimated Number of Existing Source Wells Drilled Annually by Well and
Drilling Fluid Type for the Final Rule IV-14
IV-4 Estimated Number of New Source Wells Drilled Annually by Well and
Drilling Fluid Type for the Final Rule IV-15
VII-1 SBF Drilling Waste Characteristics VII-6
VII-2 Model Well Volume Data VII-10
VII-3 API Recommended Practice 13B-2 MDL Phase 1 Study Results VII-13
VII-4 API Recommended Practice 13B-2 MDL Phase 2 Verification Results VII-13
VII-5 Drilling Fluid Treatment System Retention on Cuttings Performance VII-17
VII-6 Input Data and General Equations for Calculating Per-Well SBF/OBF Waste Volumes .... VII-20
VII-7 Summary SBF/OBF Model Well Waste Volume Estimates VII-21
VII-8 Estimated Offshore WBF Static Sheen Test/Toxicity Limitation Failure Rates Used in
Maximum Failure Rate Analysis VII-25
VII-9 EPA Determination of Sediment Toxicity For Base Fluids VII-34
VII-10 EPA Determination of Sediment Toxicity for Whole Mud Formulations with Synthetic
Base Fluids VII-35
VII-11 Industry Sediment Toxicity Results VII-36
VII-12 EPA Solid Phase Test (1000 mg/Kg) VII-39
VII-13 EPA Solid Phase Test (2000 mg/Kg) VII-40
VII-14 EPA Solid Phase Test (5000 mg/Kg) VII-41
VII-15 Industry Marine Anaerobic Closed Bottle Biodegradation Test Results VII-43
VII-16 Industry Respirometry Test Results VII-45
VII-17 Drilling Fluid Recovery Devices VII-52
VIII-1 Annual Technology Costs and Pollutant Loadings for Drill Cuttings BAT
and NSPS Options VIII-3
VIII-2 Summary Annual and Incremental Costs for Management of SBF-Cuttings
from Existing Sources VIII-16
VIII-3 Summary Annual and Incremental Costs for Management of SBF-Cuttings
from New Sources VIII-17
VIII-4 Estimated Number of Wells Drilled Annually VIII-19
VIII-5 Summary Total Pollutant Loadings And Incremental Loadings (Removals) for
Large Volume Wastes from Existing Sources VIII-35
VIII-6 SBF, OBF, and WBF Annual BAT/NSPS Option 1 Pollutant Loadings and
Incremental Loadings (Removals) for Large Volume Wastes from Existing Sources VIII-39
VIII-7 SBF, OBF, and WBF Annual BAT Option 2 Pollutant Loadings and
Incremental Loadings (Removals) for Large Volume Wastes from Existing Sources VIII-43
VI
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TABLES
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VIII-8 SBF, OBF, and WBF Annual BAT Option 3 Pollutant Loadings and
Incremental Loadings (Removals) for Large Volume Wastes from Existing Sources VIII-46
VIII-9 Summary Total Pollutant Loadings And Incremental Loadings (Removals) for
Large Volume Wastes from New Sources VIII-48
VIII-10 Summary SBF, OBF, and WBF Annual Baseline, BAT/NSPS Option 1,
BAT/NSPS Option 2, and BAT/NSPS Option 3 Pollutant Loadings and
Incremental Loadings (Removals) for Large Volume Wastes from New Sources VIII-49
IX-1 Summary of Annual NWQEI for Drill Cuttings IX-3
IX-2 Summary of Baseline and BAT/NSPS Options Air Emissions and Fuel Usage for
Existing Sources IX-4
IX-3 Summary NWQEI by Drilling Fluid Type for Baseline and BAT/NSPS Options
for Existing Sources IX-6
IX-4 Uncontrolled Emission Factors for Drill Cuttings Management Activities IX-15
IX-5 Summary Air Emissions and Fuel Usage for Gulf of Mexico New Sources IX-17
IX-6 Amounts and Incremental Increases (Decreases) of Solid Waste Disposed by
Zero Discharge Technologies for Existing and New Source Wells IX-18
IX-7 Summary of Monetized Human Health Benefits or Impacts Associated with
VOC, PM, and SO2 Emissions, Existing Sources IX-23
IX-8 Summary of Monetized Human Health Benefits or Impacts Associated with
VOC, PM, and SO2 Emissions, New Sources IX-23
X-l Properties for Reference C16-C18 lOs SBF Used in Discharge Sediment Toxicity Testing .... X-27
Vll
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FIGURES
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IV-1 Generalized Drilling Fluids Circulation Systems IV-6
VII-1 Low Range Spike Concentrations (1000 mg/Kg) VII-39
VII-2 Mid-Range Spike Concentrations (2000 mg/Kg) VII-40
VII-3 High-Range Spike Concentrations (5000 mg/Kg) VII-41
VII-4 Industry Solid Phase Test Results VII-42
VII-5 Industry Anaerobic Closed Bottle Test Results VII-44
VII-6 Industry Respirometry Test Results VII-45
VII-7 Generalized Solids Control System VII-50
VII-8 Schematic Side and Front Views of Two-Tiered Shale Shakers VII-54
VII-9 Configuration of Amirante Solids Control Equipment VII-57
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CHAPTER I
INTRODUCTION
1. LEGAL AUTHORITY
The U.S. Environmental Protection Agency (EPA) is promulgating 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 (the Federal
Water Pollution Control Act); 33 U.S.C. 1311, 1314 (b), (c), and (e); 1316; 1317; 1318; 1342; and 1361.
The regulation and supporting technical information are presented in the following 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 rule.
2. 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. 125 l(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 addresses the problem of water pollution on a number of different fronts. Its primary
reliance, however, is on establishing restrictions on the types and amounts of pollutants discharged from
various industrial, commercial, and public sources of wastewater.
Direct dischargers (i.e., those that discharge effluent directly into navigable waters) must comply
with effluent limitation guidelines and new source performance standards (NSPS) in National Pollutant
Discharge Elimination System ("NPDES") permits (CWA 401 and 402); indirect dischargers (i.e., those that
discharge to publicly owned treatment works systems which in turn discharge into waters of the U.S.) must
comply with pretreatment standards. EPA issues these guidelines and standards for categories of industrial
dischargers based on the degree of pollution control that can be achieved using various levels of control
technology. The guidelines and standards are summarized below.
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2.1 Best Practicable Control Technology Currently Available (BPT)
Section 304(b)(l)(A) of the CWA requires EPA to identify effluent reductions attainable through
the application of "best practicable control technology currently available for classes and categories of point
sources." Generally, EPA determines BPT effluent levels based upon the average of the best existing
performances by plants of various sizes, ages, and unit processes within each industrial category or
subcategory. In industrial categories where present practices are uniformly inadequate, however, EPA may
determine that BPT requires higher levels of control than any currently in place if the technology to achieve
those levels can be practicably applied (see "A Legislative History of the Federal Water Pollution Control
Act Amendments of 1972," U.S. Senate Committee of Public Works, Serial No. 93-1, January 1973, p.
1468).
In addition, CWA Section 304(b)(l)(B) requires a cost assessment for BPT limitations. In
determining the BPT limits, EPA must consider the total cost of treatment technologies in relation to
effluent reduction benefits achieved. This inquiry does not limit EPA's broad discretion to adopt BPT
limitations that are achievable with available technology unless the required additional reductions are "wholly
out of proportion to the costs of achieving such marginal level of reduction" (see Legislative History, op. cit.
p. 170). Moreover, the inquiry does not require the Agency to quantify benefits in monetary terms [e.g.,
American Iron and Steel Institute v. EPA, 526 F. 2d 1027 (3rd Cir., 1975)].
In balancing costs against the benefits of effluent reduction, EPA considers the volume and nature
of expected discharges after application of BPT, the general environmental effects of pollutants, and the
cost and economic impacts of the required level of pollution control. In developing guidelines, the Act does
not require consideration of water quality problems attributable to particular point sources, or water quality
improvements in particular bodies of water.
Effluent limitations guidelines based on BPT apply to discharges of conventional, toxic, and non-
conventional pollutants1 from existing sources (CWA section 304(b)(l)). BPT guidelines generally are
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
1 Conventional pollutants are biochemical oxygen demand (BOD5), total suspended solids (TSS),
fecal coliforn, pH, and oil and grease; toxic pollutants are those pollutants listed by the Administrator under
CWA Section 307(a); nonconventional pollutants are those that are neither toxic nor listed as conventional.
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requirements), and other factors the EPA Administrator deems appropriate (CWA ยง 304(b)(l)(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, 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)
The CWA establishes BAT as a principle means of controlling the discharge of toxic and non-
conventional pollutants. In general, BAT effluent limitation guidelines represent the best existing
economically achievable performance of direct discharging plants in the industrial subcategory or category.
The factors considered in assessing BAT include the cost of achieving BAT effluent reductions, the age of
equipment and facilities involved, the processes employed, engineering aspects of the control technology,
potential process changes, non-water quality environmental impacts (including energy requirements), and
such factors as the Administrator deems appropriate. The Agency retains considerable discretion in
assigning the weight to be accorded to these factors. An additional statutory factor considered in setting
BAT is economic achievability. Generally, the achievability is determined on the basis of the total cost to
the industrial subcategory and the overall effect of the rule on the industry's financial health. BAT
limitations may be based upon effluent reductions attainable through changes in a facility's processes and
operations. As with BPT, where existing performance is uniformly inadequate, BAT may be based upon
technology transferred from a different subcategory within an industry or from another industrial category.
BAT also may be based upon process changes or internal controls, even when these technologies are not
common industry practice.
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2.4 New Source Performance Standards (NSPS)
NSPS reflect effluent reductions that are achievable based on the best available demonstrated
control technology. New facilities have the opportunity to install the best and most efficient production
processes and wastewater treatment technologies. As a result, NSPS should represent the greatest degree of
effluent reduction attainable through the application of the best available demonstrated control technology
for all pollutants (i.e., conventional, non-conventional, and priority pollutants). In establishing NSPS, EPA
is directed to take into consideration the cost of achieving the effluent reduction and any non-water quality
environmental impacts and energy requirements.
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 publicly-owned
treatment works (POTW) that pass through, interfere, or are otherwise incompatible with the operation of
the POTW (CWA section 307(b)). Because none of the facilities to which this rule applies discharge to a
POTW, pretreatment standards are not being promulgated as part of this rulemaking.
2.6 Best Management Practices (BMPs)
Section 304(e) of the CWA gives the Administrator 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)(l) also
authorizes BMPs as necessary to carry out the purposes and intent of the CWA; see 40 CFR Part
122.44(k).
3. 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 a schedule was established for developing new and revised effluent guidelines for several
industry categories, including the oil and gas extraction industry. The Natural Resources Defense Council,
Inc. challenged the Effluent Guidelines Plan in a suit filed in the U.S. District Court for the District of
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Columbia (NRDC et al. v. Browner, Civ. No. 89-2980). On January 31, 1992, the Court entered a consent
decree (the "304(m) Decree") that included schedules for EPA's proposal and promulgation of effluent
guidelines for a number of point source categories. The most recent Effluent Guidelines Plan was published
in the Federal Register on August 31, 2000 (65 FR 53008). This plan requires, among other things, that
EPA take final action on the Synthetic-Based Drilling Fluids Guidelines by December 2000.
4. POLLUTION PREVENTION ACT
The Pollution Prevention Act of 1990 (PPA; 42 U.S.C. 13101 et seq., Pub. L. 101-508, November
5, 1990) "declares it to be the national policy of the United States that pollution should be prevented or
reduced whenever feasible; pollution that cannot be prevented should be recycled in an environmentally safe
manner, whenever feasible; pollution that cannot be prevented or recycled should be treated in an
environmentally safe manner whenever feasible; and disposal or release into the environment should be
employed only as a last resort..." (Sec. 6602; 42 U.S.C. 13101 (b)). In short, preventing pollution before it
is created is preferable to trying to manage, treat or dispose of it after it is created. The PPA directs the
Agency to, among other things, "review regulations of the Agency prior and subsequent to their proposal to
determine their effect on source reduction" (Sec. 6604; 42 U.S.C. 13103(b)(2)). EPA reviewed this
effluent guideline for its incorporation of pollution prevention.
According to the PPA, source reduction reduces the generation and release of hazardous
substances, pollutants, wastes, contaminants, or residuals at the source, usually within a process. The term
source reduction "include [s] equipment or technology modifications, process or procedure modifications,
reformulation or redesign of products, substitution of raw materials, and improvements in housekeeping,
maintenance, training or inventory control. The term 'source reduction' does not include any practice
which alters the physical, chemical, or biological characteristics or the volume of a hazardous substance,
pollutant, or contaminant through a 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 the final regulations, EPA supports pollution prevention technology by encouraging the
appropriate use of synthetic-based drilling fluids (SBFs) based on the use of base fluid materials in place of
traditional: (1) water-based drilling fluids (WBFs); and (2) oil-based drilling fluids (OBFs) consisting of diesel
oil/or and mineral oil. The appropriate use of SBFs in place of WBFs will generally lead to more efficient
and faster drilling and a per well reduction in non-water quality environmental impacts (NWQEI; including
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energy requirements) and discharged pollutants. Use of SBFs may also lead to a reduced demand for new
drilling platforms and development well drilling though the use of directional and extended reach drilling.
Compared to OBFs, discharges from SBF-drilling operations have lower aqueous and sediment toxicities,
lower bioaccumulation potentials, and faster biodegradation rates. In addition, polynuclear aromatic
hydrocarbons (PAHs), including those which are priority pollutants,2 which are constituents in OBFs are not
present in SBFs.
EPA considered a "zero discharge" requirement (i.e., BAT/NSPS Option 3) for SBF-cuttings
wastes. EPA has determined that, under this requirement, most operators would decrease the use of SBFs
in favor of OBFs and WBFs due to lower OBF and WBF drilling fluid unit costs. EPA concluded that a
zero discharge requirement for SBF-cuttings and the subsequent increase use of OBFs and WBFs would
result in: (1) unacceptable NWQEIs; and (2) increased pollutant loadings to the ocean due to operators
switching from SBFs to less efficient WBFs.
The appropriate use of SBF in place of OBF will eliminate the need to inject OBF-waste cuttings
onsite or to barge OBF wastes to shore, thereby reducing NWQEI such as fuel use, air emissions, and any
land disposal risks associated with OBFs. Operators also are using drilling fluids and creating wastes with
increased toxicity when using OBFs in place of SBFs. The controlled discharge options eliminate the risk of
OBF and OBF-cuttings spills and of cross-media contamination at land disposal operations from wells
converting to SBF use. As stated in April 2000 (65 FR 21557), EPA uses SBF and OBF spill data in this
final rule as a factor that supports a controlled discharge option. MMS spill data show that riser disconnects
in deep water drilling operations release approximately 2,400 barrels of SBF drilling fluids; these incidents
occur in deep water, on average, two to three times per year due to riser failure.1 Riser disconnects in deep
water are a particular concern due to: (1) increased riser tensioning; (2) deep water technical requirements
(e.g., riser verticality, increased use of top drive systems, multiple flex joints in deep water risers, or
placement of well heads and upper casing sections in soft sea beds); and (3) deep water ocean environments
(e.g., uncharted eddy and loop currents).2'3
In addition to these OBF versus SBF concerns, use of WBFs in place of SBFs also leads to sub-
optimal environmental performance. Thus, replacing SBFs with WBFs results in: (1) an increase in
NWQEIs due to the increased length of the drilling project; and (2) a per-well increase in the quantity of
discharged pollutants due to both the poorer technical performance of WBFs (i.e., increased washout of
WBF compared to SBF) and the permitted discharge of WBFs. These permitted discharges include not
Priority pollutants are the 126 toxic pollutants listed in Appendix A to 40 CFR 423.
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only WBF-associated cuttings, but neat WBF either as discharges related to dilution or bulk discharges of
mud systems at a mud-type change over or at the end of well. For these reasons, EPA rejected the zero
discharge option.
In addition, the technology controls in the final regulation are based on a more efficient solids
control technology to increase recycling of SBF in the drilling operation. Increased SBF recycling reduces
the quantity of SBF required for drilling operations and the quantity of SBF discharged with drill cuttings. A
discussion of this pollution prevention technology is contained in Chapter VII of this Development
Document.
5. 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 gathering phase for
this rulemaking 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 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, as well as their limitations, were developed for
WBF, the offshore regulation applied to all types of drilling fluids and drill cuttings. 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, whether 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.
Based on comments received from industry, EPA thought SBFs could also be adequately controlled
by the offshore regulation. After the offshore rule was proposed, EPA received several industry comments
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that 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 final
offshore effluent guidelines.
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 whether diesel oil, mineral
oil or formation hydrocarbons also were being discharged.
Also in the final offshore rule, EPA encouraged the use of drilling fluids that were less toxic and that
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 existing
discharge requirements. At that time, 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 existing 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 controls for discharges associated with SBFs.
The coastal rule adopted the offshore discharge requirements to allow discharge of drilling wastes in
one geographic area of the coastal subcategory (Cook Inlet, Alaska), and prohibited the discharge of drilling
wastes in all other coastal areas.
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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 noted the inadequacies of the current effluent guidelines to control SBF waste streams
and provided an outline of the parameters that EPA saw as important for adequate control. 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 preamble to the
rule provided guidance to NPDES permit writers needing to write limits for SBFs on a best professional
judgement (BPJ) basis. This guidance recommended 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 on whole SBF prior to discharge, were also
suggested for controlling the discharge of cuttings contaminated with drilling fluid.
EPA stated its intention to further evaluate test methods for benthic toxicity and to determine an
appropriate limitation if this additional test was warranted. In addition, test methods and results for
bioaccumulation and biodegradation, as indicators of the rate of recovery of SBF 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.
On February 3, 1999 (64 FR 5488), EPA published proposed effluent limitations guidelines for the
discharge of SBF drilling fluids and drill cuttings into waters of the U.S. by existing and new sources in the
oil and gas extraction point source category.
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EPA received comments on many aspects of the proposal. The majority of comments related to:
(1) the proposed analytical test methods for stock and discharge limitations; (2) equipment basis used to set
BAT and NSPS cuttings retention limitations; (3) Best Management Practices (BMPs) and their use to
control small volume spills and releases of SBF; (4) the proposal engineering and economic assumptions;
and (5) proposal procedural and definition issues. EPA evaluated all of these issues based on additional
information collected by EPA or received during the comment period following the proposal. EPA then
discussed the results of these evaluations in a Notice of Data Availability, which is discussed below.
On April 21, 2000 (65 FR 21548), EPA published a Notice of Data Availability (NODA) in which
the Agency presented a summary of new data received in comments on the proposed rule or collected by
EPA since the publication of the proposal. EPA discussed the major issues raised during the proposal
comment period and presented several revisions to the modeling and alternative approaches to address these
issues. EPA solicited comments on the data collected since proposal and on the revised modeling and
alternative approaches to manage SBF discharges.
6. 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 for the Eastern Gulf of Mexico and
Central/South Atlantic coast, Region 6 in the Central and Western Gulf of Mexico, Region 9 for offshore
California, and Region 10 for offshore Alaska and Cook Inlet, Alaska. Permits in Regions 4, 9 and 10 have
never allowed the discharge of SBFs, and those three Regions are currently preparing final general permits
that specifically prohibit SBF discharges. Any drilling using SBFs will require an individual permit or a
modification of the general permits.
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). The general permit reissued
on November 2, 1998 (63 FR 58722) also does not specifically disallow the discharge of SBF-cuttings if
they meet the limitations of the permit. The reason for these differences between Region 6 and other EPA
Regions relates to the timing of the 1993 Region 6 general permit and the issues raised in comments during
the issuance of that permit.
The previous individual and general permits of Regions 4, 9 and 10 were issued long before SBFs
were developed and used. In Region 6, however, the first SBF well was drilled in June of 1992 and the
development of the Region 6 OCS general permit, published December 3, 1993 (58 FR 63964), thus
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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 essentially 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
was consistent with 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 chemical
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 PAH content, toxicity, and
biodegradation between diesel and mineral oil versus synthetic fluids, EPA determined that SBFs were not
inverse emulsion drilling fluids as defined in the Region 6 general permit. This determination is exemplified
by the separate definitions for OBFs and SBFs introduced with the Coastal Effluent Guidelines (see 61 FR
66086, December 16, 1996).
7. REFERENCES
1. Johnston, C.A., EPA. 2000. Memorandum to the File, Telephone Conversation with T. Prosser,
Maurer Engineering. 11/22/00. (Record No. IV.B.a.3)
2. Johnston, 2000 - Attendee Information from the DOE/MMS Deepwater Dual-Density Drilling
Workshop, Houston, TX. 9/28/00. (Record No. IV.B.a.4)
3. Furlow, W. and M. Deluca. 2000. Riser management taking center stage as drilling moves into
greater depths. Offshore, January 2000. Pp 32-33. (Record No. IV.B.a.5)
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CHAPTER II
PURPOSE AND SUMMARY OF THE REGULATION
1. 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 the Cook Inlet portion of
the Coastal Subcategory of the Oil and Gas Extraction Point Source Category. These limitations apply to
effluent discharges 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).
2. SUMMARY OF THE SBF GUIDELINES
EPA is establishing regulations based on the "best practicable control technology currently available"
(BPT), "best conventional pollutant control technology" (BCT), "best available control technology
economically achievable" (BAT), and the best available demonstrated control technology (BADCT) for new
source performance standards (NSPS), for the waste stream 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 or current permits 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.
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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 olefms, internal olefms, linear alpha olefms,
synthetic paraffins, ethers, linear alkyl benzenes, and others. Other oleaginous materials have also been
developed for this purpose, such as the enhanced mineral oils and non-synthetic paraffins. Industry
developed SBFs with these synthetic and non-synthetic oleaginous materials as the base fluid to provide the
drilling performance characteristics of traditional OBFs based on diesel and mineral oil, but with lower
environmental impact and greater worker safety through lower toxicity, elimination of polynuclear aromatic
hydrocarbons (PAHs), faster biodegradability, lower bioaccumulation potential, and, in some drilling
situations, less drilling waste volume. EPA believes that this product substitution approach is an excellent
example of pollution prevention that can be accomplished by the oil and gas industry.
EPA intends that these regulations control the discharge of SBFs in a way that reflects application
of appropriate levels of technology, while also encouraging their use as a replacement to the traditional
mineral oil- and diesel oil-based fluids. Available information indicate that use of certain 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 improperly controlled 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 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.
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. EPA estimates that the final rule will reduce air emissions by 2,927 tons
per year, decrease fuel use by 200,817 barrels per year of oil equivalent, and reduce the discharge of 118
million pounds of cuttings. These estimates are based on the current industry practice of discharging SBF-
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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 offshore and Cook Inlet, Alaska.
As SBFs came into commercial use, EPA determined that the current effluent limitations guidelines
and discharge monitoring methods, which were developed to control the discharge of WBFs, did not
appropriately control the discharge of these new drilling fluids. Since cuttings associated with 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 sediment toxicity of the discharge is not apparent using 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 ensures that
substitution of synthetic and other oleaginous base fluids for traditional mineral oil and diesel oil reflects the
appropriate level of technology. Parameters that distinguish the various base fluids are their PAH content,
sediment toxicity, and rate of biodegradation.
EPA also is controlling SBF-cuttings discharges with limitations on the toxicity (sediment and solid
particulate phase) 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 takes advantage of the solids separation
efficiencies achievable with SBFs, and consequently minimizes the discharge of organic and toxic
components. Further, field results show that: (1) cuttings are dispersed during transit to the seabed and no
cuttings piles are formed when SBF concentrations on cuttings are held below 5%; and (2) cuttings
discharged from cuttings dryers (with SBF retention values under 5%) in combination with a sea water
flush, hydrate very quickly and disperse like water-based cuttings. EPA maintains that SBFs separated from
drill cuttings meet zero discharge requirements, as this is the current industry practice due to the value of
these drilling fluids.
EPA is promulgating stock limitations and discharge limitations in a two part approach to control
SBF-cuttings discharges under BAT. The first part is based on product substitution through use of stock
limitations (e.g., sediment toxicity, biodegradation, PAH content, metals content) and discharge limitations
(e.g., diesel oil prohibition, formation oil prohibition, sediment toxicity, aqueous toxicity). The second part
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is the control of the quantity of SBF discharged with SBF-cuttings. EPA finds that the second part is
particularly important because limiting the amount of SBF content in discharged cuttings controls: (1) the
amount of SBF discharged to the ocean; (2) the biodegradation rate affect of discharged SBF; and (3) the
potential for SBF-cuttings to develop cuttings piles and mats which are detrimental to the benthic
environment.
Thus, EPA is establishing limits appropriate to the use of SBFs in the drilling operation. EPA is
promulgating zero discharge of neat SBFs (not associated with cuttings), which reflects current practice.
The limitations applicable to cuttings contaminated with SBFs are as follows:
Stock Limitations on Base Fluids (BAT/NSPS):
S Maximum PAH content of 10 ppm (wt. based on phenanthrene/wt. base fluid) as measured
by EPA Method 1654A.
S Maximum sediment toxicity of SBF base fluids that allows discharge of only SBF-cuttings
that are as toxic or less toxic than C16 - C18 internal olefins (lOs) as measured by the 10-day
sediment toxicity test [ASTM E1367-92 supplemented by preparation procedures in
Appendix 3 in Subpart A of 40 CFR 435] using natural or formulated sediment and
Leptocheirus plumulosus as the test species. Alternatively, the limitation is expressed as "a
sediment toxicity ratio" defined as the 10-day LC50 of C16 - C18 IOs/ 10-day LC50 of the
stock base fluid. This ratio must be less than 1.0.
S Minimum rate of biodegradation (biodegradation equal to or faster than C16 - C18 internal
olefin by the marine anaerobic closed bottle biodegradation test [i.e., ISO 11734:1995 as
modified at Appendix 4 in Subpart A of 40 CFR 435]). Alternatively, the limitation is
expressed as "a biodegradation rate ratio" defined as the percent degradation of C16 - C18
IOs/ percent degradation of the stock base fluid, both at 275 days. This ratio must be less
than 1.0.
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Discharge Limitations on Cuttings Contaminated with SBFs:
S No free oil as determined by the static sheen test (Appendix 1 to Subpart A of 40 CFR
435). (BPT/BCT/NSPS)
S Zero discharge of formation oil as measured at two points. First, SBF must be free of
formation oil before its initial use as detected by gas chromatography with mass
spectroscopy (GC/MS; Appendix 5 to Subpart A of 40 CFR 435). Second, in the SBF
recovered by the solids control equipment as measured by the reverse phase extraction
(RPE) method (Appendix 6 to Subpart A of 40 CFR 435). (BAT/NSPS)
S Maximum well-average retention of SBF on cuttings expressed as the percentage of base
fluid on wet cuttings. The well-averaged retention limitation for SBFs with the
environmental performance (e.g., sediment toxicity, biodegradation) of vegetable esters or
low viscosity esters is 9.4%; and for SBFs with the environmental performance of C16 - C18
internal olefins (lOs) is 6.9%. (BAT/NSPS)
S Maximum sediment toxicity of SBF discharged with cuttings that allows discharge of only
SBF cuttings that are as toxic or less toxic than C16 - C18 lOs as measured by the 10-day
sediment toxicity test (ASTM E1367-92 supplemented by preparation procedures in
Appendix 3 in Subpart A of 40 CFR 435) using natural or formulated sediment and
Leptocheirus plumulosus as the test species. Alternatively, the limitation is expressed as "a
sediment toxicity ratio" defined as the 10-day LC50 of C16 - C18 IOs/10-day LC50 of the
SBF being discharged with cuttings. This ratio must be less than 1.0. (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:
S Mercury limitation in stock barite of 1 mg/kg. (BAT/NSPS)
S Cadmium limitation in stock barite of 3 mg/kg. (BAT/NSPS)
S Diesel oil discharge prohibition. (BAT/NSPS)
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S Minimum aqueous phase toxicity (96-hour LC50) of 3% by volume for SBF-cuttings using
the suspended particulate phase (SPP). (BAT/NSPS)
This final regulation establishes the geographic areas where drilling wastes may be discharged: the
offshore subcategory waters beyond 3 miles from the shoreline, and in Alaska offshore waters with no 3-
mile restriction. The only coastal subcategory waters where drilling wastes may be discharged is in Cook
Inlet, Alaska. EPA is retaining the zero discharge limitations in areas where discharge is currently prohibited
and these requirements are not within the scope of this rulemaking.
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CHAPTER III
DEFINITION OF SBF AND ASSOCIATED WASTE STREAMS
1. INTRODUCTION
This chapter describes the industry, geographic areas, and waste streams to which this regulation
would apply.
2. INDUSTRY DEFINITION AND GEOGRAPHIC COVERAGE
The final rule applies to certain coastal and offshore facilities included in the following standard
industrial classification (SIC) 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 applies 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, comprises 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
category, as defined in 40 CFR 435.40, comprises those facilities involved in exploration, development, and
production operations in waters of the U.S. landward of the inner boundary of the territorial seas
(shoreline). The only coastal area where discharge of water-based drilling fluid 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 and (b) Cook Inlet,
Alaska.
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3. WASTE STREAMS REGULATED BY THE SBF GUIDELINES
This rule applies 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 these drilling fluids.
This rule also amends the current effluent guidelines such that the current guidelines are applicable
only to water-based drilling fluids (WBF), while these SBF discharge requirements are applicable to all other
drilling fluids. To achieve this, EPA is defining 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 are controlled by either
applying the current requirements for WBFs or the final requirements for non-aqueous drilling fluids. The
definition is based on the miscibility (solubility) of the base fluid in water. The definitions for various drilling
fluids are as follows:
โข 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.
โข A non-aqueous drilling fluid is one in which the continuous phase is a water immiscible fluid such
as an oleaginous material (e.g., mineral oil, enhanced mineral oil, paraffinic oil, or synthetic material
such as olefins and vegetable esters).
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.
โข 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.
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In addition, there are other types of non-aqueous drilling fluids that are not listed in the definitions
above. For example, drilling fluids based on synthetic linear paraffins are considered non-aqueous drilling
fluids.
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CHAPTER IV
INDUSTRY DESCRIPTION
1. 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. DRILLING ACTIVITIES
There are two types of drilling associated with oil and gas operations: exploratory and development.
Exploratory drilling includes those operations drilling wells to determine potential hydrocarbon reserves.
Development drilling includes those operations drilling 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 or 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.
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.
IV-1
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Direct exploratory drilling, however, is the only method to confirm the presence of hydrocarbons and to
determine the quantity of hydrocarbons after 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 moved easily 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, semi-submersibles, drill ships, and ship-shaped barges.:
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. Semi-submersible units are able to withstand rough seas with minimal rolling and pitching tendencies.
Semi-submersibles 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 semi-submersible rigs: bottle-type
and column-stabilized.
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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 because 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 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.:
2.2 Development Drilling
Development of oil and gas involves drilling wells into the identified 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. Because 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
IV-3
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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.
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, 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,
IV-4
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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.
Because 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."
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.
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Figure IV-1
Generalized Drilling Fluids Circulation Systems
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.
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2.3 Drilling with Subsea Pumping
For use in the relatively new area of deep water 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 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 because 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. Upper well sections usually are drilled with WBF, and a conversion to
oil-based fluid (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 because the resultant drilling wastes can be discharged onsite provided these wastes
pass regulatory requirements.
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For certain drilling situations, such as drilling in reactive shales, high angle directional drilling, and
drilling in deep water, progress with 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 OBFs, which use
diesel oil or mineral oil as the base fluid. Because EPA rules require zero discharge of these 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 olefms, internal olefms, linear alpha olefms,
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
PAHs, faster biodegradability, lower bioaccumulation potential, and usually less drilling waste volume.
3. INDUSTRY PROFILE: HISTORIC AND PROJECTED DRILLING ACTIVITIES
The final regulation establishes 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. The
table 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 uses these
categories to identify model well characteristics for the control technology analyses described in later
chapters of this document. EPA also uses these data to project the types of drilling activity in each
geographic area (i.e., development versus exploratory) from drilling activity data provided by industry.
IV-8
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TABLE IV-1
NUMBER OF WELLS DRILLED ANNUALLY, 1995 - 1997, BY GEOGRAPHIC AREA
Data Source3
Shallow Water
(<1,000 ft)
Development
Exploration
Deep Water
(> 1,000 ft)
Development
Exploration
Total
Wells
Gulf of Mexico
MMS: 1995
1996
1997
Average Annual
RRCb
Total Gulf of Mexico
557
617
726
640
5
645
314
348
403
355
3
358
32
42
69
48
NA
48
52
73
104
76
NA
76
955
1,080
1,302
1,119
8
1,127
Offshore California
MMS: 1995
1996
1997
Average Annual
4
15
14
11
0
0
0
0
15
16
14
15
0
0
0
0
19
31
28
26
Coastal Cook Inlet
AOGC: 1995
1996
1997
Average Annual
12
5
5
7
0
1
2
1
0
0
0
0
0
0
0
0
12
6
7
8
a Sources: MMS: Minerals Management Service, Ref. 3
RRC: Railroad Commission of Texas, Ref. 4
AOGC: Alaska Oil and Gas Commission, Ref. 5
b 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.
Among these three areas, most historic drilling activity occurs in the Gulf of Mexico. As shown in
Table IV-1, 1,127 wells were drilled in the Gulf of Mexico, on average, from 1995 to 1997, compared to 26
wells in California and 8 wells 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, or 8.6 percent of all Gulf of Mexico wells drilled that
year. By 1997, that number increased to 173 wells drilled, or 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
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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 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).3 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
(RRC) 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 final rule, but is not included in the MMS data.
Most production activity 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.3
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 in
these SBF regulations mean Upper Cook Inlet unless otherwise identified. Currently there are three
operators active in Cook Inlet.7
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 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 offshore
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 SBF cuttings discharges are occurring under the current NPDES general for Cook Inlet.
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.
IV-10
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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 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.
For the proposed rule, EPA estimates 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 at proposal to estimate the well counts in Table IV-2.
Total Gulf of Mexico WBF/SBF/OBF Wells: For the Gulf of Mexico, EPA estimated that 80% of
the average annual wells were drilled using WBF exclusively (902 wells); 10% (113 wells) were
drilled with SBF, and 10% (112) were drilled with OBF.9
Gulf of Mexico SBF Wells: EPA learned that approximately 75% of all deep water wells in the
Gulf of Mexico were drilled with either SBF or OBF.10 Further, EPA learned that operators were
reluctant to use OBF in deep water operations because of the possibility of riser disconnect.6 For
this reason, EPA determined that in deep water: no OBF wells were drilled; 75% used SBF, and
25% used WBF exclusively. Thus, EPA estimated that 36 of 48 DWD wells and 57 of 76 DWE
wells were 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% of
shallow water wells were development, 36% were exploratory).
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TABLE IV-2
ESTIMATED NUMBER OF WELLS DRILLED ANNUALLY
BY DRILLING FLUID USED FOR PROPOSED RULE
Drilling Fluid
Shallow Water
(<1,000 ft)
Development
Exploratory
Deep Water
(> 1,000 ft)
Development
Exploratory
Total
Wells
Gulf of Mexico
Total Wells
Well Using WBF (80%)
Wells Using SBF (10%)
Wells Using OBF (10%)
645
560
13
72
358
311
7
40
48
12
36
0
76
19
57
0
1,127
902
113
112
Offshore California
Total Wells
Wells Using WBF
Wells Using OBF
11
10
1
0
0
0
15
4
11
0
0
0
26
14
12
Coastal Cook Inlet
Total Wells
Wells Using WBF
Wells Using OBF
7
6
1
1
1
0
0
0
0
0
0
0
8
7
1
Gulf of Mexico OBF Wells: Because EPA estimated that OBFs were not used in the deep water, all
112 OBF wells in offshore Gulf of Mexico were 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.
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 were 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 were drilled with OBF; 75% of deep water wells
were drilled with OBF. All other wells were assumed to be drilled exclusively with WBF.
IV-12
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โข WBF Wells: The numbers of WBF wells distributed among the four model well types were simply
the difference between the numbers of SBF/OBF wells and the total well population for a given
model well. These numbers were presented for completeness, and did not appear in any further
analysis in the document for the proposed rule. Also, the top portion of SBF and OBF wells were
drilled with WBF, but this portion of the well was not included in EPA's proposed analysis.
Existing versus New Sources: 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 would 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 would be a new source. Of the
estimated 36 DWD wells drilled annually, EPA estimated that 18 of these would be new sources.
Exploratory wells, by definition, are not new source wells. EPA did not project any new source
wells to be drilled in offshore California or coastal Cook Inlet, Alaska.
For the final rule, EPA has retained certain percentages noted above for various categories of wells,
but has applied these where necessary to more recent estimates of industry activity. Thus, industry
projected a total of 1,047 shallow water wells (including both new and existing sources) to be drilled in the
Gulf of Mexico. Among these shallow water wells, 80% (836) were projected to be WBF wells, 6% (69)
projected to be OBF wells, and 14% (142) projected to be SBF wells. Similarly, for 138 total deep water
wells (including both new and existing sources), 43% (59) were projected to be WBF wells, 0% (0)
projected to be OBF wells, and 57% (79) projected to be SBF wells. However, these industry projections
allocated these well types neither into exploratory versus development wells, nor existing versus new source
categories.
Therefore, the allocation of wells into exploratory versus development, existing versus new source,
and WBF, OBF, or SBF well types was a three-stage process. First, EPA used the percentage allocations
into exploratory and development well categories based on the projections developed for the proposed rule,
as applied to the total shallow and deep water well counts provided by industry. Second, EPA also used its
existing versus new sources percentages, as described in the proposed rule, to allocate wells into these well
categories. Lastly, wells were allocated into the various mud types based on the projected percentages, as
described above, provided by industry.
IV-13
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TABLE IV-3
ESTIMATED NUMBER OF EXISTING SOURCE WELLS DRILLED ANNUALLY
BY WELL AND DRILLING FLUID TYPE FOR THE FINAL RULEa
Drilling โ .
โ, . โ & Region
Fluid Type
Well Type
SWD SWE
DWD
OWE
Total
Wells
Baseline
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
511
86
42
3
0
1
3
0
1
298
51
25
2
0
1
1
0
1
12
16
0
0
0
0
0
0
0
36
48
0
0
0
0
0
0
0
857
201
67
5
0
2
4
0
2
BAT/NSPS Options 1 and 2
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
479
124
25
3
0
1
3
1
0
279
74
15
2
0
1
1
0
1
11
17
0
0
0
0
0
0
0
34
49
0
0
0
0
0
0
0
803
264
40
5
0
2
4
1
1
BAT/NSPS Option 3
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
511
0
128
3
0
1
3
0
1
298
0
76
2
0
1
1
0
1
17
3
8
0
0
0
0
0
0
51
8
25
0
0
0
0
0
0
877
11
237
5
0
2
4
0
2
Source: Ref. No. 9.
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TABLE IV-4
ESTIMATED NUMBER OF NEW SOURCE WELLS DRILLED ANNUALLY
BY WELL AND DRILLING FLUID TYPE FOR THE FINAL RULE
Drilling โ .
โ, .,rr Region
Fluid Type &
Well Type
SWD SWE
DWD
OWE
Total
Wells
Baseline
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
27
5
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
11
15
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
38
20
2
0
0
0
0
0
0
BAT/NSPS Options 1 and 2
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
25
8
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
10
16
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
35
24
1
0
0
0
0
0
0
BAT/NSPS Option 3
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
27
0
7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
15
3
8
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
42
3
15
0
0
0
0
0
0
Thus (with consideration of rounding effects), the 1,047 shallow water wells disaggregated into 673
(64.3%) development wells and 374 (35.7%) exploratory wells; the 673 development wells disaggregated
into 639 (95%) existing and 34 (5%) new source wells (all exploratory wells are considered existing
sources). These disaggregated well counts were then respectively allocated into WBF, OBF, and SBF well
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types based on the 80%, 6%, and 14% allocations provided in industry's most recent activity projection.
The same procedure was used to allocate the 138 deep water wells into 84 exploratory wells (61.3%) and
54 development wells, of which 28 were classified as existing sources and 26 new sources. Tables IV-3 and
IV-4 summarize these well count allocations for existing and new sources, respectively.
In developing these well counts, EPA has considered the increased ability of operators using SBF to
take advantage of directional drilling technology. Information received by EPA indicates that, compared to
WBF, developing a reservoir using SBF would be expected to require one-third fewer wells (or reduce total
drilled footage by one-third). Improved directional drilling allows fewer wells and/or less drilled footage
because operators can reach pay zone targets at a greater deviation from a fixed location (or increase the
drilled footage through a production zone).
Thus, for the final rule, the well counts under BAT/NSPS Options 1 and 2 have been adjusted.
The projected number of WBF wells converting to SBF wells has been adjusted to reflect the ability to
maintain comparable productivity with one-third fewer wells. Thus, the 54 WBF wells projected to convert
to SBF result in an increase in the SBF well count of only 36 SBF wells. This results in a total SBF, SBF,
and OBF well count of 1,125 existing source wells, under the baseline and BAT/NSPS Option 3, reducing
to a total of 1,107 wells under BAT/NSPS Options 1 and 2.
4. REFERENCES
1. Baker, R., "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. (Record No. I.F. 1)
3. U.S. Department of the Interior, MMS, Herndon, VA, TIMS Database, MMS 97-007, 1997.
4. Covington, J.C., EPA, Memorandum regarding well count data from the Railroad Commission of
Texas, 6/15/98. (Record No. I.E.21)
5. Daly, J., EPA, Memorandum regarding "Phone Conversation Regarding Number of Wells Drilled in
Cook Inlet, Alaska," 10/23/98. (Record No. I.C.a.l)
6. American Petroleum Institute, responses to EPA's "Technical Questions for Oil and Gas
Exploration and Production Industry Representatives," attached to E-mail sent by M. Parker, Exxon
Company, U.S.A., to J. Daly, EPA. 8/7/98. (Record No. I.C.c. 1)
7. Veil, John A., Argonne National Laboratory, Washington, D.C., "Data Summary of Offshore
Drilling Waste Disposal Practices," prepared for the U.S. EPA, Engineering and Analysis Division,
and the U.S. Department of Energy, Office of Fossil Energy, November 1998. (Record No.
(I.C.d.l)
IV-16
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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. 2/3/99. (Record No. II.D.l)
9. Henry, L., Chevron. Memorandum to C.A. Johnston, EPA, Response to EPA Request for
Additional Input Parameter for EPA Modeling. 9/11/00. (Record No. IV.B.a.9)
IV-17
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CHAPTER V
DATA AND INFORMATION GATHERING
1. INTRODUCTION
This chapter describes the sources and methods EPA used to gather data and information for the
final rule. The following sections discuss the data and information gathered concerning pollutant loadings
and numeric limitation analyses; base fluid stock limitations; compliance costs; NWQEIs; compliance
analytical methods; and seabed impact characterizations.
2. POLLUTANT LOADING AND NUMERIC LIMIT ANALYSES
2.1 SBF Retention on Cuttings
SBF retention on cuttings (ROC) data quantify the amount of SBF retained on cuttings (mass of
SBF/mass of wet cuttings, expressed as a percentage). Lower ROC values indicate less SBF retained on
cuttings. EPA uses ROC data, along with other engineering factors (e.g., installation requirements, fluid
rheology) to evaluate the performance of various solids control technologies.
In response to the February 1999 proposal, industry submitted data for SBF ROC from 36 wells.
EPA determined that 16 files were complete and accurate, and these data were presented in the April 2000
NODA. EPA rejected six files due to incomplete reporting. EPA received the remaining 14 files too late for
inclusion in the NODA analyses.
In response to the NODA, EPA received and evaluated ROC data from an additional 79 SBF wells:
the 14 received after the February 1999 proposal comment period; 27 additional sets received during the
NODA comment period; and 38 received after the NODA comment period. EPA has determined that data
from 49 of these 79 wells are sufficiently complete for inclusion in the final rule analyses. Therefore, EPA
uses data from 65 wells to characterize ROC performance of the various solids control technologies. EPA
bases its determination of average ROC values of various solids control technologies on this final, 65-well
data set. These revised average ROC values are combined to yield weighted average ROC values
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(weighting factors based on the relative contribution of each treatment unit to the final, composite waste
stream) for the following three primary SBF-cuttings technology options:
BAT/NSPS (Discharge) Option 1 is based on: the use of shale shakers, cuttings dryers, and fines
removal units; inclusion of discharges from both cuttings dryers and fines removal units in the
development of final effluent limitations guidelines; and a combined, long-term average ROC value
of 4.03%.
โข BAT/NSPS (Discharge) Option 2 is based on: the use of shale shakers, cuttings dryers, and fines
removal units; inclusion of only one discharge, from cuttings dryers, in the development of final
effluent limitations guideline; and a long-term average ROC value of 3.82%.
BAT/NSPS (Zero Discharge) Option 3 requires no discharge of SBF or SBF cuttings and is based
on: the use of shale shakers (with a long-term average ROC value of 10.2%), cuttings boxes,
barges, and trucking to achieve zero discharge via land disposal; or onsite disposal that uses cuttings
grinding systems and injection into subseabed formations offshore.
In addition, using the ROC data, EPA developed two BAT/NSPS limitations and standards that
control the amount of base fluid retained on cuttings for drilling fluids either (a) with the environmental
performance of esters (e.g., biodegradation, sediment toxicity) or (b) with the environmental performance of
C16-C18 internal olefins. EPA is using this approach to provide operators an incentive to use ester-SBFs or
equivalent fluids because they provide better environmental performance. EPA uses ROC data on four
cuttings dryer technologies (vertical and horizontal centrifuges; squeeze presses; and High-G linear shakers)
to base the discharge limitation and standard for SBFs that comply with stock limitations based on esters
(i.e., a long-term average ROC of 4.8% and a discharge limitation and standard of 9.4%). EPA uses ROC
data on the two better performing technologies (vertical and horizontal centrifuges) to base the discharge
limitation and standard for SBFs that comply with the stock limitations based on C16-C18 internal olefins
(i.e., a long-term average ROC of 3.82% and a discharge limitation and standard of 6.9%). The base fluid
retention-on-cuttings limitation and standard both incorporate the variability of solids control efficiencies and
are higher than the long-term average for both esters and C16-C18 internal olefins.
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2.2 Days to Drill
EPA uses the number of days to drill the SBF interval, for all four model wells, as an input
parameter in the NWQI and cost analysis. EPA extracted relevant data from each of the 65 wells identified
above to estimate the number of days to drill each of the four model well SBF intervals.1 For each well
type, the SBF interval volume was determined as well as the number of days to drill the respective interval.
The average interval volume over all intervals was then calculated, and a 7.5% washout factor for SBF was
added to this average interval volume. The average interval volume plus washout (1,050 bbl) is divided by
the average number of days to drill (9.65) to obtain the revised average rate of SBF-cuttings generation (i.e.,
108.7 bbls wet cuttings/day). Each of the model well-type volumes is divided by the cuttings generation rate
to obtain the number of days to drill. The revised numbers of days required to drill the SBF model wells
are: (1) 5.2 days for shallow-water development wells (SWD); (2) 10.9 days for shallow-water exploratory
wells (SWE); (3) 7.9 days for deep-water development wells (DWD); and (4) 17.5 days for deep-water
exploratory wells (DWE).
2.3 Well Count Projections Over Next Five Years
EPA revised annual well count projections for offshore Gulf of Mexico, offshore California, and
Cook Inlet, Alaska based on information submitted post-NODA by industry.2'3> 4 The revised annual well
counts for the baseline are 1,047 shallow water wells and 138 deep water wells in offshore Gulf of Mexico;
7 shallow water wells and no deep water wells in offshore California; and 6 shallow water wells and no deep
water wells in Cook Inlet, Alaska. These revised well counts are not significantly different from the well
counts used in the proposed rule and the NODA (i.e., see SBF Proposal Development Document; Table IV-
2: 1,022 shallow water wells and 139 deep water wells across the Gulf of Mexico, offshore California, and
Cook Inlet, Alaska).
Industry provided well-type data (i.e., SBF, OBF, or WBF well counts), but only provided these
well counts as shallow water wells or deep water wells and provided actual well counts for the baseline.
EPA required industry's revised well counts categorized into both development versus exploratory wells and
existing source versus new source wells for the baseline and all options to estimate pollutant loadings,
compliance costs, and NWQEIs. EPA performed the development versus exploratory allocation using prior
well count data from the NODA. EPA derives percentages of development versus exploratory wells for
both shallow water wells (64.3% and 35.7%, respectively) and deep water wells (38.7% and 61.3%,
respectively) based on the well counts projected in the NODA. EPA then applies these percentages to the
revised aggregated shallow water and deep water well counts provided by industry. EPA made existing
V-3
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source versus new source allocations based on the same assumptions as in the NODA, i.e., a 50% existing
source/50% new source allocation for development wells and a 100% existing source/0% new source
allocation for exploratory wells (which by definition, are drilled from existing sources).
Thus, industry provided baseline counts of 138 total deep water wells (i.e., both existing source and
new source) consisting of 79 SBF, no OBF, and 59 WBF wells. The 79 SBF wells are allocated 38.7% to
development (31 wells) and 61.3% to exploration (48 wells); the 31 development wells are allocated 50%
each (with rounding considerations) to existing source (16 wells) and new source (15 wells); all 48 of the
exploratory wells are classified as existing sources. This same approach is used for all other total baseline
deep water and shallow water total baseline well counts (i.e., both existing and new source wells) provided
by industry: 59 WBF and no OBF deep water wells; 142 SBF, 69 OBF, and 836 WBF shallow water well
counts.
EPA also revised well count projections to reflect enhanced directional drilling capabilities when
using SBF. EPA received information that SBF directional drilling can reduce the number/total footage of
wells required to develop a project. This results from several properties of SBF (increase rate of
penetration, increased lubricity, fewer stuck pipe) whereby operators are able to successfully drill at much
greater deviations, resulting in greater penetration of productive zones in target formations. Thus, industry
can develop the same reservoir with fewer wells and/or less footage drilled than would be required using
WBF. Industry indicated that SBF development drilling can generally reduce by one-third the total drilled
footage required for full development of typical reservoir2 and EPA has included this consideration by
commensurately reducing the count of SBF wells resulting from conversion of development wells to SBF
wells under the two controlled discharge options.
2.4 Current and Projected OBF, WBF, and SBF Use Ratios
For proposal and NODA, EPA estimated that 80% of the average annual Gulf of Mexico wells are
drilled using WBF exclusively; 10% are drilled with SBF; and 10% are drilled with OBF. EPA also included
in well counts estimates of operators converting from OBF to SBF or SBF to OBF under each of the SBF-
cuttings controlled discharge options.
For the final rule, EPA revises the relative frequency of use for WBF, OBF, and SBF under the
two discharge options and the zero discharge option based on data submitted by industry.2'3> 4 Industry
supplied this information to EPA in several formats. EPA uses what it considers the most reliable
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information (e.g., a review of the actual well count data for WBF, OBF, and SBF wells over a period of
three years) to estimate drilling fluid use under each of the SBF-cuttings control options.
Based on these industry well count data, EPA projects that some operators would also switch from
WBFs to SBFs for certain wells due to the increased efficiency of SBF drilling. While no extensive good
industry average statistics exist, it is generally considered that SBFs reduce overall drilling time by 50% (e.g.,
if a well took 60 days to drill with WBF, the same well should be able to be drilled with SBF in 30 days).2'3>
4 Reduced drilling time is expected to result in reduced drilling costs. However, not all drilling operators will
switch from WBFs to SBF due to a variety of other factors, (e.g., WBFs are less expensive [per barrel] than
SBFs, potential for lost circulation downhole). The result of EPA's analysis of these industry submissions is
that 40% of OBF wells are projected to convert to SBF under BAT Options 1 and 2; for WBF wells, a
6.25% conversion rate is projected.
Additionally, based on industry data EPA projects that under the SBF-cuttings zero discharge
option, not all operators would switch from SBFs to OBFs but that some operators would switch to WBFs.
Some drilling operations require the technical performance of non-aqueous drilling fluids and operators must
select either an OBF or SBF. Therefore, for these drilling operations, operators would select OBFs in place
of SBF under the SBF-cuttings zero discharge option as OBFs are less expensive (per barrel) than SBFs.
However, some drilling operations could use either WBFs or oleaginous drilling fluids such as OBFs,
enhanced mineral oil based drilling fluids, or SBFs. Depending on a variety of site specific factors (e.g.,
formation characteristics, directional drilling requirements, torque and drag requirements), operators may
select WBFs in lieu of SBFs or OBFs under the SBF-cuttings zero discharge option.
Industry provided the observation that relative WBF/OBF/SBF usage would remain unchanged as it
was a mature technology. However, EPA noted that data provided by industry at the same time indicated a
different pattern. For example, from 1998 to 2000 OBF usage decreased consistently, respectively 14%,
9%, and 7% in shallow water and 12%, 8%, and 6% overall. SBF usage fluctuated in shallow water, going
from 13% to 8% to 14%, but consistently increased in deep water, from 50% to 51% to 57%, and overall
ranged from 16% to 14% to 19%. WBF mirrored that of SBF, i.e., showed a consistent decrease in deep
water (50% to 49% to 43%) but fluctuated in shallow water from 74% to 83% to 80%. EPA projects that
SBF usage will continue to rise relative to WBF and OBF for several reasons.
There are clear operational advantages for SBF compared to WBF in many drilling situations and
clear environmental and health and safety advantages over diesel or mineral oil base fluids. Another
advantage of SBF is the shorter duration of drilling program using SBF compared to WBF, as well as an
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increased capability to utilize directional drilling technology to reduce the number of wells and/or total
footage required to develop a reservoir. In addition, the patterns of usage in deep water environments, in
which the industry expects to heavily invest future resources, clearly show an increased usage of SBF. EPA
projects, therefore that usage patterns will change for WBF/OBF/SBF. EPA recognizes that well count
projection data are sparse, and a well-characterized and highly reliable projection would be difficult. EPA
believes, for the reasons enumerated above, however, that a change to increased SBF usage is highly likely.
As a conservative approach, therefore, EPA is revising its initial model of WBF/OBF/SBF usage under
BAT/NSPS Options 1 and 2 (i.e., 80/10/10) to reflect the year 2000 projection provided by industry. To
do so, EPA is adjusting the well counts by the relative percentage difference between its initial 80/10/10
allocation and the year 2000 allocation of 75/6/19. (Note: the submitted data, due to rounding, was reported
76/6/19, which sums to 101%. The 3-year WBF utilization averaged 75%, so the WBF allocation was
adjusted by 1% to give the allocation used in EPA's analysis.)
To effect this re-allocation, the relative percentage change in WBF and OBF usage was calculated
and applied to baseline well counts. That is, the change from initial 10% OBF allocation to a 6% allocation
represents a 40% reduction (4%/10%) in OBF wells; the reduction from 80% to 75% represents a 6.25%
reduction in the WBF well count (5%/80%). These reductions result in a net conversion to SBF of 81 wells
~ 27 from OBF and 54 from WBF. This well count is further adjusted to take into consideration the
improved ability to drill directionally and develop reservoirs with fewer wells and/or total footage which
produces a net decrease of 18 total wells (i.e., all from the one-third reduction of the well count for WBF
wells converting to SBF). Thus, the 1,185 total baseline and BAT/NSPS Option 3 Gulf of Mexico wells
reduce to 1,167 BAT/NSPS Option 1 or 2 wells.
2.5 Waste Volumes and Characteristics
EPA collected additional data to identify the volumes and characteristics of WBF discharges. This
additional data more adequately describes the total amount of pollutants loadings and NWQEI under each of
the three SBF-cuttings management options. For example, under the SBF zero discharge option
(BAT/NSPS Option 3), operators would more likely choose WBF and OBF over SBF due primarily to the
relatively higher unit cost of SBF.
Different pollutant loadings and NWQEI are expected for WBF as compared with either OBF or
SBF wells based on differences in washout and length of drilling time. EPA anticipates a reduction in
cuttings waste volume when comparing SBF-drilling to WBF-drilling based on greater hole washout (i.e.,
enlargement) in WBF drilling. Industry estimated that WBF washout percentages vary between 25% and
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75%, with 45% being an acceptable average and confirmed EPA's SBF and OBF washout percentage of
7.5% as appropriate.2
For the final rule, EPA also estimated that the barite used in SBF drilling is nearly pure barium
sulfate (i.e., BaSO4) and, by gravimetric analysis, calculated the weight percentage of barium in barite as
58.8%.
3. COMPLIANCE COSTS ANALYSES
3.1 Equipment Installation and Downtime
For the NODA, projected compliance costs for all options included equipment installation and
downtime for each SBF well drilled. After reviewing ROC data sets submitted in response to the NODA,
EPA modified this parameter in the final analyses to reflect current practice of drilling multiple wells for any
one equipment installation.2 EPA reviewed the ROC well data for the frequency of multiple wells on
specified structures. EPA used the resulting well-per-structure analysis to adjust projected annual SBF
compliance costs by including the consideration of drilling more than one SBF well per equipment
installation per year. EPA estimated that 2.2 development wells per structure and 1.6 exploratory wells per
structure are current industry practice, based on industry-submitted data.5
Industry also submitted estimates of the number of wells drilled per structure.6 EPA's estimates
result in a more conservative cost projection than industry's estimates of 3 wells per structure in deep water
and 4 wells per structure in shallow water.
EPA also received information on the ability of operators to install cuttings dryers (e.g., vertical or
horizontal centrifuges, squeeze press mud recovery units, High-G linear shakers) on existing Gulf of Mexico
rigs.7 While some industry sources filed timely comments alleging that some rigs could not accommodate
additional solids control equipment, in late comments, industry provided additional comments concerning the
number of Gulf of Mexico rigs in operation which are not capable of having a cuttings dryer system installed
due to either rig space and/or rig design without prohibitive costs or rig modifications.
EPA also requested comments in the NODA on the issue of rig compatibility with the installation of
cuttings dryers (e.g., vertical or horizontal centrifuges, squeeze press mud recovery units, High-G linear
shakers). EPA received general information on the problems and issues related to cuttings dryer installations
from API/NOIA stating that not all rigs are capable of installing cuttings dryers.6 In late comments, some
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industry commentors asserted that 48 of the 223 GOM drilling rigs are not capable of having a cuttings
dryer system installed due to either rig space and/or rig design without prohibitive costs or rig modifications.7
Upon a further, more extensive review of Gulf of Mexico rigs, these same commentors asserted that 30 of
234 Gulf of Mexico drilling rigs are not capable of having a cuttings dryer system installed due to either rig
space and/or rig design without prohibitive costs or rig modifications.8 EPA also received late comments
from one operator, Unocal, stating that 36 of 122 Unocal wells drilled between late 1997 and mid-2000
were drilled with rigs that do not have 40 foot x 40 foot space available which they assert is necessary for a
cuttings dryer installation.9 The API/NOIA rig survey and the Unocal rig survey identified most of the same
rigs as unable to install cuttings dryers. However, two rigs (i.e., Parker 22, Nabors 802) identified in the
Unocal rig survey as having no space for a cuttings dryer installation were identified in the API/NOIA rig
survey as having a previous cuttings dryer installation. Unocal requested in late comments that EPA
subcategorize certain rigs from being subject to the retention limit or that these rigs be able to discharge
SBFs using performance that reflects current shale shaker technology.
Based on the record, EPA finds that current space limitations for cuttings dryers do not require a 40
foot x 40 foot space. Specifically, EPA has in the record information gathered during EPA's October 1999
site visit and information supplied by API/NOIA and equipment vendors. Also, EPA received information
from a drilling fluid manufacturer and cuttings dryer equipment vendor, M-I Drilling Fluids, stating that they
are not aware of any Gulf of Mexico rig not capable of installing a cuttings dryer.10 API/NOIA estimated
that 150 square feet are required for a cuttings dryer installation in order to meet the ROC BAT limitation
and NSPS. EPA also estimates that the minimum height clearance for a typical cuttings dryer installation is
6 feet. The API/NOIA estimate is based on the installation of a horizontal centrifuge cuttings dryer. The
Unocal estimate is based on the vertical centrifuge cuttings dryer and is also characterized by other industry
representatives as too high.8 EPA's estimate of a typical vertical centrifuge installation is 15 feet x 15 feet
with a minimum height clearance of 11 feet. EPA based the ROC BAT limitation and NSPS (e.g., 6.9%)
on the use of both these cuttings dryers for SBFs with the stock limitations of C16-C18 lOs. Based on
comments from operators and equipment vendors, EPA believes that most of these shallow well rigs have
the requisite 160-225 square feet available to install a cuttings dryer. Therefore, EPA finds that operators
are not required to have a 1,600 square foot space for a cuttings dryer installation in order to meet the ROC
BAT limitation and NSPS. Proper spacing and placement of cuttings dryers in the solids control equipment
system should prevent installation problems.
Because of the large discrepancy between EPA's record information and the space requirements
asserted by the commenter (1,600 square feet versus EPA's 225 square feet +11 feet in height for the
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vertical centrifuge or 150 square feet + 6 feet in height for the horizontal centrifuge - MUD-6), EPA does
not necessarily believe that there are as many wells that cannot install cuttings dryers.
EPA also received information on a new cuttings containment, handling, and transfer equipment
system. The new system is designed to eliminate the need to use cuttings boxes to handle cuttings. EPA
received information from one operator that recently field tested the cuttings transfer system on one 12%
inch well section in the North Sea. The operator contained 100% of the cuttings on a rig (Alba) with limited
deck space. Cuttings were handled in bulk below deck and pumped directly onto a waiting vessel for
eventual land disposal. The operator estimated that use of the new cuttings transfer system eliminated
hundreds of crane lifts and manual handling issues and thereby improved worker safety.
3.2 Current Drilling Fluid Costs
In response to the NODA, EPA received new information and revised unit costs of WBF, OBF,
and SBF. Based on industry data, EPA estimates WBF at a unit cost of $45 per barrel for the final rule.
The proposed rule and NODA used OBF and SBF unit costs of $75 and $200 per barrel of drilling fluid,
respectively. More recent industry data indicate a range of OBF unit costs from $70 - $90 per barrel; EPA
uses an OBF unit cost of $79 per barrel for the final rule.:: Based on industry data submissions, EPA
estimates that SBF unit costs will remain between $160 to $300 per barrel of drilling fluid over the next few
years, and uses an SBF unit cost of $221 per barrel of drilling fluid for the final rule based on the most
frequently used SBF in the offshore market (see Section 3.3.2 of Chapter VIII for further detail on unit cost
derivation).
3.3 Cost Savings of SBF Use as Compared with WBF Use
EPA revised its compliance costs/savings to include the following factors: (1) the cost savings
associated with decreased length of drilling programs when using SBF as compared to WBF; (2) the cost of
lost WBFs that are discharged while drilling; and (3) the costs associated with projected failures of a fraction
of WBF wells to meet sheen or toxicity limitations, including costs of meeting zero discharge from these
wells. EPA used these data to examine compliance costs impacts of operators converting to or from SBF
from or to WBF.
EPA requested data from industry on rate of penetration (ROP) for WBF operations as compared
to SBF operations. Industry stated that ROP values of 300 feet per hour for SBF (and OBF) operations
and 150 feet per hour for WBF are reasonable averages. However, using these values over an entire well
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was not recommended "due to the large number of variables."2 Industry's information further states that a
generally-accepted estimate is that "SBFs reduce overall drilling time by 50%"2 and is due not only to
greater ROP but decreased incidence of stuck pipe and other operational difficulties (e.g., lost circulation,
bore hole integrity, etc.).
3.4 Construction Cost Index
EPA used the Construction Cost Index (CCI) from the Engineering News and Record12 to reflect
costs in 1999 dollars rather than 1998 dollars as was used for the NODA. EPA used a CCI factor of 1.108
to reflect 1999 dollars and a base year of 1995.
4. NON-WATER QUALITY ENVIRONMENTAL IMPACT ANALYSES
EPA received additional data relating to the NWQEI analyses in response to the NODA. These
data include additional information on retention on cuttings and information regarding offshore injection and
onshore disposal practices for each of the three geographical areas: Gulf of Mexico, offshore California, and
Cook Inlet, Alaska.
EPA revised the average SBF retention on cuttings for the two discharge options based on
additional ROC data. Revisions in ROC data affect the volume of SBF-cuttings generated. Consequently,
EPA revised the amount of SBF-cuttings that will need to be treated under the two SBF-cuttings controlled
discharge options (e.g., BAT/NSPS Options 1 and 2). EPA also revised: (1) the amount of SBF-fmes that
will need to be re-injected on-site or hauled to shore for disposal under one of the SBF-cuttings controlled
discharge option (e.g., BAT/NSPS Options 2); and (2) the amount of SBF-fmes and SBF-cuttings injected
onsite or hauled to shore for disposal under the zero discharge option (BAT/NSPS Options 3).
EPA received additional SBF well interval data which was used to re-calculate the number of days
to drill the model SBF wells. For the NWQI analyses, the number of days to drill the model wells serves as
the basis for estimating the length of time equipment will be used to either treat the cuttings before discharge
or the hauling requirements under the zero discharge option. The EPA NWQI models estimate that air
emissions and fuel use rates increase when the time required to complete a model well also increases.
EPA obtained information regarding the current practice of zero discharge disposal for each of three
geographic areas, Gulf of Mexico, offshore California, and Cook Inlet, Alaska. Current practice indicates
that most of the waste generated in the Gulf of Mexico and offshore California and brought to shore is
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injected onshore, whereas all of the waste currently generated in Cook Inlet is injected offshore at the
drilling site or at a near-by Class II UIC disposal well. EPA also received from an onshore injection facility
specific equipment information, including the cuttings injection rate and cuttings grinding and injection
equipment power requirements and fuel rates.13
Industry provided EPA with information regarding SBF use. One operator (Unocal) stated that it is
starting to use SBF to drill the entire well and not just intervals in which WBFs present problems because
drilling time can be significantly reduced. EPA incorporated this information into the NWQI analyses by
estimating the reduction of impacts when using SBFs instead of WBFs. EPA also received during the
NODA comment period information related to the average increase in drilling time (1.5 days) in order to
comply with zero discharge.14
5. COMPLIANCE ANALYTICAL METHODS
EPA completed additional studies in response to the NODA to support the development of
analytical methods for determining sediment toxicity, biodegradation, and oil retention on cuttings. For
sediment toxicity and biodegradation, EPA focused specifically on optimizing test conditions (e.g., test
duration, sediment composition), discriminatory power, reproducibility, reliability, and practicality. EPA's
sediment toxicity study provided toxicity data for both pure base fluids and standard mud formulations of
these base fluids. EPA's biodegradation study evaluated the degradation of pure base fluids as determined
by the solid phase test. For oil retention on cuttings, EPA conducted studies to verify and document the
sensitivity of the retort test method.
During this same time period, industry sponsored Synthetic Based Muds Research Consortium
(SBMRC) conducted parallel studies on the same three parameters (i.e., sediment toxicity, biodegradation,
and base fluid retention on cuttings). For sediment toxicity, industry provided extensive data comparing a 4-
day versus a 10-day test duration, natural versus synthetic sediments, as well as toxicity data on both pure
base fluids and mud formulations of these base fluids. For biodegradation, industry submitted results from
the closed bottle and respirometry tests for biodegradation in addition to the solid phase test. For oil
retention on cuttings, Industry and EPA conducted rig-based method detection limit studies.
6. SEABED SURVEYS
EPA received public comments regarding the impact of SBF discharges on the benthic environment.
EPA also received information on the on-going joint industry/MMS Gulf of Mexico seabed survey. The
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Industry/MMS workgroup completed the first two cruises of the four cruise study in time for EPA's
consideration for this final rule. Cruise 1 was a physical survey of 10 Gulf of Mexico shelf locations, with
the objective of detection and delineation of cuttings piles using physical techniques. Cruise 2 was to scout
and screen the final 5 shelf and 3 deep water Gulf of Mexico wells chosen for the definitive study where
SBF were used. The SBF-cuttings discharges included either internal olefins or LAO/ester blends. Both
cruises did not detect any large mounds of cuttings under any of the rigs or platforms. Remotely operated
vehicles (ROV) using video cameras and side-scanning sonar were used to conduct the physical
investigations on the seabed. Video investigations only detected small cuttings clumps (<6") around the base
of some of the facilities and 1" thick cuttings accumulations on facility horizontal cross members. Outside
of a 50-100' radius from the facility, no visible cuttings accumulations (large or small) were detected at any
of the facility survey sites.
Finally, EPA received a report prepared for the MMS which provided a review of the scientific
literature and seabed surveys to determine the environmental impacts of SBFs.15 The literature report
confirms EPA's position that benthic communities will recover as SBF concentrations in sediments decrease
and sediment oxygen concentrations increase. The report also confirms EPA's position that within three to
five years of cessation of SBF cuttings discharges, concentrations of SBFs in sediments will have fallen to
low enough levels and oxygen concentrations will have increased enough throughout the previously affected
area that complete recovery will be possible.
7. REFERENCES
1. Orentas, N. 2000. Email to B. Vanatta, ERG, Revised days to drill. 8/28/00. (Record No.
IV.B.a.7)
2. Henry, L., Chevron. Memorandum to C.A. Johnston, EPA. Response to EPA Request for
Additional Input Parameter for EPA Modeling. 9/11/00. (Record No. IV.B.a.9)
3. Farmer, J.M., BPAmoco. Email to C.A. Johnston, EPA. Response to EPA Request for Additional
Input Parameter for EPA Modeling. 9/9/00. (Record No. IV.B.a. 10)
4. Ressler, J., Unocal. Email to C.A. Johnston, EPA. Response to EPA Request for Additional Input
Parameter for EPA Modeling. 9/11/00. (Record No. IV.B.a. 11)
5. Avanti. 2000. Memorandum to File, Assessment of Numbers of Wells Drilled per Structure in the
Gulf of Mexico. 9/18/00. (Record No. IV.B.a. 14)
6. Moran, R., National Ocean Industries Association, Re: National Ocean Industries Association,
American Petroleum Institute, Offshore Operators Committee, and Petroleum Equipment Suppliers
Association Comments on "Effluent Limitations Guidelines for Oil and Gas Extraction Point Source
Category," Proposed Rule 65 FR 21548 (April 21, 2000). 6/20/00. (Record No. IV.A.a.13)
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7. Angelle, R. and P. Scott. 2000. Rig Survey Related to Installation Cost and Operational Costs of
"Cuttings Dryers" to Reduce the Retention of Synthetic Based Mud on Cuttings Discharge.
(Record No. IV.B.b.33)
8. Angelle, R. and P. Scott. 2000. Rig Survey Update Focusing on the Number of Rigs/Platforms
Where Cuttings Dryers Could Not be Installed. Prepared by the Technology Assessment
Workgroup of Synthetic Based Mud Research Consortium (API and NOIA) in Conjunction with
Cuttings Dryer Equipment Vendor Representatives. 11/9/00. (Record No. IV.B.b.34)
9. O'Donnell, K., Unocal. 2000. Letter to M. Rubin, EPA transmitting additional information.
10/26/00. (Record No. IV.B.b.31)
10. Candler, J., M-I Drilling Fluids. Email to C. Johnston, EPA concerning ability of service companies
to place cuttings dryers on rigs. 11/10/00. (Record No. IV.B.b.32)
11. Candler, J., M-I Drilling Fluids. Email to C.A. Johnston RE: unit costs for various muds. 10/23/00.
(Record No. IV.B.a. 13)
12. http://www.enr.com/cost/costcci.asp (Record No. IV.B.a. 12)
13. Johnston, C.A., EPA. Memorandum to File, On-shore Formation Injection Disposal Non-Water
Quality Environmental Impact Input Parameters. 6/20/00. (Record No. IV.D.2)
14. Van Slyke, Don, Unocal. Unocal Comments; Effluent Limitations Guidelines for the Oil and Gas
Extraction Point Source Category; Proposed Ruling (40 CFR 435). 6/9/00. (Record No. IV.A.a.3)
15. Neff, J.M., S. McKelvie and R.C. Ayers. 2000. A Literature Review of Environmental Impacts of
Synthetic Based Drilling Fluids, Draft. Report to USDOI, MMS. 4/27/00. (Record No. IV.F. 1)
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CHAPTER VI
SELECTION OF POLLUTANT PARAMETERS
1. INTRODUCTION
This section presents information concerning the selection of the pollutants to be limited for the
SBF Effluent Limitations Guidelines and Standards. The information consists of identifying the pollutants
for which limitations and standards have been promulgated. 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. STOCK LIMITATIONS OF BASE FLUIDS
2.1 General
EPA is establishing BAT and NSPS that require the synthetic materials and other oleaginous
materials which form the base fluid of the SBFs and other non-aqueous drilling fluids to meet limitations on
PAH content, sediment toxicity, and biodegradation. The technology basis for meeting these limits would
be product substitution, zero discharge based on land disposal or injection if these limits are not met, or use
of traditional drilling fluids under existing requirements. These parameters are being regulated to control the
discharge of certain toxic and nonconventional pollutants. A large range of synthetic, oleaginous, and water
miscible materials have been developed for use as base fluids. These stock limitations on the base fluid are
intended to encourage product substitution reflecting the best available technology of using those synthetic
materials and other base fluids which minimize potential loadings and toxicity.
EPA is promulgating BAT, and NSPS for SBFs and SBF-cuttings for Coastal Cook Inlet, Alaska as
zero discharge except when Coastal Cook Inlet, Alaska, operators are unable to dispose of their SBF-
cuttings using any of the following disposal options: (1) on-site injection (annular disposal or Class II UIC);
(2) injection using a nearby Coastal or Offshore Class II UIC disposal well; (3) onshore disposal using a
nearby Class II UIC disposal well or land application. The regulated toxic, conventional, and
nonconventional pollutant parameters are identified below.
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2.2 Base Fluid PAH Content
EPA is regulating the PAH content of base fluids because PAHs consist 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.:
The PAHs typically found in diesel and mineral oils include the toxic priority pollutants fluorene,
naphthalene, phenanthrene, and others, and nonconventional pollutants such as alkylated benzenes and
biphenyls.2 Therefore, the BAT limitation and NSPS for PAHs are components of the final regulation
which help discriminate between acceptable and non-acceptable base fluids.
2.3 Base Fluid Sediment Toxicity
EPA is also regulating the sediment toxicity in base fluids as a nonconventional pollutant parameter
and as an indicator for toxic pollutants of base fluids (e.g., enhanced mineral oils, internal olefms, linear
alpha olefms, poly alpha olefms, paraffinic oils, C12-C14 vegetable esters of 2-hexanol and palm kernel oil,
"low viscosity" C8 esters, and other oleaginous materials.)3 It has been shown, during EPA's development
of the Offshore Guidelines, that establishing limits on toxicity encourages the use of less toxic drilling fluids
and additives. Many of the SBF base fluids have been shown to have lower sediment toxicity than OBF
base fluids, but among SBFs some are more toxic than others.4'5> 6 The selected discharge option (i.e.,
BAT/NSPS Option 2) includes a base fluid sediment toxicity stock limitation, as measured by the 10-day
sediment toxicity test (ASTM E1367-92) using a natural sediment or formulated sediment and Leptocheirus
plumulosus as the test organism.
2.4 Base Fluid Biodegradation
EPA is also regulating biodegradation of base fluids as an indicator of the extent, in both level and
duration, of the adverse effects of toxic and nonconventional pollutants present that are in base fluids (e.g.,
enhanced mineral oils, internal olefms, linear alpha olefms, poly alpha olefms, paraffinic oils, C12-C14
vegetable esters of 2-hexanol and palm kernel oil, "low viscosity" C8 esters, and other oleaginous materials).
Based on results from seabed surveys at sites where various base fluids have been discharged with drill
cuttings, EPA believes that the results from the three biodegradation tests used during the rulemaking (e.g.,
solid phase test, anaerobic closed bottle biodegradation test, respirometry biodegradation test) are indicative
of the relative rates of biodegradation in the marine environment. In addition, EPA believes biodegradation
correlates strongly with the rate of recovery of the seabed where OBF- and SBF-cuttings have been
discharged. The various base fluids vary widely in biodegradation rates, as measured by the three
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biodegradation methods.6 However, the relative ranking of the base fluids under consideration remain
similar across all three biodegradation tests investigated under this rulemaking.
As originally proposed in February 1999 (64 FR 5504) and re-stated in April 2000 (65 FR 21550),
EPA is today promulgating a BAT limitation and NSPS to control the minimum amount of biodegradation
of base fluids. Today's final discharge option (i.e., BAT/NSPS Option 2) includes a base fluid
biodegradation stock limitation, as measured by the marine anaerobic closed bottle biodegradation test (i.e.,
ISO 11734).
2.5 Base Fluid Bioaccumulation
EPA also considered establishing a BAT limitation and NSPS that would limit the base fluid
bioaccumulation potential. The regulated parameters would be the nonconventional and toxic priority
pollutants that bioaccumulate. EPA reviewed the current literature to identify the bioaccumulation potential
of various base fluids. After this review EPA determined that SBFs are not expected to significantly
bioaccumulate because of their extremely low water solubility and consequent low bioavailability. Their
propensity to biodegrade makes them further unlikely to significantly bioaccumulate in marine organisms.
EPA identified that hydrophobic chemicals (e.g., ester-SBF base fluids) that have a log Kow less
than approximately 3 to 3.5 may bioaccumulate rapidly but not to high concentrations in tissues of marine
organisms, particularly if they are readily biodegradable into non-toxic metabolites.3 [Note: the
octanol/water partition coefficient (Kow) is used as a surrogate for estimating bioaccumulation in biological
lipid components. Moreover, hydrophobic chemicals (e.g., C16-C18 internal olefms, various poly alpha
olefms, and C18 n-paraffms) with a log Kow greater than about 6.5 to 7 do not bioaccumulate effectively
from the water phase primarily, because their solubility, hence mobility, in the water phase is very low.3
Finally, the degradation by-products of SBF base fluids (e.g., alcohols) are likely to be more polar (i.e.,
more miscible with water) than the parent substances. The higher water solubility will result in these
degradation by-products partitioning into the water column, but should quickly be diluted to lexicologically
insignificant concentrations.
Based on current information, EPA believes that the stock base fluid controls on PAH content,
sediment toxicity, and biodegradation rate being promulgated today are sufficient to only allow the discharge
of base fluids (e.g., esters, internal olefms) with lower bioaccumulation potentials (i.e., log Kow < 3 to 3.5
and log Kow > 6.5 to 7).
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3. DISCHARGE LIMITATIONS
3.1 Free Oil
Under BPT and BCT limitations for SBF-cuttings, EPA retains the prohibition on the discharge of
free oil as determined by the static sheen test (see Appendix 1 of Subpart A of 40 CFR 435). Under this
prohibition, drill cuttings may not be discharged when the associated drilling fluid fails the static sheen test.
The prohibition on the discharge of free oil is intended to minimize the formation of sheens on the surface
of the receiving water. The regulated parameter of the no free oil limitation is the conventional pollutant oil
and grease, which separates from the SBF and causes a sheen on the surface of the receiving water.
The free oil discharge prohibition does not control the discharge of oil and grease and crude oil
contamination in SBFs as it would in WBFs. With WBFs, oils that may be present (such as diesel oil,
mineral oil, formation oil, or other oleaginous materials) are present as the discontinuous phase. As such,
these oils are free to rise to the surface of the receiving water where they may appear as a film or sheen
upon or discoloration of the surface. By contrast, the oleaginous matrices of SBFs do not disperse in water.
In addition they are weighted with barite, which causes them to sink as a mass without releasing either the
oleaginous materials that constitute the SBF or any contaminant formation oil. Thus, the test would not
identify these pollutants. However, a portion of the synthetic material that constitutes 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 is
to control the discharge of oil and grease that separates from the SBF and causes a sheen on the surface of
the receiving water. In addition, the no free oil limitation controls all pollutants (i.e., conventional,
nonconventional, and toxic pollutants) in SBFs by approximating the level of control that can be achieved by
existing shall shaker technology. The limitation, however, is not intended to control formation oil
contamination.
3.2 Formation Oil Contamination
Formation oil contamination of the SBF associated with the cuttings is limited under BAT and
NSPS. EPA also promulgated a screening method [Reverse Phase Extraction (RPE) method presented in
Appendix 6 to Subpart A of Part 435] and a compliance assurance method [Gas Chromatograph/Mass
Spectrometer (GC/MS) method presented in Appendix 5 to Subpart A of Part 435].
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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 Chapter VII). The
RPE method is a fluorescence test and is appropriately "weighted" to better detect crude oils. These crude
oils contain more toxic aromatic and PAH pollutants and show brighter fluorescence (i.e., noncompliance) in
the RPE method at lower levels of crude oil contamination. Because the RPE method is a relative
brightness test, GC/MS is promulgated as the confirmatory compliance assurance method when the results
from the RPE compliance method are in doubt by either the operator or the NPDES controlling authority.
Results from the GC/MS method will supersede those of the RPE method. EPA also requires that
operators verify and document that an SBF is free of formation oil contamination before initial use of the
SBF. The GC/MS method will be used to verify and document the absence of formation oil contamination
in SBFs.
3.3 Retention of SBF on Cuttings
EPA is promulgating a BAT limitation and NSPS to control the retention of drilling fluid on drill
cuttings. The BAT limitation and NSPS are presented as the percentage of base fluid on wet cuttings [i.e.,
mass base fluid (g)/mass wet cuttings (g)], averaged over the entire well sections drilled with SBF. The
limitation and standard control the quantity of drilling fluid discharged with the drill cuttings. Both
nonconventional and priority toxic pollutants are controlled by this limitation. Nonconventionals include the
SBF base fluids, such as enhanced mineral oils, internal olefins, linear alpha olefins, poly alpha olefins,
paraffinic oils, C12-C14 vegetable esters of 2-hexanol and palm kernel oil, "low viscosity" C8 esters, and
other oleaginous materials. 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 This limitation also controls nonconventional pollutants found in some drilling
fluid components (e.g., emulsifiers, oil wetting agents, filtration control agents, and viscosifiers) that are
added to the base fluid in order to build a complete SBF package. These pollutants would not be controlled
by the sediment toxicity stock limitations. In response to the February 1999 Proposal (64 FR 5501), EPA
received comments that these nonconventional pollutants include fatty acids.4 EPA also received further
information that the non-conventional pollutants in these drilling fluid components include amine clays,
amine lignites, and dimer/trimer fatty acids.5
This limitation also controls the toxic effect of the drilling fluid and the persistence or biodegradation
of the base fluid. Specifically, as stated in the April 2000 NODA (65 FR 21553), lowering the percentage of
residual drilling fluid retained on cuttings increases the recovery rate of the seabed receiving the cuttings.6i 7> 8
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Limiting the amount of SBF content in discharged cuttings controls: (1) the amount of toxic and non-
conventional pollutants in SBF which are discharged to the ocean; (2) the biodegradation rate of discharged
SBF; and (3) the potential for SBF-cuttings to develop cuttings piles and mats which are deleterious to the
benthic environment.
As originally proposed in February 1999 (64 FR 5547) and re-stated in April 2000 (65 FR 21552),
EPA promulgated a retort and sampling compliance method for the cuttings retention BAT limitation and
NSPS (see Appendix 7 to Subpart A of 40 CFR 435; API Recommended Practice 13B-2).
3.4 Cuttings Discharge Sediment Toxicity
EPA also regulates the sediment toxicity in SBF discharged with cuttings as a nonconventional
pollutant parameter and as an indicator for toxic pollutants in SBFs and additives (e.g., emulsifiers, oil
wetting agents, filtration control agents, and viscosifiers) that comprise the drilling fluid package. EPA has
promulgated a BAT limitation and NSPS to control the maximum sediment toxicity of the SBF discharged
with cuttings at the point of discharge. The sediment toxicity of the SBF-cuttings at the point of discharge is
measured by the modified sediment toxicity test (ASTM El367-92) using a natural sediment or formulated
sediment and Leptocheirus plumulosus as the test organism.
EPA finds that the sediment toxicity test at the point of discharge is practical as an indicator of the
sediment toxicity of the drilling fluid at the point of discharge. The sediment toxicity test applied at the point
of discharge will control non-conventional pollutants found in some drilling fluid components (e.g.,
emulsifiers, oil wetting agents, filtration control agents, and viscosifiers) which are added to the base fluid in
order to build a complete SBF package. Other possible toxic pollutants of drilling fluids may include
mercury, cadmium, arsenic, chromium, copper, lead, nickel, and zinc, and formation oil contaminants. As
previously stated, establishing discharge limits on toxicity encourages the use of less toxic drilling fluids and
additives. The modifications to the 10-day sediment toxicity test include shortening the test to 96-hours.
Shortening the test allows operators to continue drilling operations while the sediment toxicity test is being
conducted on the discharged drilling fluid. Finally, operators discharging WBFs are already complying with
a biological test at the point of discharge, the 96-hour SPP toxicity test, which tests whole WBF aquatic
toxicity using the test organism Mysidopsis bahia.
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4. MAINTENANCE OF CURRENT REQUIREMENTS
EPA retains the existing BAT and NSPS limitations on the stock barite of 1 mg/kg mercury and 3
mg/kg cadmium. These limitations control the levels of toxic pollutant metals because cleaner barite that
meets the mercury and cadmium limits is also likely to have reduced concentrations of other metals.
Evaluation of the relationship between cadmium and mercury and the trace metals in barite shows a
correlation between the concentration of mercury with the concentration of arsenic, chromium, copper,
lead, molybdenum, sodium, tin, titanium and zinc.2
EPA also retains 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.
EPA is not modifying the existing BAT limitation and NSPS for controlling the maximum aqueous
phase toxicity of SBF-cuttings at the point of discharge using the suspended particulate phase (SPP) test
(see Appendix 2 of Subpart A of Part 435). The BAT limitation and NSPS for controlling aqueous toxicity
of discharged SBF-cuttings is retained as the minimum 96-hour LC50 of the SPP shall be 3 percent by
volume. EPA is interested in controlling the toxicity of drilling fluids in the sediment and the water column
and is requiring both a sediment toxicity test and an aqueous phase toxicity test to assess overall toxicity of
the drilling fluid at the point of discharge. EPA finds that the SPP test at the point of discharge is practical
as a measurement of the aquatic toxicity of the drilling fluid at the point of discharge. The discharge SPP
test will control non-conventional pollutants found in drilling fluid components (e.g., emulsifiers, oil wetting
agents, filtration control agents, and viscosifiers) which are added to the base fluid in order to build a
complete SBF package. Moreover, operators discharging WBFs are already complying with the SPP
toxicity test on discharged WBFs.
5. REFERENCES
Daly, J., 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,
D.F. Jacques, Ph. D., June 25, 1996, and 2) Letter from M.E. Parker, P.E., Exxon Company
U.S.A., to M. B. Rubin, EPA. 9/17/96. (Record No. I.B.a.2)
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2. 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.
3. Neff, J.M., S. McKelvie and R.C. Ayers. 2000. A Literature Review of Environmental Impacts of
Synthetic Based Drilling Fluids, Draft. Report to USDOI, MMS. 4/27/00. (Record No. IV.F. 1)
4. Rubin, M., API and R.J. Moran, NOIA. Letter to M. Rubin, EPA in response to proposed effluent
limitation guidelines, May 1999. (Record No. III.A.a.7)
5. Parker, M. Industry Operator Answers to EPA Solids Control Questions. Personal communication
between M. Parker, ExxonMobil Production Company and R. Kirby, EPA, November 1999.
(Record No. III.B.b.l)
6. Vik, E.A., B.S. Dempsey, B. Nesgard. 1996. 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. (Record No. I.D.b.30)
7. Vik, E.A., B. Nesgard, J.D. Berg, S.M. Dempsey, D.R. Johnson, L. Gawel, and E. Dalland. 1996.
Factors Affecting Methods for Biodegradation Testing of Drilling Fluids for Marine Discharge. SPE
35981, pp. 697-711. (Record No. I.D.b.31)
8. Getliff, J. A. Roach, J. Toya, and J. Carpenter. 1997. An Overview of the Environmental Benefits
of LAO Based Drilling Fluids for Offshore Drilling. Presented at the 5th International Conference
on Minimizing the Environmental Effects of Drilling Operations. 6/23/97. (Record No. III.B.a. 15)
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CHAPTER VII
DRILLING WASTES CHARACTERIZATION, CONTROL, AND
TREATMENT TECHNOLOGIES
1. 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
currently available pollution control and treatment technologies that recover SBF from drill cuttings,
reducing the volume of drilling wastes and the quantities of pollutants discharged to surface waters.
2. DRILLING WASTE SOURCES
Drilling fluids and drill cuttings are the most significant waste streams from exploratory and
development well drilling operations. EPA proposes limitations for the waste stream of synthetic-based
fluids and associated cuttings ("SBF-cuttings") that are generated when SBF or other non-aqueous drilling
fluids are used. All other waste streams from well drilling operations and other drilling fluid types (i.e.,
water-based or oil-based fluids) have current applicable limitations and standards that are not included under
this rulemaking. The following subsections discuss the sources of SBF and SBF-cuttings in well drilling
operations.
2.1 Drilling Fluid Sources
SBFs are considered a valuable commodity and not a waste. It is industry practice to continuously
reuse SBFs while drilling a well interval. At the end of the well, remaining SBF is shipped back to shore for
refurbishment and reuse. SBF is discharged only as a contaminant of the drill cuttings waste stream. It is
not discharged as a neat drilling fluid waste stream (drilling fluid not associated with cuttings), unlike WBF
discharges. Compared to WBFs, SBFs are relatively easy to separate from drill cuttings because they do
not disperse in WBFs to the same extent. Due to the dispersion of fine cuttings in WBF, drilling fluid
components often need to be added to maintain required drilling fluid flow properties (rheology). These
additions are frequently in excess of the drilling fluid system capacity. The excess "dilution volume" of a
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water-based drilling fluid is discharged as a resultant waste. The generation of this dilution volume waste
stream does not occur with SBFs.
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
OBF or 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,
โข 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,
โข drilling fluid cost - base cost plus daily operating cost,
drilling operation cost - rig cost plus logistics and operation support, and
โข drilling waste disposal cost.
Industry has commented that while the right combination of factors that favor the use of SBF can occur in
any area, they most frequently occur with "deep water" operations.: This is due to the fact that these are
higher cost operations and therefore can better justify the higher initial cost of SBF use.
The recovery of SBF from drill cuttings serves two purposes. The first is to return drilling fluid for
reintroduction to the active drilling fluid system, and the second is to minimize the discharge of SBF. As
more aggressive methods are used to recover drilling fluid from cuttings, the cuttings tend to break down
into smaller particles, called fines. Fines are not only more difficult to separate from drilling fluid, but also
cause a deterioration of certain properties (i.e., rheology) of the drilling fluid. Increased recovery of fluid
from cuttings is a larger problem for WBFs than SBFs because WBFs encourage cuttings to disperse and
degrade WBF rheology more than do SBFs. Compared to WBF, more aggressive methods of recovering
SBF from the cuttings waste stream are both practical and, because of the much higher cost of SBF,
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desirable. These more aggressive fluid recovery methods also more effectively reduce the discharge of
SBF. This improved treatment reduces the potential for anoxia (lack of oxygen) in the receiving sediment as
well as the quantity of toxic and nonconventional components of discharged SBF. The level of reduction of
SBF on cuttings discharges required in this rule reflects appropriate use of the BAT technologies.
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, 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
faster biodegradation (especially anaerobic) is environmentally preferable to slower biodegradation despite
the increased risk of short term anoxia that accompanies faster biodegradation. This is because cuttings
piles generally promote anaerobic activity, especially in deeper waters, and 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 piles or directly in sediment, and does not seem to be correlated with short term 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 regulated drilling fluid pollutant parameters in section VI.2).
Barite, a weighting agent that is a component of SBF, is also discharged with SBF adhering to 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
VII-3
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fines as well as the large cuttings from the drilling fluid to maintain the required flow properties (see section
VII. 5. 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 (often called "scalp" 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 from the primary and secondary shakers may be passed through a centrifuge (often referred to
as a decanting centrifuge) or another shale shaker with a very fine mesh screen (often referred to as a mud
cleaner) that functions as a fines removal unit. It is important to remove fines from drilling fluid to maintain
the desired rheology of the active drilling fluid system. Thus, the cuttings waste stream typically consists of
larger cuttings from the primary shale shakers, fines from a fine mesh shaker or centrifuge, and may also
consist of smaller cuttings from a secondary shale shaker. Additionally, the cuttings that leave the primary
shaker may be further treated by another shaker, typically referred to as a drying shaker or cuttings dryer, to
indicate that its purpose is to treat cuttings, as opposed to a secondary shaker or mud cleaner that treats
drilling fluid.
Drill cuttings are typically discharged continuously during drilling as they are separated from the
drilling fluid in the solids separation equipment. The drill cuttings will also carry a residual amount of
adherent 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 habitats.
3. DRILLING WASTE CHARACTERISTICS
The waste stream discharged from drilling operations that use SBFs or other non-aqueous drilling
fluids consists of three components: adherent 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.
VII -4
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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 waste stream, 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 waste stream. A total oil concentration of 190.5 Ibs 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 Ibs/bbl).7'8
EPA estimates 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 metal pollutants. The
characteristics of raw barite determine the concentrations of metals found in the adhering drilling fluid. 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 cadmium and 1 mg/1 for mercury (58 FR 12454, March
4, 1993). Table VII-1 includes the metals concentration profile for barite.
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TABLE VII-1
SBF DRILLING WASTE CHARACTERISTICS
Waste Characteristics
SBF formulation
Synthetic base fluid density
Barite density
SBF drilling fluid density
Percent (vol.) formation oil
Value
47% synthetic base fluid, 33%
barite, 20% water (by weight)
280 pounds per barrel
1,506 pounds per barrel
9.65 pounds per gallon
0.2%
References
Calculated from industry data (Ref.
Ref. 7 and 8
Ref. 9
Calculated from industry data (Ref.
See section VII.3.3
Pollutant Concentrations in SBF
Conventional
Total Oil as synthetic base fluid
Total Oil as formation oil
TSS as barite
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Priority Pollutant Metals
Cadmium
Mercury
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Non-Conventional Metals
Aluminum
Barium
Iron
Tin
Titanium
Non- Conventional Organics
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total Dibenzothiophenes
Ibs/bblofSBF
190.5
0.588
133.7
Ibs/bblofSBF
0.0010024
0.0005468
0.0012968
0.000003528
mg/kg Barite
1.1
0.1
5.7
7.1
0.7
240.0
18.7
35.1
13.5
1.1
0.7
1.2
200.5
mg/kg Barite
9,069.9
588,000
15,344.3
14.6
87.5
Ibs/bblofSBF
0.0056429
0.0530502
0.0063859
0.0080683
0.0000311
0.0104867
0.0004469
Reference
Derived from SBF formulation and
densities listed above
Reference
Calculated from diesel oil
composition in Offshore
Development Document, Table VII-9
(Ref. 10 and 11)
Reference
Offshore Development Document,
Table XI-6 (Ref. 10)
Reference
Offshore Development Document,
Table XI-6 (Ref. 10), except for
barium, which was estimated (Ref.
12)
Reference
Calculated from diesel oil
composition in Offshore
Development Document, Table VII-9
(Ref. 10 and 11))
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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
133.7 Ibs/bbl of SBF listed in Table VII-1, was calculated from the SBF formulation described above, and a
barite density of 1,506 Ibs/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 9.65 Ibs/gal (405 Ibs/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 waste stream is based on the density of the dry weight of
cuttings, quoted in the literature as 910 Ibs/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.
3.3 Formation Oil Contamination
In addition to the SBF base fluid, formation oil is another source of oil and grease in SBF-cuttings
discharges. Formation oil contains organic priority pollutants. For the proposed rule, the majority of
formation oils would fail to meet the static sheen test or toxicity test limitations when present in SBFs at a
concentration of about 0.5%. Based on this estimate of the concentration of formation oil that would not
meet existing requirements and based on information from the industry concerning formation oil
contamination of drilling fluids,15 EPA estimates that, on average, the adhering drilling fluid in a model SBF-
cuttings waste stream 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 0.588 Ibs of formation oil per bbl SBF
VII-7
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shown in Table VII-1 was calculated from the SBF formulation described above, and a specific gravity of
0.84 (294 Ibs/bbl) quoted in the literature for diesel oil.9
4. 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
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; a generalization of washout for WBFs is 45 percent.62 Intervals drilled
with OBFs or SBFs are typically closer to gage size (i.e., washout is zero percent). A rule-of-thumb value
of 5 to 10% washout was recently cited by a Gulf of Mexico operator17 for intervals drilled with SBF,
consistent with a generalized estimate of 7.5 percent washout for SBF provided by another industry
source.62 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. 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. Each
separation unit in the system produces a cuttings waste stream 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
VII-8
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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 OBFs or SBFs than WBFs because drill solids disperse and break up into
finer particles to a greater extent in WBFs.
4.2 Estimates of Drilling Waste Volumes
Based on the waste characteristics presented above in Table VII-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 waste stream.
4.2.1 Waste SBF/OBFDrill 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 industry sources17'62 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
VII-9
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SBF is the same for intervals drilled with OBF, based on industry source information stating that there is
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.
TABLE VII-2
MODEL WELL VOLUME DATA3
Model Well
SWD
SWE
DWD
DWE
Hole
Diameter15
(inches)
8.5
12.25
8.5
6
12.25
8.5
17.5
12.25
8.5
Depth
Interval15
(feet)
7,500
6,000
2,500
1,500
4,500
2,000
4,500
2,000
2,000
Gage
Volume
(cu. feet)
2,955
4,911
985
295
6,190
3,683
788
4,471
7,517
1,637
788
2,425
Gage
Volume
(barrels)
526
873
175
52
1,101
655
140
795
1,337
291
140
1,768
Gage Volume plus
7.5% Washout
(barrels)
565
1,184
855
1,901
a Data represent only those intervals API identified as being drilled with SBF.1 Numbers in bold typeface
are totals for the given model well.
b Source: API responses to EPA Technical Questions.1
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4.2.2 SBF Drilling Fluid Retention-on-Cuttings (ROC) Values
4.2.2.1 Retort Analytical Method
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
of50-cm3 + 0.25-cm3...
According to API RP 13B-2, the following measurements are made during the retort
procedure:
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:
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 (Mj) equals the weight of the cooled
retort assembly (E) minus the weight of the clean and dry retort assembly
(A).
Md = E - A
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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 M4 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 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 revised procedures that were instituted following the
proposal and published in the April 2000 NODA, included guidelines for sampling, and a worksheet for
calculating the amounts of total waste and waste components generated. API's goal in writing these revised
procedures was to "develop a definitive data base on retention of synthetic material in cuttings discharge
streams."21
Since the April 2000 NODA, EPA in conjuction with API conducted a study to establish the
method detection limit (MDL) of quantification for API Recommended Practice 13B-2. These studies
confirm that API Recommended Practice 13B-2 (50 mL retort with a 20 mL liquid receiver graduated in 0.1
mL increments) is sensitive enough to meet the ROC limitations.
In developing the study, EPA/API sought to simulate realistic field conditions by conducting the first
phase at three oil rig facilities. The first phase of the study required each rig-based laboratory to analyze a
set of replicate MDL samples (see Table VII-3). Based on the replicate analyses, EPA calculated an MDL
for each facility using the procedures specified at 40 CFR part 136, Appendix B. EPA then used the
facility-specific MDLs to calculate a pooled MDL and ML for the method. The pooled MDL and ML
include components of interlaboratory variability and represent levels which can be achieved by a single
laboratory using the method. In the second phase of the study, EPA contracted a single land-based
laboratory to verify that it could achieve the calculated pooled MDL and ML using two types of base fluids
(IO and ester; see Table VII-4).
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TABLE VII-3
API RECOMMENDED PRACTICE 13B-2 MDL PHASE 1 STUDY RESULTS
Facility
Marathon Oil
Exxon-Mobil
Mi-Shell
Pooled
MDL
1.7%
0.5%
1.1%
1.0%
ML
5%
2%
2%
2%
TABLE VII-4
API RECOMMENDED PRACTICE 13B-2 MDL PHASE 2 VERIFICATION RESULTS
Base Fluid
Internal olefin (IO)
Ester
MDL
0.9%
1.0%
ML
2%
2%
4.2.2.2 Solids Control Description and Performance
For proposal, EPA determined average drilling fluid retention values for solids control equipment
that was used in offshore drilling operations in the U.S. (hereafter referred to as baseline solids control) and
for solids control equipment that was 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 supplied offshore operators with synthetic-based drilling fluid.18 This
database contained 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 provided no further information regarding the arrangement of the solids control systems
associated with the individual wells. While a primary shale shaker was assumed to be the first unit in the
solids control train, the location and purpose of a what the database called a "secondary" shale shaker was
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 cuttings from the
secondary shale shakers were, 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. Centrifuge data were too limited to utilize in EPA's analysis. Based on this initial API database,
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EPA at proposal 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
applied equally to SBF-cuttings and OBF-cuttings in the baseline analysis for the proposal.
Retention data for the add-on solids control technology also 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, at proposal, 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 showed that the vibrating centrifuge was likely to perform at least as well
if not better, in the Gulf of Mexico than in the North Sea because untreated Gulf of Mexico cuttings have
lower retention values than those found 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%.19
This was 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 waste stream of cuttings
from the secondary shale shakers.
Subsequent to the proposal, EPA received and reviewed additional retention on cuttings data. In
response to the February 1999 Proposal, industry submitted data for SBF retention from 36 wells. EPA
rejected six files due to incomplete reporting and determined that 16 files were complete and accurate and
these data were present in the April 2000 NODA. Additionally, EPA received 14 post-proposal files too late
for inclusion in the April 2000 NODA analyses.
In response to the April 2000 NODA, EPA received and evaluated retention data from an additional
79 SBF wells: the 14 received after the February 1999 Proposal comment period; 27 additional data sets
received during the April 2000 NODA comment period; and 38 received after the April 2000 NODA
comment period. EPA determined that data from 49 of these 79 wells were complete and included in the
final rule analyses. Therefore, EPA used data from 65 wells to determine the final performance
effectiveness of the various solids control technologies. A summary of the data from the 65 wells used to
determine the final limitations is presented in the Statistical Analysis Document. The collection, engineering
review, and extraction of data from these files are described in a separate document entitled "Engineering
Review of SBF Retention-on-Cuttings Data."63
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4.2.3 Analysis of ROC Data and Determination of ROC Values
EPA developed effluent limitations guidelines and standards for the control of pollutant discharges
associated with the retention on cuttings (ROC) of SBFs and other drilling fluids that are non-dispersible in
water. EPA used data supplied by oil and operators and equipment vendors to support development of this
rule. EPA primarily used summary statistics based on these data for the following purposes: (a) estimating
current (baseline) pollutant discharges, (b) calculating potential effluent limits, and (c) evaluating regulatory
options. In this section, EPA presents the technology bases for final numeric limits, the data on which these
limits were based, and summary statistics from the Statistical Analysis Document.23
4.2.3.1 Effluent Guidelines Limitations and Standards
EPA selected two final numeric limits for the retention of SBF on cuttings. For drilling fluids with
the environmental properties of esters (toxicity and bio-degradation), the well-average ROC not to be
exceeded is 9.4%. Including foreign data but excluding measurement results without backup data, this is
based on the within-well averages of measurement results from Cuttings Dryer Technology 1. Cuttings
Dryer Technology 1 includes horizontal centrifuges, vertical centrifuges, squeeze presses, and high-G
dryers. For all other SBFs, the well-average ROC not to be exceeded is 6.9%. Including foreign data but
excluding measurement results without backup data, this is based on the within-well averages of
measurement results from Cuttings Dryer Technology 3. Cuttings Dryer Technology 3 includes horizontal
and vertical centrifuges. In both cases, as was proposed and presented in the April 2000 NODA, the
numeric limit is estimated as the 95th percentile of a normal probability distribution for the well-averages.
4.2.3.2 Data
Industry and equipment vendor representatives provided EPA with percent retention measurements
on drill cuttings discharged from solids control systems. These data described the percent retention of SBF
on cuttings after treatment from each of three technology types. The technology types include shakers
(with subtypes primary shakers, secondary shakers, and other shakers); cuttings dryers (with subtypes
horizontal centrifuge [Mud 10], vertical centrifuge, squeeze press, and high-G dryer); and fines removal
units (with subtypes decanting centrifuge and mud cleaner). These data were recorded as percent SBF on
cuttings in a sample ([weight of SBF]/[weight of wet cuttings], expressed as a percentage). Associated data
generally included either the drilling depth or the length of a segment drilled, pipe diameter, drilling fluid
treatment technology, backup data for the calculation of percent retention, and location of the drilling site.
EPA's engineering review of the raw data is documented in a separate memorandum.63
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4.2.3.3 Summary Statistics
For purposes of analysis and the development of potential limitations, the treatment technology
categories or subcategories used in EPA's Statistical Support Document are: primary shakers, secondary
shakers, other shakers, horizontal centrifuge (Mud 10), vertical centrifuge, squeeze press, high-G dryer,
cuttings dryer 1 (a combination of the horizontal centrifuge, vertical centrifuge, squeeze press, and high-G
dryer subcategories), cuttings dryer 2 (a combination of the horizontal centrifuge, vertical centrifuge, and
squeeze press subcategories), cuttings dryer 3 (a combination of the horizontal and vertical centrifuge
subcategories), decanting centrifuge, mud cleaner, and fines removal (a combination of the decanting
centrifuge and mud cleaner subcategories). Summary statistics describing SBF ROC performance for
various treatment systems based on foreign and domestic data, but excluding measurement results for which
there are no backup data, are presented in Table VII-5.
EPA has also compared the observed performance of wells used to develop the 95th percentile-
based limits to those final limits. For drilling fluids with the environmental properties of ester-based drilling
fluids, the numeric limit is based on combining data from the high-G dryer, squeeze press, horizontal
centrifuge, and vertical centrifuge. The high-G dryer is particularly important because it appears to take less
space than other technologies and it may fit on drilling rigs that may not otherwise be able to install a
cuttings dryer technology. For wells used in the development of final numeric limits, three out of six high-G
dryers, all five squeeze press units, all eight vertical centrifuges, and twenty-five out of twenty-six horizontal
centrifuges demonstrated their ability to comply with the numeric limit of 9.4% without further attention to
operations, maintenance, or design. For all other SBFs, the numeric limit is based on combining data from
the horizontal and vertical centrifuges. Both technologies are included to provide industry the ability to
choose between equipment vendors. For wells used in the development of the final numeric limits, all eight
vertical centrifuges and twenty-four out of twenty-six horizontal centrifuges demonstrated their ability to
comply with the numeric limit of 6.9% without further attention to operations, maintenance, or design.
VII-16
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TABLE VII-5
DRILLING FLUID TREATMENT SYSTEM RETENTION ON CUTTINGS PERFORMANCE3
Technology Category/Subcategory
'rimary Shale Shakers
Secondary Shale Shakers
Other Shale Shakers
-lorizontal Centrifuge (Mud 10)
Vertical Centrifuge
Squeeze Press
-ligh-G Dryer
Cuttings Dryer 1 (Combined Horizontal Centrifuge, Vertical
Centrifuge, Squeeze Press , and High-G Dryer )
Basis for limit on drilling fluids with the environmental
properties of esters]
Cuttings Dryer 2 (Combined Horizontal Centrifuge, Vertical
Centrifuge, and Squeeze Press )
Cuttings Dryer 3 (Combined Horizontal and Vertical Centrifuge )
Basis for limit on all other SBF\
decanting Centrifuge
Vlud Cleaner
7ines Removal (Combined Decanting Centrifuge and Mud
Cleaner)
Number of
Wells
32
22
22
26
8
5
6
45
39
34
22
21
39
Mean of
Wells
9.32
13.8
8.96
3.85
3.72
6.71
9.40
4.89
4.19
3.82
9.97
11.9
10.8
Variance
of Wells
9.28
12.1
3.16
4.04
2.38
1.92
4.69
7.42
4.25
3.56
5.13
6.97
6.30
95th
Percentil
e
14.3
19.5
11.9
7.16
6.26
8.99
13.0
9.37
7.59
6.93
13.7
16.2
14.9
a Includes foreign data, but excluding measurements for which there are no backup data.
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
API,21 EPA determined that the baseline treatment train includes primary shale shakers (PSS), secondary
shale shakers (SSS), and fines removal units (FRU). The estimated volume contribution of PSS, SSS, and
FRUs to the discharge waste stream are 78.5%, 18.5%, and 3.0%, respectively. Analysis of long-term
average (LTA) retention-on-cuttings data indicate that PSS demonstrate a retention value of 9.32%; SSS
demonstrate an SBF retention value of 13.8%; FRUs demonstrate an SBF retention value of 10.7%; a
retention value of 3.82% was determined for the solids control units that classify as cuttings dryers. The
following calculation was used to estimate system-wide retention for the baseline solids control system:
VII-17
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Weighted Average Baseline Solids Control Retention:
(0.785x9.32%) + (0.185x13.8%) + (0.03x10.7%) = 10.2%.
The final cuttings waste stream retention value was determined for the BAT Options 1 and 2 compliance-
level solids control system, which consists of final discharge waste stream contribution from cuttings dryers
and FRUs. Cuttings dryers receive and treat all cuttings from the primary shale shaker and contributes 97%
of the volume to the discharge waste stream, while the FRU volume contribution is 3%. Under BAT
Option 1, the discharged effluent is a composite of the waste streams from these two solids control units.
The weighted average retention for this system is as follows:
Weighted Average Compliance-Level Solids BAT 1 Control Retention:
(0.97 x 3.82%) + (0.03 x 10.7%) = 4.03%.
Under BAT Option 2, the FRU discharge does not receive an allowable volume contribution to the final
discharge limitation. Thus, only the cuttings dryers contribute to the final discharge effluent limitation. The
SBF retention value, therefore, for BAT Option 2 is 3.82% (i.e., 1.0 x 3.82%).
4.2.4 Calculation of SBF/OBF Model Well Drilling Waste Volumes
For each of the four SBF/OBF model wells, EPA calculated drilling waste volumes for intervals
drilled with SBF or OBF. The calculations specified per-well volumes for the waste stream 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,
โข barite,
โข whole SBF or OBF (the sum of the synthetic or oil base fluid, water, and barite),
โข formation oil, and
โข total waste generated (the sum of whole SBF, formation oil, and dry cuttings).
The general approach to this method is to calculate the total waste generated based on the relative
proportions of the above components in the waste stream 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
waste stream. Waste volumes are calculated for each model well for three discharge scenarios considered,
VII-18
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i.e., under baseline (current) technology conditions, under BAT 1 conditions (discharge of cuttings and
fines), and BAT 2 (discharge of cuttings; zero discharge of fines). The input data and generalized equations
used for these calculations are shown in Table VII-6. Appendix VII-1 presents the detailed calculations for
the four model wells, based on the equations in Table VII-6. The results are summarized for the baseline
and three regulatory options evaluated for all four well types in Table VII-7.
VII-19
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TABLE VII-6
INPUT DATA AND GENERAL EQUATIONS FOR
CALCULATING PER-WELL SBF/OBF WASTE VOLUMES
Input Data and Assumptions
โข 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 Ibs/bbl (Ref. 7 and 8)
2. barite = 1,506 Ibs/bbl (Ref. 9)
3. water = 350 Ibs/bbl
4. dry cuttings = 910 Ibs/bbl (Ref. 9)
5. formation oil (as diesel) = 294 Ibs/bbl (Ref. 9)
Retort analysis results, wt./wt.: 10.2% for standard (baseline) solids control; 4.03% for BAT/NSPS
Option 1 level solids control see section VII.4.2.2); 3.82% for BAT/NSPS Option 2 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) x n x [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 (Ibs) = drill cuttings (bbls) x 910 Ibs/bbl (3)
Waste Components in Ibs (algebraic calculation of Ibs of waste components in the given drilled
TW =(RFxTW) + {[RFx(WF/SF)]xTW} + {[RFx(BF/SF)]xTW}+(DFxTW) (4)
(base fluid) + (water) + (barite) + (drill cuttings)
where:
TW = total waste (whole drilling fluid + dry cuttings), in Ibs
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 (Ibs) / DF (6)
Waste Component Amounts Converted from Ibs to bbls
synthetic base fluid (bbls) = [RF x TW (Ibs)] / (280 Ibs/bbl)
water (bbls) = {[RF x (WF/SF)] x TW (Ibs)} / (350 Ibs/bbl)
barite (bbls) = {[RF x (BF/SF)] x TW (Ibs)} / (1,506 Ibs/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-20
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TABLE VII-7
SUMMARY SBF/OBF MODEL WELL WASTE VOLUME ESTIMATES
Waste Component
Shallow Water (1,000ft)
Development
bbls
Ibs
Exploratory
bbls
Ibs
Deep Water (> 1,000 ft)
Development
bbls
Ibs
Exploratory
bbls
Ibs
Waste Volumes Calculated for Baseline Solids Control System (a), 10.2% (wt.) Retention
Synthetic base fluid (or oil base fluid)
Water
Barite
Dry cuttings (includes 7.5% washout)
Cuttings and adherent drilling fluid
generated from SBF/OBF interval
Whole SBF/OBF adhering to cuttings
Formation oil (0.2% of adherent drilling
fluid)
239
81
31
565
917
352
0.7
66,979
28,502
47,028
514,150
656,659
142,509
207
501
170
65
1,184
1,921
737
1.5
140,360
59,728
98,551
1,077,440
1,376,078
298,638
433
362
123
47
855
1,387
532
1.1
101,358
43,131
71,166
778,050
993,705
215,655
313
805
274
105
1,901
3,085
1,184
2.4
225,358
95,897
158,230
1,729,91
2,209,39
6
479,486
696
Waste Volumes Calculated for BAT 1 Add-on Solids Control System @ 4.03% (wt.) Retention
Synthetic base fluid
Water
Barite
Dry cuttings (includes 7.5% washout)
Cuttings and adherent drilling fluid
generated from SBF/OBF interval
Whole SBF/OBF adhering to cuttings
Formation oil (0.2% of adherent drilling
fluid)
81
28
11
565
684
119
0.2
22,664
9,644
15,913
514,150
562,370
48,220
70
170
58
22
1,184
1,433
249
0.5
47,493
20,210
33,346
1,077,440
1,178,489
101,049
147
123
42
16
855
1,035
180
0.4
34,296
14,594
24,080
778,050
851,020
72,970
106
272
93
36
1,901
2,302
401
0.8
76,254
32,448
53,540
1,729,91
1,892,15
2
162,242
235
-------
TABLE VII-7 (Continued)
SUMMARY SBF/OBF MODEL WELL WASTE VOLUME ESTIMATES
Waste Component
Shallow Water (1,000ft)
Development
bbls
Ibs
Exploratory
bbls
Ibs
Deep Water (> 1,000 ft)
Development
bbls
Ibs
Exploratory
bbls
Ibs
Waste Volumes Calculated for BAT 2 Solids Control System @ 3.82% (wt.) Retention
Synthetic base fluid (or oil base fluid)
Water
Barite
Dry cuttings (includes 7.5% washout)
Cuttings and adherent drilling fluid
generated from SBF/OBF interval
Whole SBF/OBF adhering to cuttings
Formation oil (0.2% of adherent drilling
fluid)
74
25
10
551
660
109
635
20,838
8,867
14,631
501,163
545,499
44,336
64
156
53
20
1,154
1,383
229
0.5
43,668
18,582
30,660
1,050,224
1,143,135
92,910
135
113
38
15
833
999
166
0.3
31,534
13,419
22,141
758,397
825,490
67,093
97
250
85
33
1,853
2,221
368
0.7
70,112
29,835
49,227
1,686,21
1,835,38
7
149,174
217
Waste Volumes Calculated for BAT 3 Zero Discharged Wastes (Wastes NOT Discharged)
Synthetic base fluid
Water
Barite
Dry cuttings (includes 7.5% washout)
Cuttings and adherent drilling fluid
generated from SBF/OBF interval
Whole SBF/OBF adhering to cuttings
Formation oil (0.2% of adherent drilling
fluid)
6.4
2.2
0.8
14
24
10
0.0
1,805
768
1,267
13,030
16,871
3,841
6
14
4.6
1.8
30
50
20
0.0
3,783
1,610
2,656
27,306
35,355
8,049
12
9.8
3.3
1.3
22
36
14
0.0
2,732
1,162
1,918
19,718
25,531
5,812
8
22
7.4
2.8
48
80
32
0.1
6,074
2,585
4,265
43,842
56,765
12,923
19
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4.2.5 WBF Waste Volumes and Characteristics
For the final rule, EPA has included an analysis of the projected use of WBF under the Baseline,
BAT/NSPS discharge options 1 and 2, and the (SBF) zero discharge option that were considered for this
rule. This WBF analysis included projected well counts, discharge loadings, and onsite/onshore zero
discharge requirements for WBF wells projected to fail the static sheen and/or SPP toxicity limitations. The
source of data for this analysis is the Development Document for the Effluent Limitations and Guidelines
for the Offshore Subcategory (EPA 821-R-93-003). The detailed calculations for this WBF analysis are
provided in Appendix VIII-2 of this document.
The general approach used in the WBF analysis for the final SBF rule is as follows: waste volume
and/or pollutant loading data on use of OBFs and WBFs presented in the Offshore Development Document
were expressed on a "per bbl," "per well," or a "per day" basis. Data from the Offshore rulemaking record
included: (1) WBF composition; (2) waste volumes for WBFs, OBFs, and associated cuttings; (3) the
frequency of mineral oil use in WBF operations; and (4) the expected permit limitation failure rates
(primarily for toxicity) on mineral oil fluids resulting in the requirement to haul or inject these wastes).
These data then were applied to the current, revised well count projections and/or projected waste volumes
to estimate discharge option loadings and the amount of OBFs, WBFs, and associated cuttings that require
zero discharge under existing regulations (e.g., OBFs containing diesel oil, WBFs that fail the SPP toxicity
test).
The first exercise in this analysis was to develop the allocation of offshore wells into various types
based on the assumptions used in the Offshore Development Document. These assumptions are provided
in Table XI-10 of the Offshore Development Document and specify, on a regional basis, the percentages of
shallow wells versus deep wells as well as wells with mineral oil added as a lubricant, as a spotting fluid, or
as both. (Cautionary note: the Offshore Development Document does not use the terms "shallow" and
"deep" with reference to the water depth in which these wells are drilled, i.e., as these terms are used in this
SBF rule, which classifies wells as "shallow water" wells or "deep water" wells. The Offshore
Development Document, in contrast, uses these terms with reference to the target depth of the well itself,
i.e., "shallow" wells ranging from 7,607 feet to 10,633 feet in depth and "deep" wells ranging from 10,082
feet to 13,037 feet in depth.)
In summary these assumptions were:
Shallow wells respectively accounted for 51%, 58% and 41% of all wells drilled in Gulf of Mexico,
California, and Alaska.
VII-23
-------
โข Deep wells respectively accounted for 49%, 42%, and 59% of all wells drilled in Gulf of Mexico,
California, and Alaska.
โข 15% of all deep wells used OBF and were subject to a zero discharge limitation.
12% of all WBF wells used mineral oil as a lubricant (78% do not).
22% of WBF wells used mineral oil as a spotting fluid.
The projected sheen and/or toxicity limitation failure rates for WBF wells were: no lube/no spot =
1%; lube or spot = 33%; lube plus spot = 56%.
Based on these assumptions, the percentages of WBF wells projected to pass or fail the sheen and toxicity
limitations were initially developed from the data in the Offshore Development Document for application to
the well counts developed for this SBF rule in order to project zero discharge requirements and loadings of
WBF wells under the various regulatory options considered for the final SBF rule. The Agency questioned
the applicability and reliability of these assumptions to current operations, and concluded this analysis yields
a conservative (maximum upper bound) failure rate estimate.
The results of the maximum failure rate analysis are provided in Table VII-8. For the final rule,
EPA decided not to rely on this failure rate estimate in its cost analysis methodology. EPA instead used the
maximum lower bound estimate of 0% failure in its cost analysis. Because one cost element derived from
this failure rate estimate is the cost savings from WBF wells projected to fail their limits that convert to SBF
wells, using a 0% failure rate effectively eliminates this cost savings to industry and presents a more
conservative aspect to the cost methodology. For the final rule, a sensitivity analysis that includes the
maximum upper bound failure rate estimate was performed as an ancillary analysis (see Ref 71).
VII-24
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TABLE VII-8
ESTIMATED OFFSHORE WBF STATIC SHEEN TEST/TOXICITY LIMITATION
FAILURE RATES USED IN MAXIMUM FAILURE RATE ANALYSISa
Well Location/Type
Gulf of Mexico
Shallow
Deep (including 15% OBF)
Deep (excluding 15% OBF)
California
Shallow
Deep (including 15% OBF)
Deep (excluding 15% OBF)
Alaska
Shallow
Deep (including 15% OBF)
Deep (excluding 15% OBF)
Projected Percent of Total Wells
Passing
Sheen/Toxicity
Limitation b
45.1%
36.8%
51.3%
31.5%
36.2%
44.3%
Failing
Sheen/Toxicity
Limitation c
5.94%
12.2%
4.85%
6.75%
10.5%
4.16%
4.77%
14.7%
5.84%
With Lube, Spot,
or Lube+Spot
That Discharge d
10.4%
8.50%
11.8%
7.28%
8.37%
10.2%
SeeRef. 71.
b Used to project discharge loadings and costs (See Ref. 71).
0 Used to project zero discharge quantities and costs (See Ref. 71).
d Used to project oil and grease loadings from added mineral oil (See Ref. 71).
Source: Offshore Development Document (Ref. 10)
The WBF and WBF-cuttings waste volumes and their composition were taken from the Offshore
Development Document (see Tables XI-3, XI-5, XI-6, XI-7, XI-9; ODD Section XI.3.4). The waste
volumes of the WBF and associated cuttings as determined in the ODD and used in the WBF analysis for
the SBF rule are as follows:
Gulf of Mexico
California
Alaska
Shallow
Deep
Shallow
Deep
Shallow
Deep
Drilling Fluids
(bbl)
6,938
9,752
5,939
6,777
6,963
9,458
Cuttings
(bbl)
1,475
2,458
1,242
1,437
1,480
2,413
VII-25
-------
The analysis for WBF includes a projections of conventional pollutants from cuttings (TSS from
barite or cuttings, plus oil and grease from cuttings from wells in which mineral oil was used as a lubricant or
spotting fluid), conventional pollutants from discharged WBF (TSS from barite in the WBF plus oil and
grease from wells in which mineral oil as used as a lubricant or spotting fluid), and toxic plus
nonconventional pollutants from discharged WBF (from both WBF components as well as from mineral oil
added as a lubricant or spotting fluid).
For cuttings, a TSS value of 551 Ibs/bbl was used in the WBF analysis for the final SBF rule. The
oil and grease contribution from mineral oil was calculated based on an assumed 5% (v/v) value of adherent
drilling fluid on WBF cuttings and a mineral oil content (as a lubricant or for spotting) of 9 Ibs/bbl WBF
(applied to the projected number of WBF wells using mineral oil as a lubricant or spotting fluid).
For the discharged WBF, a TSS value of 131 Ibs/bbl was used. The oil and grease contribution
from mineral oil was the same as that used for cuttings: 9 Ibs/bbl WBF. To calculate contributions of toxic
and nonconventional pollutants, a value of 37.7 Ibs toxics + nonconventionals/bbl was used. The
contribution of toxics and nonconventionals from mineral oil was based on a value of 0.324 Ibs toxics +
nonconventionals/bbl mineral oil.
To assess the overall reliability of the WBF fluids and cuttings discharge volumes, and their
comparability to the current discharge volumes used in this SBF rule, a comparison was conducted of
calculated WBF-cuttings discharge volumes to current SBF-cuttings discharge volumes for each of the four
model well types specified in the rule. This analysis assumed that WBF was used over the same interval as
the SBF analysis. To estimate this volume of waste requiring disposal, a weighted average barrel-per-day
estimate of WBF drilling fluid and cuttings was applied to the number of days of the SBF interval assumed
for the four model well types used in this final rule. The total shallow and deep well volumes of drilling
fluid and cuttings in the Gulf of Mexico (6,938 bbl and 9,752 bbl, respectively of drilling fluids; 1,475 bbl
and 2,458 bbl for cuttings) were averaged over the 20-day drilling program assumed in the Offshore
Development Document.
When the average daily discharges of shallow and deep wells (respectively 351 and 494 bbl
fluids/day; 74 and 123 bbl cuttings/day) were combined with the number of wells of each type projected for
this SBF rule (347 shallow; 488 deep), a weighted average discharge of 415 bbl WBF/day and 96 bbl WBF-
cuttings/day resulted. The estimated days to fill and haul SBF wastes (10.4, 23.3, 7.6, and 13.6 days,
respectively for DWD, DWE, SWD, and SWE well types) were converted to the number of days to "fill
and haul" WBF wastes (i.e., because of the 50% reduction in drilling time for SBFs compared to OBFs,
VII-26
-------
these day-estimates were doubled) to estimate the duration of WBF drilling activity. Combining these day-
estimates with average daily WBF-cuttings estimates, projected waste volumes of 1,999 bbl; 4,468 bbl;
1,461 bbl; and 2,611 bbl resulted for DWD, DWE, SWD, and SWE well types.
These volumes were compared to SBF volume estimates, which for DWD, DWE, SWD, and SWE
well types respectively were 1,387 bbl; 3,085 bbl; 917 bbl; and 1,921 bbl. Assuming a 7.5% washout for
SBF wells and a 45% washout for WBF wells, these SBF waste volumes were converted to WBF-
equivalents (i.e., [SBF volumes/1.075] x 1.45) resulting in 1,871 bbl; 4,161 bbl; 1,237 bbl; and 2,591 bbl
for DWD, DWE, SWD, and SWE well types. These SBF volume-based estimates ranged from 85% to
99% of the WBF estimates that are based on data in the Offshore Development Document. The
comparability of these two waste volume estimates provides substantial confirmation of the validity and
appropriateness of analyses combining waste volume estimates based on two different sources of data.
5. 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:
โข 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
The current BPT and BCT limitation of no free oil for drilling fluid wastes was first published on
April 13, 1979 (44 FR 22069), and at that time, was based on drilling product substitution or the use of
more environmentally benign products, combined with onshore disposal as 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 using the current shale shaker technology by varying the SBF formulation and treatment.
VII-27
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5.2 Product Substitution: SBF Base Fluid Selection
EPA proposed 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 anticipated that these limitations would be
achieved by product substitution of the base fluid. For the final rule EPA is establishing BAT limitations
and NSPS requiring synthetic materials that form the base fluid of SBFs to meet limitations and standards
on PAH content, sediment toxicity, and biodegradation.
The technology basis for meeting these limitations and standards is product substitution, or zero
discharge, based on land disposal or cuttings re-injection, if these base fluid limitations are not met. The
regulated toxic, conventional, and non-conventional pollutant parameters are identified below. A large range
of synthetic, oleaginous, and water miscible materials are available for use as base fluids. These stock
limitations on the base fluid are intended to encourage product substitution reflecting best available
technology and best available demonstrated technology wherein only those synthetic materials and other
base fluids which minimize potential toxic pollutant (PAH) loadings and toxicity and which maximize
biodegradation may be discharged. The following sections discuss the technical basis for the limitations on
stock base fluids.
5.2.1 Currently Available Synthetic and Non-Aqueous Base Fluids
As SBFs have developed over the past several years, the industry has come to use mainly a few
primary base fluids that represent virtually all the SBFs currently used in oil and gas extraction industry.
These include the internal olefms, linear alpha olefins, poly alpha olefins, paraffmic oils, C12-C14 vegetable
esters of 2-hexanol and palm kernel oil, and "low viscosity" C8 esters. EPA has collected data and costs on
these SBFs to develop the effluent limitations for the final rule. Internal olefins (IO) are a series of isomeric
forms of C16 and C18 alkenes; linear alpha olefins (LAO) are a series of isomeric forms of C14 and C16
monoenes; poly alpha olefins (PAO) refers to a mixture primarily of a hydrogenated decene dimer C20H62
(95%) with lesser amounts of C30H62 (4.8%) and C10H22 (0.2%); vegetable esters are monoesters of 2-
ethylhexanol and saturated fatty acids with chain lengths in the range C8 - C16; and "low viscosity" esters are
esters of natural or synthetic C8 fatty acids and alcohols. EPA also has data on other SBF base fluids, such
as enhanced mineral oil, paraffmic oils (i.e., saturated hydrocarbons or "alkanes"), and the traditional OBF
base fluids, mineral oil, and diesel oil.
VII-28
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The stock base fluid limitations and standards and discharge limitations and standards presented
below are based on currently available base fluids that can be, and are, used in a wide variety of drilling
situations. The promulgated limitations would be achievable through product substitution. Also, the very
small number of wells that do not meet the limitations could comply with the rule through zero discharge.
EPA anticipates that base fluids meeting all requirements would include vegetable esters, low viscosity
esters, and internal olefms.
As stated in the April 2000 NODA, EPA considered basing the sediment toxicity and biodegradation
stock limitations and standards on vegetable esters instead of the proposed C16-C18IO. EPA has also
considered a sub-categorization of the final rule, for situations when vegetable esters are not practical and
C16-C18 lOs could be used instead. EPA considered these options due to the potential for better
environmental performance of vegetable ester-based drilling fluids. However, EPA rejected the discharge
option of basing stock limitations and standards on vegetable esters only because of several technical
limitations that preclude the use of demonstrated esters in all areas covered by this rule. These technical
limitations include: (1) high viscosity compared with typical lOs at all temperature, with an increasing
difference as temperature decreases, leading to lower rates of penetration in wells and greater probability of
losses due to higher equivalent circulating densities; (2) high gel strength in risers that develops when a
vegetable ester-SBF is not circulated; (3) a high temperature stability limit ranging from about 225 ยฐF to
perhaps 320 ยฐF - the exact value depends on the detailed chemistry of the vegetable ester (i.e., the acid, the
alcohol) and the drilling fluid chemistry; (4) reduction of the thermal stability limit by contact with highly
basic materials (e.g., lime, green cement) at elevated temperatures (i.e., a hydrolysis reaction that is
impossible with other NAF); and (5) less tolerance of the muds to contamination by seawater, cement, and
drill solids than is observed for IO-SBFs.64'65'66' 67>68'69 EPA also rejected the option of sub-categorizing the
use of esters. EPA could not establish a "bright line" rationale to define situations where only esters should
be the benchmark fluid. EPA considered many of the engineering factors used for selection of a drilling
fluid (e.g., rig size and equipment; formation characteristics; water depth and environment; lubricity,
rheological, and thixotropic requirements) and determined that no sub-categorization was possible because
the Agency could not specify the combination of factors where esters would meet all technical requirements.
EPA also considered basing sediment toxicity and biodegradation stock limitations and standards on
low viscosity esters. However, these esters have not been well demonstrated by full scale use in drilling
operations. EPA has received information on only one well section drilled with low viscosity esters. The
performance of this low viscosity ester well section was compared to that of another well section in the
same location where C16-C18 lOs were used and showed that the low viscosity ester had: (1) comparable or
better equivalent circulating densities (i.e., acceptable fluid properties); and (2) faster ROP through better
VII-29
-------
hole cleaning and higher lubricity (i.e., required fewer days to drill to total depth, leading to less NWQI and
overall drilling costs). Low viscosity esters are relatively new base fluids and have only recently been
available to the market.
Comments to the April 2000 NODA state that laboratory-scale evaluations, which were designed to
simulate Gulf of Mexico conditions to which a fluid may be exposed, indicated that low viscosity esters have
several beneficial technical properties:
โข They demonstrate similar or better viscosity than C16-C18 lOs.
โข They can be used to formulate stable low viscosity ester-SBFs up to 300 ยฐF.
โข They can be used to formulate low viscosity ester-SBFs to 16.0+ Ibs/gal mud weight.
They reduce the volume of base fluid discharged because the oil/water ratios can be reduced to
70/30.
They have a high tolerance to drilled solids.
They make it easier to break circulation flat gels, minimizing initial circulation pressures and
subsequent risk of fracture.
โข They have a high tolerance to seawater contamination.
โข Their rheological properties can be adjusted by use of additives to suit specific conditions.70
Despite the results from the laboratory evaluation and the one well drilling section, EPA does not
believe it has enough information to conclude that low viscosity esters can be used in all (or nearly all)
drilling conditions on the OCS (e.g., differing formations, water depths, and temperatures). Therefore, EPA
rejected the option of basing sediment toxicity and biodegradation stock limitations and standards on low
viscosity esters only. However, EPA is sufficiently satisfied that esters provide better environmental
performance (e.g., sediment toxicity, biodegradation) and are available for use in a number of drilling
operations. Consequently, EPA is promulgating higher retention on cuttings discharge limitations to
encourage operators to use esters whenever possible.
5.2.2 PAH Content of Base Fluids
EPA proposed 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 EPA is concerned
about the PAH content of base fluids because PAHs are comprised of toxic priority pollutants. Producers of
several SBF base fluids have reported to EPA that their base fluids are free of PAHs,27 including: linear
alpha olefins, vegetable esters, certain enhanced mineral oils, synthetic paraffins, certain non-synthetic
VII-30
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paraffins, and others. In contrast, diesel oil typically contains 5% to 10% PAH; mineral oil typically
contains about 0.35% PAH.27 PAHs typically found in diesel and mineral oils include toxic priority
pollutants (e.g., fluorene, naphthalene, phenanthrene, and others) and nonconventional pollutants (e.g.,
alkylated benzenes and biphenyls).
For the final rule, EPA has determined that a PAH BAT limitation and NSPS are important
components of the final regulation because they control the discharge of priority and nonconventional
pollutants such as naphthalene, phenanthrene, alkylated naphthalenes, and biphenyls. For the final rule, the
limitation of PAH content for the Gulf of Mexico and Offshore California is a weight-to-weight ratio of PAH
(as phenanthrene) to the stock base fluid. The PAH weight ratio limit is 0.001 percent, or 10 parts per
million (ppm). This limitation is based on the availability of base fluids that are free of PAHs and the
detection of the PAHs by EPA Method 1654A, which refers to a method for measuring the "PAH Content
of Oil by High Performance Liquid Chromatography with a UV Detector" published in "Methods for the
Determination of Diesel, Mineral and Crude Oils in Offshore Oil and Gas Industry Discharges" [EPA-821-
R-92-008], available from National Technical Information Service at: (703) 605-6000. As originally
proposed in February 1999 (64 FR 5503), EPA is promulgating the use of the EPA Method 1654A for
compliance with this PAH content BAT limitations and NSPS.
5.2.3 Sediment Toxicity of Base Fluids
EPA proposed 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 that time, the only base fluids that would attain this limitation were lOs
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. Among the synthetic and other oleaginous base fluids some are more toxic than others (see 65 FR
21550).71 Still et al. reported the following 10-day LC50 results, expressed as mg base fluid/Kg dry sediment
for diesel oil, mineral oil, an IO, and a PAO: diesel LC50 = 850 mg/kg, enhanced mineral oil LC50 = 251
mg/kg, internal olefm LC50 = 2,944 mg/kg, and poly alpha olefm LC50 = 9,636 mg/kg. Similar results have
been reported by Hood et al.2S Candler et al. performed the 10-day sediment toxicity test with the
amphipod Ampelisca abdita and again obtained very similar results as follows: diesel LC50 = 879 mg/kg,
VII-31
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enhanced mineral oil LC50 = 557 mg/kg, internal olefm LC50 = 3,121 mg/kg, and PAO LC50 = 10,680
mg/kg.29
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 olefm.
Researchers in the United Kingdom and Norway investigating effects in the North Sea have
conducted sediment toxicity tests on other organisms, namely Corophium volutator wdAbra alba32
Similar trends were seen in the measured toxicity, with vegetable ester having less sediment toxicity than
PAO and IO.
While the PAOs were found to have the lowest toxicity of the measured base fluids (excluding
vegetable esters), at proposal EPA did not base the toxicity limitation on PAOs because they biodegrade
much more slowly and so are unlikely to pass the biodegradation limitation (see below, Section 5.2.4). EPA
proposed to generate and gather additional data comparing the toxicity of the various base fluids. If
vegetable esters were found to have significantly reduced toxicity compared to the other base fluids, EPA
reserved the option to base the toxicity limitation on vegetable esters. EPA noted its concerns, however,
over the technical performance and possible non-water quality implications of using vegetable esters as the
only available technology that would meet the stock base fluid limitations, as discussed below under
biodegradation.
For this final rule, EPA is regulating the sediment toxicity for base fluids as a non-conventional
pollutant parameter and as an indicator for toxic pollutants of base fluids. 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. The selected discharge option (BAT/NSPS Option 2) includes a base fluid
sediment toxicity stock limitation, as measured by the 10-day sediment toxicity test (ASTM E1367-92) using
either natural sediment or formulated sediment and Leptocheirus plumulosus as the test organism. The
SBF rulemaking record indicates that drilling fluids that meet the stock base fluid sediment toxicity limitation
and standard (e.g., internal olefins, esters) will meet all drilling requirements in the waters to which this rule
applies.
For this final rule, EPA is promulgating a sediment toxicity stock base fluid limitation that only
allows the discharge of SBF-cuttings using SBF base fluids that have toxicity less than or equal to C16-C18
VII-32
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lOs. Alternatively, this limitation can be expressed as a "sediment toxicity ratio," defined as the 10-day
LC50 of C16 - C18 lOs divided by the 10-day LC50 of stock base fluid being tested. EPA is promulgating a
sediment toxicity ratio of less than or equal to 1.0 for the final rule. Compliance with this limitation is
determined by the 10-day Leptocheirus plumulosus sediment toxicity test [i.e., ASTM E1367-92: "Standard
Guide for Conducting 10-day Static Sediment Toxicity Tests With Marine and Estuarine Amphipods"
(incorporated by reference and available from ASTM, 100 Bar Harbor Drive, West Conshohocken, PA
19428), supplemented with the preparation procedure specified in Appendix 3 of Subpart A of 40 CFR
435]. As originally proposed in February 1999 (64 FR 5503) and re-stated in April 2000 (65 FR 21549),
EPA is promulgating the use of the ASTM E1367-92 method for compliance with this sediment toxicity
BAT limitation and NSPS.
EPA finds this limit to be technically available because information in the rulemaking record
supports that vegetable esters, low viscosity esters, and internal olefms. together have performance
characteristics enabling them to be used in a wide variety of drilling situations offshore. Marketing data given
to the EPA shows that, at least for certain of the major drilling fluid suppliers, internal olefm SBFs are
currently the most popular SBFs used in the Gulf of Mexico. Since the February 1999 Proposal, EPA and
other researchers conducted numerous 10-day and 96-hour L. plumulosus sediment toxicity tests on various
SBF base fluids with natural and formulated sediments. EPA anticipates that the base fluids meeting this
limitation include vegetable esters, low viscosity esters, internal olefms, and some PAOs (see 65 FR
21550).71
EPA's L. plumulosus sediment toxicity tests confirm that although numeric toxicity results can vary
substantially from test to test, the relative toxicities of the base fluids remain consistent. These tests have
found that the order of sediment toxicity, from least toxic to most toxic, is consistently as follows: esters >
lOs > LAOs > paraffin > mineral oil > diesel. Therefore, variability in numeric LC50 values would not
affect an assessment of a test base fluid's sediment toxicity against the sediment toxicity ratio limitation
because the ratio is dependent on relative toxicities.
Initially, EPA conducted sediment toxicity tests on whole base fluids. In these initial tests EPA used
two test durations (i.e., 10-day and 96-hour) and natural sediment collected from Galveston Bay, Texas.
The results are presented in the Table VII-9.
VII-33
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TABLE VII-9
EPA DETERMINATION OF SEDIMENT TOXICITY FOR BASE FLUIDS
Drilling Base Fluid
-4โ ยป
tยซ
(L>
H
tH
o
ffi
VO
ON
-4โ ยป
tยซ
(L)
H
>^
a
Q
o
IO
LAO
Ester
Mineral Oil
Paraffin
IO
LAO
Ester
Mineral Oil
Paraffin
LC50 (mg/Kg)
>8000a
2921
7686
436
2263
2530
1208
4275
176
1151
95% Confidence Interval
NA
2260 - 3775
7158 - 8253
391 -485
1936 - 2644
2225 - 2876
1089- 1339
3921 - 4662
163 - 190
1038 - 1276
a Test result fell outside of the test concentration range.
In subsequent tests, EPA evaluated the sediment toxicity of whole mud formulations of base fluids.
Again, EPA conducted both 10-day and 96-hour test using natural sediment collected from Galveston Bay,
Texas. The results (see Table VII-10) show that whole mud formulations of base fluids, when using the 96-
hour test duration, exhibit the same relative sediment toxicities as pure base fluids. EPA is specifying the
use of the 96-hour test duration for point-of-discharge monitoring in order to allow operators to continue
drilling operations while the sediment toxicity test is being conducted on the discharge drilling fluid.
VII-34
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TABLE VII-10
EPA DETERMINATION OF SEDIMENT TOXICITY FOR WHOLE MUD FORMULATIONS
WITH SYNTHETIC BASE FLUID
Drilling Base Fluid
โข&
(L>
H
8
a
VO
ON
โข&
(L)
H
>^
ยซs
Q
o
IO
LAO
Ester
Diesel
IO
LAO
Ester
Diesel
LC50 (mg/Kg)
>24a
7.58
39.4
1.15
3.28
3.09
3.19
0.46
95% Confidence Interval
NA
4.54- 12.7
33.6-47.6
1.09- 1.21
2.78 - 4.97
1.82-5.26
2.96 - 3.44
0.39-0.55
a Test result fell outside of the test concentration range.
Parallel studies conducted by Industry analytical workgroups also show that the relative sediment
toxicities of base fluids are consistent. Table VII-11 presents a summary of industry results submitted to
EPA.
VII-35
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TABLE VII-11
INDUSTRY SEDIMENT TOXICITY RESULTS
Drilling Base Fluid
LC50 (mg/Kg)
95% Confidence Interval
Baroid-Generated Data:
โข&
H
8
a
VO
ON
โข&
(L)
H
>>
ยซs
Q
o
Diesel
IO
LAO
Ester
Ester (Low viscosity)
Diesel
IO
LAO
Ester
Ester (Low viscosity)
453
876
490
>20000
>20000
230
564
338
> 10000
2447
416-493
442 - 1663
291 - 924
NA
NA
209-251
447 - 639
294 - 378
NA
2197-2701
M-I Driling Fluid-Generated Data:
โข&
(L)
H
8
a
VO
ON
Diesel
IO
566
3686
510-629
2890 - 4893
EPA has selected the C16-C18 IO as the basis for the sediment toxicity ratio limitation and standard
instead of the vegetable ester or low viscosity ester for two reasons: (1) EPA does not believe that vegetable
esters can be used in all drilling situations; (2) EPA has insufficient field testing information demonstrating
that low viscosity esters can be used in all drilling situations. Consequently, operators may not be
encouraged to switch from OBFs or WBFs to SBF if only vegetable ester- or low viscosity ester-SBFs could
be discharged. As previously stated, EPA is promoting the appropriate conversion from OBF- and WBF-
drilling to SBF-drilling to encourage the reduction of pollutant loadings and NWQIs. Due to demonstrated
and potential technical limitations of vegetable ester or low viscosity esters, EPA estimates that the pollutant
loadings and NWQIs associate with establishing vegetable esters or low viscosity esters as the basis for stock
limitation would be comparable to the pollutant loadings and NWQIs associated with a zero discharge option
for all SBF-cuttings. EPA finds these increases in pollutant loadings and NWQIs unacceptable.
VII-36
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5.2.4 Biodegradation Rate of Base Fluids
EPA proposed a limitation of biodegradation rate for the base fluid (as determined by the solid
phase test),33 equal to or faster than the rate of a C16-C18IO. The proposed method was provided in
Appendix 4 to Subpart A of the proposed amendments to 40 CFR Part 435. With this proposed limitation,
the base fluids currently available for use include vegetable ester, LAOs, lOs, and possibly certain linear
paraffins, EPA further concluded that applying the biodegradation rate, PAH content, and sediment toxicity
limitations on stock base fluid, available data indicated that lOs 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 chose to pursue this
approach, it expected that it may need to revise this numerical limitation as additional test results were
generated and evaluated.
Similar to SBF sediment toxicity, in order to minimize the effect of test variability, the final
limitations and standards are based on comparative testing rather than numerical limitations. Therefore, if
SBFs based on fluids other than lOs and vegetable esters were to be discharged with drill cuttings, data
showing the biodegradation of both the base fluid and the IO standard, generated in the same series of tests,
would be required. EPA preferred this approach rather than a numerical limitation at proposal because of
the limited data available to EPA upon which to base a numerical limitation. EPA considered this approach
to be an interim solution to this data sufficiency problem at the time of proposal because it still provided a
limitation based on the performance of available technologies.
Rates of biodegradation for synthetic and mineral oil base fluids had been determined by both a
solid phase and a simulated seabed test; relative rates of biodegradation between these two tests are in
agreement.34 These tests have found that the order of degradation, from fastest to slowest, is as follows:
vegetable esters and low viscosity esters > LAOs > lOs > linear paraffin > mineral oil > PAOs.
At proposal, EPA had selected lOs 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. This property makes vegetable ester SBFs
more difficult to pump, and may render them impractical for deep water drilling. The cooler temperatures
in deep water drilling further increase viscosity, and the long drill string at this higher viscosity requires
higher pump pressures to circulate the SBF. Cost also was recognized as a factor in encouraging the use of
VII-37
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SBFs in place of OBFs. Industry representatives had told EPA that vegetable ester SBF costs about twice
as much as an IO SBF.24 EPA believed that if the lower cost IO SBFs could be discharged, more wells
currently drilled with OBF would be encouraged to convert to SBF than if only the more expensive
vegetable ester SBFs could be discharged. This OBF-to-SBF conversion is preferable to improve non-water
quality environmental impacts. If continued research showed that vegetable esters had significantly reduced
toxicity in addition to their faster rate of biodegradation, EPA reserved the option to consider more stringent
stock base fluid limitations to favor the use of vegetable ester SBFs for the final rule.
For the final rule, EPA is regulating the biodegradation in base fluids as an indicator of the extent, in
level and duration, of the toxic effect of toxic pollutants and nonconventional pollutants present in base
fluids (e.g., enhanced mineral oils, lOs, LAOs, PAOs, paraffinic oils, C12-C14 vegetable esters of 2-hexanol
and palm kernel oil, "low viscosity" C8 esters, and other oleaginous materials). Based on results from
seabed surveys at sites where various base fluids have been discharged with drill cuttings, EPA believes that
the results from the three biodegradation tests used during the rulemaking (e.g., solid phase test, anaerobic
closed bottle biodegradation test, respirometry biodegradation test) are indicative of the relative rates of
biodegradation in the marine environment. EPA puts strong emphasis on the use of the anaerobic
biodegradation (closed bottle) test based on the deep water and cuttings piles characteristics which promote
anaerobic rather than aerobic degradation. In addition, EPA thinks the biodegradation parameter correlates
strongly with the rate of recovery of the seabed where OBF- and SBF-cuttings have been discharged. The
various base fluids vary widely in biodegradation rates, as measured by the three biodegradation methods.
However, the relative ranking of the base fluids under consideration remain relatively similar across all three
biodegradation tests investigated under this rulemaking.
Since proposal, EPA has evaluated four sets of biodegradation data. EPA generated one data set
using the solid phase test, and industry generated one data set for each of the three tests that were noticed in
the proposal and NODA (i.e., solid phase test, anaerobic closed bottle test, and respirometry test for
biodegradation).
EPA conducted its solid phase test over 112 days on 6 base fluids (ester, IO, LAO, mineral oil,
PAO, and paraffin) at 3 initial spike concentrations (1000 mg/Kg, 2000 mg/Kg, and 5000 mg/Kg). The
results (see Tables VII-12 through 14 and Figures VII-1 through VII-3) of this test support the historically
observed rankings of the biodegradation rates for these test fluids (i.e., ester > LAO > IO > paraffin >
mineral oil > PAO).
VII-38
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TABLE VII-12
EPA SOLID PHASE TEST (1000 mg/Kg)
Elapsed Time
of Test
Day 0
Day 14
Day 28
Day 56
Day 84
Day 112
Concentration (mg/Kg)
Ester
751
424
265
152
144
11
LAO
946
904
799
833
487
314
IO
1005
879
820
739
529
451
Paraffin
1045
828
846
981
726
624
Mineral Oil
1161
907
892
997
835
785
PAO
890
917
903
1065
928
948
1500
FIGURE VII-1
Low-Range Spike Concentrations
(1000mg/Kg)
Days
VII-39
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TABLE VII-13
EPA SOLID PHASE TEST (2000 mg/Kg)
Elapsed Time
of Test
Day 0
Day 14
Day 28
Day 56
Day 84
Day 1 12
Concentration (mg/Kg)
Ester
1352
887
691
565
231
152
LAO
1949
1512
1646
1676
1199
949
IO
2027
1831
1732
1578
1388
1040
Paraffin
2060
1670
1754
2044
1551
1487
Mineral Oil
2165
1855
1799
1943
1864
1733
PAO
1964
1796
1786
2039
1899
1865
FIGURE VII-2
Mid-Range Spike Concentration
(2000mg/Kg)
2500
VII-40
-------
TABLE VII-14
EPA SOLID PHASE TEST (5000 mg/Kg)
Elapsed Time
of Test
Day 0
Day 14
Day 28
Day 56
Day 84
Day 112
Concentration (mg/Kg)
Ester
3742
2331
2139
1619
1241
712
LAO
4717
4277
4050
4474
3302
3209
IO
4620
4421
4075
3649
3450
3486
Paraffin
4864
4199
4190
4959
4132
3933
Mineral Oil
5291
4255
4396
4898
4673
4457
PAO
5211
4916
4761
5318
4970
4840
FIGURE VII-3
High-Range Spike Concentrations
(5000mg/Kg)
Ester
VII-41
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The industry data, however, did not reproduce the historical results associated with the solid phase
test. Instead, the industry data indicated a rapid disappearance of all fluids. Based on an analysis of their
data and followup investigation, EPA and the industry workgroup determined that industry's results (see
Figure VII-4) were affected by physical loss of the base fluids rather than loss through biodegradation. The
solid phase test's susceptibility to physical loss of fluid into the test environment is one reason EPA chose to
specify the use of the anaerobic closed bottle test in this rule.
FIGURE VII-4
INDUSTRY SOLID PHASE TEST RESULTS
Kinetics of Fluid Loss 2000 ppm
E
Q.
a.
c
o
?
5
โข+โขยป
0)
o
c
o
o
0
20
40
60
Days
Rapeseed
Hexadecene
Petrofree
Squalane
Diesel
Biobase 100
C1618IO
Amodrill 1000
Biobase 250
The industry also submitted data (see Table VII-15 and Figure VII-5) to show that the relative
rankings of biodegradation rates as determined by the anaerobic closed bottle test follows the historical
trend. In addition, the closed bottle test offers a clear advantage over the other two biodegradation tests in
terms of cost per analysis and ease of use.
VII-42
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TABLE VII-15
INDUSTRY MARINE ANAEROBIC CLOSED BOTTLE BIODEGRADATION TEST RESULTS
Elapsed Time
of Test
Day 0
Day 5
Day 25
Day 33
Day 67
Day 77
Day 95
Day 113
Day 132
Day 155
Day 194
Day 231
Day 271
Cumulative Gas Production Over Time (ml)
Olive Oil
0.00
9.29
50.00
103.50
150.41
152.50
160.61
162.88
164.78
169.18
167.74
171.57
175.58
C16-C18 10
0.00
2.77
8.59
12.50
18.38
22.21
24.60
29.71
39.74
59.00
92.36
104.50
119.88
Cl4-C16
LAO
0.00
3.67
10.00
15.00
22.15
26.46
32.74
42.91
55.50
88.16
114.50
138.22
151.20
Synthetic
Paraffin
0.00
3.32
7.05
10.00
13.67
15.83
18.16
21.14
23.17
27.19
25.82
29.49
33.33
QsO
0.00
3.32
6.62
8.00
10.45
12.42
12.18
12.80
13.38
15.42
13.97
17.47
21.63
Blank
Control
0.00
3.88
5.99
8.30
11.12
12.28
12.98
13.30
14.01
16.07
14.57
17.63
22.11
VII-43
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FIGURE VII-5
INDUSTRY ANAEROBIC CLOSED BOTTLE TEST RESULTS
Normal Sediment Total Gas
Olive Oil
Squalane
Hexadecene
Ethyl Oleate
Petrofree
Biobase250
C1618
'
0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150
Time
Finally, industry-submitted data on the respirometry test for biodegradation also show that the
respirometry test ranks the relative biodegradation rates of base fluids according to the historical data (see
Table VII-16 and Figure VII-6). While the respirometry test shows promise, it is only in the early stages of
development, and its procedures have not been finalized. Therefore, EPA is not specifying the use of this
test for monitoring compliance with the biodegradation limit.
VII-44
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TABLE VII-16
INDUSTRY RESPIROMETRY TEST RESULTS
Blank
Squalane
Rapeseed Oil
Diesel
LAO
IO
Ester
CO2 % Deg
0%
3%
75%
14.6%
45.2%
41.5%
72.7%
O2 % Deg
0%
-0.8%
84.8%
4.4%
37. 1%
44%
77.4%
FIGURE VII-6
INDUSTRY RESPIROMETRY TEST RESULTS
% Biodegradation based on O2
90
C16/C18 IO 1000
C16/C18 IO5000
Iโ ester
ester 5000
C14/C16/C18(LAO) 1000.17
#2dieseloil*1001.239
#2 diesel oil 5000
Rapeseed oil 999.83
Squalene * 999.83
time (hrs)
As originally proposed in February 1999 (64 FR 5504) and re-stated in April 2000 (65 FR 21550),
for the final rule EPA is promulgating a BAT limitation and NSPS to control the minimum amount of
biodegradation of base fluid. The selected discharge option (BAT/NSPS Option 2) includes a base fluid
VII-45
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biodegradation stock limitation, as measured by the marine anaerobic closed bottle biodegradation test (i.e.,
ISO 11734).
The biodegradation stock base fluid limitation only allows the discharge of SBF-cuttings using SBF
base fluids that degrade as fast or greater than C16-C18 lOs. Alternatively, this limitation could be expressed
in terms of a "biodegradation rate ratio" that is defined as the percent degradation at 275 days of C16-C18
lOs divided by the percent degradation of stock base fluid being tested. EPA is promulgating a
biodegradation rate ratio of less than 1.0. As discussed in April 2000, EPA is promulgating the use of the
marine anaerobic closed bottle biodegradation test (i.e., ISO 11734:1995) with modifications for compliance
with this biodegradation BAT limitation. With this limitation the base fluids currently available for use
include vegetable ester, low viscosity esters, LAOs, and lOs.
The marine anaerobic closed bottle biodegradation test (i.e., ISO 11734:1995) is incorporated by
reference into the effluent limitation guidelines and is available from the American National Standards
Institute, 11 West 42nd Street, 13th Floor, New York, NY 10036. Additionally, EPA modified the marine
anaerobic closed bottle biodegradation test to make the test more applicable to a marine environment.
These modifications are listed in Appendix 4 of Subpart A of 40 CFR 435 and included: (1) the laboratory
shall use sea water in place of freshwater; (2) the laboratory shall use marine sediment in place of digested
sludge as an innoculum; and (3) the laboratory shall run the test for 275 days.
EPA selected the closed bottle test because it models the ability of a drilling fluid to degrade
anaerobically. Industry comments to the April 2000 NODA report the results of seabed surveys.66 These
seabed surveys and the scientific literature indicate that the environments under cuttings piles are anaerobic
and that the recovery of seabeds did not occur in acceptable periods of time when drilling fluids cannot
anaerobically degrade (e.g., diesel oils, mineral oils). The scientific literature also indicates that there is no
known mechanism for initiation of anaerobic alkane biodegradation.72 The general anaerobic microbiology
literature indicates that metabolic pathways are just beginning to be determined for anaerobic biodegradation
of linear alkanes. The anaerobic biodegradability of the SBF base fluid represents an essential prerequisite
for the prevention of long-term persistence of SBFs and deleterious impacts on marine sediments.73
Therefore, EPA considers the control of anaerobic degradation as crucial in ensuring the biodegradation of
SBF under cuttings piles and other anaerobic environments for the recovery of benthic environments in an
acceptable period.
EPA finds this limit to be technically available because information in the rulemaking record
supports that vegetable esters, low viscosity esters, and lOs have performance characteristics enabling them
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to be used in a wide variety of drilling situations offshore. Marketing data given to the EPA shows that, at
least for certain of the major drilling fluid suppliers, internal olefin SBFs are currently the most popular
SBFs used in the Gulf of Mexico.
5.2.5 Bioaccumulation
EPA also considered establishing a BAT limitation and NSPS that would limit the base fluid
bioaccumulation potential. The regulated parameters would be the non-conventional and toxic priority
pollutants that bioaccumulate. EPA reviewed the current literature to identify the bioaccumulation potential
of various base fluids. After this review EPA determined that SBFs are not expected to significantly
bioaccumulate because of their extremely low water solubility and consequent low bioavailability. Their
propensity to biodegrade makes them further unlikely to significantly bioaccumulate in marine organisms.
EPA identified that hydrophobic chemicals (e.g., ester-SBF base fluids) that have a log Kow less
than about 3 to 3.5 may bioaccumulate rapidly but not to high concentrations in tissues of marine organisms,
particularly if they are readily biodegradable into non-toxic metabolites.74 Hydrophobic chemicals (e.g., C16-
C18 lOs, various PAOs, and C18 n-paraffms) with a log Kow greater than about 6.5 to 7 do not bioaccumulate
effectively from the water, because their solubility in both the water and lipid phases is very low.74 Finally,
the degradation by-products of SBF base fluids (e.g., alcohols) are likely to be more miscible with water
than the parent substances, resulting in degradation by-products partitioning into the water column and being
diluted to lexicologically insignificant concentrations.
Based on current information, EPA believes that the stock base fluid controls on PAH content,
sediment toxicity, and biodegradation rate being promulgated today are sufficient to only allow the discharge
of base fluids (e.g., esters, internal olefms) with lower bioaccumulation potentials (i.e., log Kow < 3 to 3.5
and log Kow > 6.5 to 7).
5.2.6 Product Substitution Costs
EPA finds that the promulgated stock base fluid controls are economically achievable. Industry has
commented to EPA that while the synthetic base fluids are more expensive than diesel and mineral oil base
fluids, the savings in being able to discharge the SBF-cuttings versus land disposal or injection of OBF-
cuttings (in order to meet current regulations) more than offsets the increased cost of SBFs. Moreover, the
reduced time to complete a well with SBF as compared with OBF- and WBF-drilling can be significant (i.e.,
days to weeks). This reduction in time translates into lower rig rental costs for operators. In addition, the
VII-47
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use of more efficient solids removal technology (used as a basis for the BAT and NSPS retention
limitations) increases the recovery of SBF fluid which adds to the overall savings. Thus, it reportedly costs
less for operators to invest in the more expensive SBF provided it can be discharged. The stock base fluid
limitations promulgated above allow use of the currently widely used SBFs based on internal olefins
($160/bbl), vegetable esters ($250/bbl), and low viscosity esters ($300/bbl).75 For comparison, diesel oil-
based drilling fluid costs about $70/bbl, and mineral oil-based drilling fluid costs about $90/bbl. According
to industry sources, currently in the Gulf of Mexico the most widely used and discharged SBFs are, in order
of use, based on internal olefins, linear alpha olefins, and vegetable esters. Since the stock limitations allow
the continued use of the IO- and ester-SBFs or other fluids with equivalent toxicity and biodegradation
properties and meeting the PAH limitation, EPA attributes no additional cost due to the stock base fluid
requirements other than monitoring (testing and certification) costs. EPA anticipates that discharges could
satisfy the PAH requirements by having suppliers monitor each batch of stock SBF and that they could
satisfy stock sediment toxicity and biodegradation limitations and standards by having suppliers monitor
once annually.
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 rheology of the drilling fluid. Drilling fluid
properties degrade as the amount of fine particles in the drilling fluid increases. 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 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 waste streams. EPA has also learned that there is no
distinguishable difference in the separability of cuttings from OBF as compared to SBF.20>36
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A typical solids control system for SBF/OBF drilling consists of some combination of the following
equipment, depending on the nature of the drilling program: primary and secondary shale shakers that
separate drill cuttings from drilling fluid; a "drying" shale shaker or centrifuge to further recover drilling fluid
from the cuttings waste stream; a "high-G" shale shaker or centrifuge to remove fine solids from the drilling
fluid stream; and sand traps.
Drilling fluid returning from the well is laden with drill cuttings. The drill cuttings range in size from
large particles that are on the order of a centimeter or more in size to small particles (i.e., fines or "low
gravity solids") that are fractions of a millimeter in size. Standard or current practice solids control systems
employ primary and secondary shale shakers in series with a "fines removal unit" (e.g., decanting centrifuge
or mud cleaner). The drilling fluid and drill cuttings from the well are first passed through primary shale
shakers. These shakers remove the largest cuttings which are approximately 1 to 5 millimeters in size. The
drilling fluid recovered from the primary shakers is then passed over secondary shale shakers to remove
smaller drill cuttings. Finally, a portion or all of the drilling fluid recovered from the primary and secondary
shakers may be passed through the fines removal unit to remove fines from the drilling fluid. It is important
to remove fines from the drilling fluid in order to maintain the desired rheological properties of the active
drilling fluid system (e.g., viscosity, density). Thus, the cuttings waste stream normally consists of
discharged cuttings from the primary and secondary shale shakers and fines from the fines removal unit.
Operators using improved solids control technology insert an additional treatment unit in the above-
described treatment train. An improved solids control system processes the cuttings discarded from the
primary and secondary shale shakers through a "cuttings dryer" (e.g., vertical or horizontal centrifuge,
squeeze press mud recovery unit, High-G linear shaker). The cuttings from the cuttings dryer are
discharged and the recovered SBF is sent to the fines removal unit. The advantage of the cuttings dryer is
that more SBF is recovered for re-use and less SBF is discharged into the ocean. This, consequently, will
reduce the pollutant loadings and the potential of the waste to cause anoxia (lack of oxygen) in the receiving
sediment. Figure VII-7 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. Performance results related to retention on cuttings of SBFs are summarized
in Section 4.2.3 of this chapter. Individual well data used in the evaluation of the performance of the
technologies are contained in Table 2 of the Statistical Support Document.23
Table VII-17 presents a comparative overview of the various baseline and improved solids control
drilling fluid recovery devices currently available. EPA reviewed current literature from eight equipment
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FIGURE VII-7
GENERALIZED SOLIDS CONTROL SYSTEM
manufacturers or distributors. Table VII-17 lists selected design and operating characteristics of shale
shakers and centrifuges commercially available to U.S. drilling operators.
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 waste
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stream 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 additionally treated by a third type of shale
shaker, referred to as a "drying" shaker or "cuttings dryer" to indicate that it treats cuttings as opposed to
the secondary shale shaker that treats drilling fluid. The drying shaker or cuttings dryer is used to remove
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TABLE VII-17
DRILLING FLUID RECOVERY DEVICESa
Manufacturer/
Distributor
Brandt
Derrick
Equipment
Swaco
Broadbent
Mud Recovery
Systems, Ltd.
(MRS); JB
Equipment, Inc.
Centrifugal
Services, Inc.
(CSI)
Apollo Services,
Inc.
Device
Name
ATL-Dryer
SDW-25
ffl-G Dryer
ATL-II
NAb
MUD 6
MUD 10
Verti-G30
Verti-G60
Squeeze
Press
Device
Type(s)
Linear motion
shale shakers
Mud cleaner
Decanting
centrifuge
Linear motion
shale shaker
Mud cleaner
Linear motion
shale shaker
Mud cleaner
Decanting
centrifuges
Vibrating
centrifuge
Vertical axis
centrifuge
Press
Device
Category
SS
FRU
FRU
Dryer
FRU
SS
FRU
NA
Dryer
Dryer
Dryer
Dryer
Performance
(Wt % SBF Retention
Reported by Co.)
EPA Technology Avg.]
(Stationary Rigs: 8-10%)
(Floating Rigs: 12%)
[11.9%]
[9.97%]
(<10%)
[11.9%]
(6-8%)
[11.9%]
(<10%)
[9.97%]
(<7%)
[3.85]
(2.5-3%)
[3.72]
[6.71]
Capacity
ATL: 8
SOW: 7
ton/hr
2-8 ton/hr
4-8 ton/hr
Up to 1 ,200
gal/min
2-8 ton/hr
500 gal/min
2-8 ton/hr
5.5-27.5
tons/hr
11 tons/hr
88 tons/hr
30 tons/hr
60 tons/hr
9": NA
12": NA
Size
(LxWxH, inches)
Weight (Ibs)
ATL: 100x71x57
SOW: 134x78x109
-118x70x83
-115x58x48
142x71x74
-118x70x83
129x63x61
-118x70x83
NA
59x54x52
89x74x67
87x87x120
87x87x128
64x9x16
64x12x16
Max.
G-Force
Applied to
Cuttings
ATL: 4.2
SOW: 7
8.0
6.25
NA
130
800
NA
Power
NA
NA
NA
NA
45 amp; 440 v; 60
Hz
85 amp; 440 v; 60
Hz
480W3 phase, 60
Hz (150 amp
breaker)
75+1/4 hp motors
NA
Cost Information
(1998$ unless
otherwise noted)
Day Rate: $200-
$250/day
Capital Cost: $30K-
$40K
O&M: $50/day
Day Rate: $225/day
Capital Cost: $47. 5K
O&M: $600/week
Day Rate: $190/day
ยฃ2MMinl989
(~$3.8MM)
Day Rate for Amoco
Demo of
Mud-10: $1200 (incl.
one FTEC)
NA
NA
Information presented in this table was either quoted or derived from information provided in company literature or telephone communications with company representatives.
b Not available. c Full-time equivalent.
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additional drilling fluid from the waste cuttings before they are discharged, injected, or transported offsite for
disposal.
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.
EPA 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-8, 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
VII-53
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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.
Three shale shaker manufacturers claim their shale shakers can reduce the amount of SBF or OBF
SUE
Far-Raid Scrams
FRCNT
CJthp
n
Lags1
Ctffcp
aid?
Ofrg;
FIGURE VII-8
SCHEMATIC SIDE AND FRONT VIEWS OF TWO-TIERED SHALE SHAKERS
retained on the cuttings to less than 10% base fluid by weight. EPA's evaluation of data submitted for this
rulemaking shows the long-term average of SBF retained on cuttings following processing by primary and
secondary shale shakers is 9.32% and 13.8%, respectively (see Section 4.2.3 of this chapter and the
Statistical Analysis Document23). As was expected because of the smaller particle sizes in the cuttings
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waste stream, the retention value for the secondary shale shaker is considerably higher than the primary
shaker. 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.
5.3.2 High-G Shale Shaker
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 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 from the cuttings waste stream. 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 observed a high-G shale shaker at an offshore Gulf of Mexico drilling operation that was using
SBF at the time of the site visit.17 (This was the same site discussed above that also was operating primary
and secondary shale shakers.) The high-G shale shaker was 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 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.
Information provided by the manufacturer indicated that the unit should process cuttings to an SBF
retention of <10%. EPA's evaluation of the data supplied by industry demonstrates a retention value of
9.4%, which is consistent with the design and specified performance of the unit.
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5.3.3 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 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-17 lists centrifuges manufactured by three companies for use as drilling fluid recovery
devices. The first two (decanting) centrifuges listed are manufactured and marketed as a component in a
typical (i.e., baseline) cuttings management treatment train. Such solids control system components were
used to process all the cuttings returning from the well, using primary and secondary centrifuges as
necessary in parallel. The remaining centrifuges listed in Table VII-17 represent a new 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. The Mud 10 was developed by a manufacturer serving North
Sea operators, and has a record of demonstrated 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 VII-9 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. On the drilling rig, the Mud 10 unit was mounted on a platform, adding two
to three feet to its height.
VII-56
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EPA's evaluation of data submitted for the rulemaking shows the amount of SBF retained on cuttings
following Mud 10 centrifuge technology is 3.85%. The cost of renting the Mud 10, including one man
dedicated to its operation, was $1,200 per day.
SJ^Ottng
L PS
1/3 SEF
-iiur*
Fnslc
Dschas
FIGURE VII-9
CONFIGURATION OF AMIRANTE SOLIDS CONTROL EQUIPMENT
VII-57
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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 EPA's evaluation of data submitted by industry for this technology shows that
the amount of retained SBF on cuttings following vertical centrifuge treatment was 3.72% (the best value
reported by EPA).
5.3.4 Squeeze Presses
In addition to shale shakers and centrifuges, squeeze presses have been used to separate adhering
drilling fluid from the bulk cuttings waste stream prior to discharge. Squeeze 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. The squeeze press creates brick-like solid chunks of cuttings waste with
entrapped drilling fluid. Squeeze presses are not widely utilized by U.S. drilling operators for recovering
drilling fluid from cuttings. EPA's evaluation of retention on cuttings data submitted by industry for squeeze
press technology revealed a performance level of 6.71% retained SBF on cuttings, intermediate between
horizontal and vertical centrifuges (3.71% - 3.85%) and primary shale shaker (9.32%)/decanting centrifuge
(9.97%) technologies and, as expected, considerably better than secondary shale shaker (13.8%)/mud
cleaner (11.9%) technology performance.
5.3.5 Fines Control
As discussed in the April 2000 NODA (65 FR 21569), solids control equipment generally breaks
larger particles into smaller particles. An undesirable increase in drilling fluid weight and viscosity can occur
when drill solids degrade into fines that cannot be removed by solids control equipment [i.e., generally
classified as < 5 microns (10~6 meters) in length]. An unacceptable high fines content (i.e., generally > 5%
of total drilling fluid weight) may consequently lead to drilling problems (e.g., undesirable rheological
properties, stuck pipe). Therefore, it is possible that the increased recovery of SBF from cuttings for re-use
in the active mud system, often achieved through use of the cuttings dryer in solids control systems, may
lead to a build-up in fines for certain formation characteristics (e.g., high reactivity of formation cuttings,
limited loss of drilling fluid into the formation). In order to meet EPA's promulgated numeric cuttings
retention value where there are unfavorable formation characteristics, operators may be limited to: (1)
diluting the fines in the active mud system through the addition of "fresh" SBF; and/or (2) capturing a
portion of the fines in a container and sending the fines to shore for disposal.
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EPA requested comments on the issue of fines management in the April 2000 NODA. Comments
from API/NOIA identified only one instance in which the use of a cuttings dryer in combination with a fines
removal unit in the United States may have lead to an increase in "fines build-up" and a loss of circulation
event.71 Further communication with industry identified that this well (Shell, Green Canyon 69, OCS-G-
13159#3) was the first application of the cuttings dryer type (Mud-10 cuttings dryer) in the Gulf of Mexico
and that fines were not an issue for the well in question.76 Moreover, further industry comments revealed
that the properties of formations are often the main culprit of loss circulation and that the same rig
(Marianas) had a loss of circulation at another nearby well in the same formation (without a cuttings dryer)76
Therefore, based on the record, which includes over three dozen successful cuttings dryer deployments,
EPA concluded that extensive fines build up is not an issue related to the control technology when operators
properly operate and maintain cuttings dryers and fines removal equipment.
5.3.6 Rig Compatibility
EPA requested comments on the issue of rig compatibility with cuttings dryer installation. EPA
received information on the ability of operators to install cuttings dryers (e.g., vertical or horizontal
centrifuges, squeeze press mud recovery units, High-G linear shakers) on existing Gulf of Mexico rigs.77
There are 223 drilling rigs in the Gulf of Mexico and 173 are in operation. Of the 173 Gulf of Mexico in
operation, 28% are not capable of having a cuttings dryer system installed due to either rig space and/or rig
design without prohibitive costs or rig modifications.
EPA requested comments in the April 2000 NODA on the issue of rig compatibility with the
installation of cuttings dryers (e.g., vertical or horizontal centrifuges, squeeze press mud recovery units,
High-G linear shakers). EPA received general information on the problems and issues related to cuttings
dryer installations from API/NOIA stating that not all rigs are capable of installing cuttings dryers.71'77 In
late comments, some industry commentors asserted that 48 of the 223 Gulf of Mexico drilling rigs are not
capable of having a cuttings dryer system installed due to either rig space and/or rig design without
prohibitive costs or rig modifications.35 Upon a further, more extensive review of Gulf of Mexico rigs, these
same commentors asserted that 30 of 234 Gulf of Mexico drilling rigs are not capable of having a cuttings
dryer system installed due to either rig space and/or rig design without prohibitive costs or rig
modifications.77 EPA also received late comments from one operator, Unocal, stating that 36 of 122 Unocal
wells drilled between late 1997 and mid-2000 were drilled with rigs that do not have 40 foot x 40 foot space
available which they assert is necessary for a cuttings dryer installation.38 The API/NOIA rig survey and the
Unocal rig survey identified most of the same rigs as unable to install cuttings dryers. However, two rigs
(i.e., Parker 22, Nabors 802) identified in the Unocal rig survey as having no space for a cuttings dryer
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installation were identified in the API/NOIA rig survey as having a previous cuttings dryer installation.
Unocal requested in late comments that EPA subcategorize certain rigs from being subject to the retention
limit or that these rigs be able to discharge SBFs using performance that reflects current shale shaker
technology.39
Based on the record, EPA finds that current space limitations for cuttings dryers do not require a 40
foot x 40 foot space. Specifically, EPA has in the record information gathered during EPA's October 1999
site visit and information supplied by API/NOIA and equipment vendors. Also, EPA received information
from a drilling fluid manufacturer and cuttings dryer equipment vendor, M-I Drilling Fluids, stating that they
are not aware of any Gulf of Mexico rig not capable of installing a cuttings dryer.86 API/NOIA estimated
that 150 square feet are required for a cuttings dryer installation in order to meet the ROC BAT limitation
and NSPS.57 EPA also estimates that the minimum height clearance for a typical cuttings dryer installation
is 6 feet. The API/NOIA estimate is based on the installation of a horizontal centrifuge cuttings dryer (i.e.,
MUD-6). The Unocal estimate is based on the vertical centrifuge cuttings dryer and is also characterized by
other industry representatives as too high.77 EPA's estimate of a typical vertical centrifuge installation is 15
feet x 15 feet with a minimum height clearance of 11 feet. EPA based the ROC BAT limitation and NSPS
(e.g., 6.9%) on the use of both these cuttings dryers for SBFs with the stock limitations of C16-C18 lOs.
Based on comments from operators and equipment vendors, EPA believes that most of these shallow well
rigs have the requisite 160-225 square feet available to install a cuttings dryer (see Table VII-17 for
dimensions). Therefore, EPA finds that operators are not required to have a 1,600 square foot space for a
cuttings dryer installation in order to meet the ROC BAT limitation and NSPS. Proper spacing and
placement of cuttings dryers in the solids control equipment system should prevent installation problems.
Because of the large discrepancy between EPA's record information and the space requirements
asserted by an industry commenter (1,600 square feet versus EPA's 225 square feet +11 feet in height for
the vertical centrifuge or 150 square feet + 6 feet in height for the horizontal centrifuge - MUD-6), EPA
does not necessarily believe that there are as many wells that cannot install cuttings dryers as the commentor
claims. Further, based on scant detail supporting these assertions, and their lateness in the process, EPA has
no basis upon which to assess them or verify them.
Moreover, EPA does not believe that it has enough information to reasonably subcategorize these
facilities, nor did it have time to provide public notice of how it would define such a subcategory, given the
court-ordered deadline for this rule. EPA does not believe that basing a subcategory by specifying a space
requirement alone (e.g. operators that do not have a certain amount of deck space available on, below or
adjacent to the deck would not be subject to this requirement) would be sufficient to prevent operators from
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configuring their other equipment in a manner that would enable them to fit into the subcategory. Such an
exception might also lead to operators to make other assertions justifying that they should be included (e.g.,
that while they have a certain amount of space available, safety reasons prevent placement of the
technology on the rig). Without a solution to these issues, EPA is concerned that such a subcategorization
would potentially be too broad and be unworkable.
For these reasons, EPA believes that the appropriate way to handle these concerns is through the
fundamentally different factors (PDF) variance process. This process, provided for under CWA section
301(n), would allow operators to submit supporting data and information to EPA and would give the public
the opportunity to comment on that data to determine whether an PDF is truly warranted for that drilling
facility. EPA has authority over owners and operators, who are both dischargers, but the NPDES
regulations require the operator to apply for the NPDES permit: "When a facility or activity is owned by one
person but is operated by another person, it is the operator's duty to obtain a permit," [see 40 CFR
122.21(b)]. Thus, mobile drill rig "operators" as dischargers can apply for FDFs [see 40 CFR 125.32;
122.21(b)] even when not currently drilling (or discharging).
5.3.7 Small Volume Wastes
EPA has also decided that solids accumulated at the end of the well ("accumulated solids") and
wash water used to clean out accumulated solids or on the drill floor are associated with drill cuttings and
are therefore not controlled by the zero discharge requirement for SBFs not associated with drill cuttings.
EPA is controlling accumulated solids and wash water under the discharge requirements for cuttings
associated with SBFs. The amount of SBF base fluid discharged with discharged accumulated solids will be
estimated using procedures in Appendix 7 to Subpart A of 40 CFR 435 and incorporated into the base fluid
retained on cuttings numeric limitation or standard. The source of the pollutants in the accumulated solids
and associated wash water are drill cuttings and drilling fluid solids (e.g., barite). The drill cuttings and
drilling fluid solids can be prevented from discharge with SBF-cuttings due to equipment design (e.g., sand
traps, sumps) or improper maintenance of the equipment (e.g., failing to ensure the proper agitation of mud
pits). Discharge of SBF associated with accumulated solids in the SBF active mud system and the
associated wash water is normally a one-time operation performed at the completion of the SBF well (e.g.,
cleaning out mud pits and solids control equipment).
The quantity of SBF typically discharged with accumulated solids and wash water is relatively
small. The SBF fraction in the 75 barrels of accumulated solids is approximately 25% and generally only
very small quantities of SBF are contained in the 200 to 400 barrels of associated equipment wash water.
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Current practice is to retain accumulated solids for zero discharge or recover free oil from accumulated
solids prior to discharge. Since current practice is to recover free oil and discharge accumulated solids, the
controlled discharge option for SBF-cuttings represents current practice and is economically achievable.
Moreover, recovering free oil from accumulated solids prior to discharge has no unacceptable NWQIs. EPA
defines accumulated solids and wash water as associated with drill cuttings. Therefore, operators will
control these SBF-cuttings wastes using the SBF stock limitations and cuttings discharge limitations. As
compliance with EPA's SBF stock limitations and cuttings discharge limitations does not require the
processing of all SBF-cuttings wastes through the solids control technologies (e.g., shale shakers, cuttings
dryers, fines removal units), operators may or may not elect to process accumulated solids or wash water
through the solids control technologies.
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. In Cook Inlet, operators primarily use injection for waste disposal. An
informal survey of offshore operators showed that 11 of the 14 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 information 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.
EPA received additional information regarding waste disposal practices in each of the three
geographic areas (e.g., Gulf of Mexico, Offshore California, Cook Inlet, Alaska). As a result of this
information, EPA revised the assumptions for the fraction of waste either injected at the drill site, injected
on-shore or land disposed. Though the percentage of waste injected onsite versus hauled to shore
(20%/80%) in the Gulf of Mexico remains unchanged, the method of onshore disposal has been revised for
the final rule. In the Gulf of Mexico, 80% of the waste hauled to shore is injected onshore and only 20% is
landfarmed.
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EPA estimates that all SBF wastes from Californian deep water exploratory wells are sent onshore
(i.e., 100% onshore disposal/0% onsite injection). For all other wells (i.e., shallow water development and
exploratory and deep water development), EPA estimates that most of the offshore waste is disposed
through offshore onsite cuttings injection (i.e., 20% onshore disposal/80% onsite injection) based on the fact
that most of these wells are being drilled from fixed platforms. EPA estimates that most California offshore
wastes sent onshore are disposed via onshore formation injection (i.e., 20% of offshore wastes sent onshore
disposed via landfarming/80% of offshore wastes sent onshore disposed via onshore injection) based on the
number of California land disposal operations identified in the most recent review of the Industry.
Based on the record for the 1996 Coastal rulemaking, EPA determined that onsite injection was not
feasible throughout Cook Inlet, Alaska (see Coastal Development Document, EPA-821-R-96-023, Section
5.10.3). More recently, however, EPA identified in the April 2000 NODA that the SBF rulemaking record
now demonstrates that many Cook Inlet operators in Coastal waters are using cuttings injection.78'79> 42
EPA contacted Cook Inlet operators (e.g., Phillips, Unocal, Marathon Oil) and the State regulatory agency,
Alaska Oil and Gas Conservation Commission (AOGCC), for more information on the most recent injection
practices of Cook Inlet operators. AOGCC regulations provide Cook Inlet operators the opportunity to
permit and operate Class II disposal wells and annular disposal activities. Information provided to EPA
indicate that Cook Inlet operators in Coastal waters are availing themselves of onsite cuttings injection and
are receiving AOGCC permits for this activity. Generally, Cook Inlet operators in Coastal waters agree that
onsite injection is available for most operations.
AOGCC also agreed that there should be enough formation injection disposal capacity for the small
number of wells (< 5-10 well per year) being drilled in Cook Inlet Coastal waters. AOGCC stated,
however, that case specific limitations should be considered when evaluating disposal options. For instance,
Unocal has experienced difficulty establishing formation injection in several wells that were initially
considered for annular disposal. In addition, Cook Inlet operators have the burden of proving to AOGCC's
satisfaction that the waste will be confined to the formation disposal interval. Approval of annular disposal
includes a review of cementing and leak-off test records. In some instances the operator may also have to
run a cement bond log. When an older well is converted for use as a disposal well, some of this information
may not exist. In cases where there is insufficient information, disposal is not allowed. Annular disposal is
also limited to the platform on which the waste is generated. Although Class II disposal regulations don't
restrict waste transport, it has generally been the practice of the various fields' owners not to accept any
waste generated by other operators. In addition, AOGCC stated that a zero discharge requirement poses
serious technical hurdles with respect to the handling of drilling waste for exploration drilling with mobile
rigs. Normally, there is neither capacity for storage or room for processing equipment on exploratory drilling
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rigs. Therefore, for the NWQI analysis, EPA estimates that all of the cuttings from the Coastal Cook Inlet
operations (i.e., shallow water wells) are injected (i.e., 0% onshore disposal/100% on-site injection) based
on the ability of industry to dispose of oil-based cuttings via onsite formation injection or annular disposal
after gaining State regulatory approval.
In order to assess the SBF NWQIs relative to the total impacts from drilling operations, EPA
included estimates of the daily drilling rig impacts to the NWQIs from SBF-related activities. The additional
impacts consist of fuel use and air emissions resulting from the various drilling rig pumps and motors as well
as impacts of a daily helicopter trip for transporting personnel and/or supplies. Impacts were assessed for
the number of days that an SBF interval is drilled versus the number of days well intervals are drilled using
WBFs and OBFs and for the number of wells drilled using each of the drilling fluids (see Chapter IV of this
document).
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 that may be 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 boxes.47'4S 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 twelve 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
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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 Chapters VIII and IX present the source data and detailed methodology EPA used
to apply these estimates in compliance cost and other pertinent analyses.
Gulf of Mexico and California 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 Estimated trucking
distances also vary between geographic areas, as follows: 20 miles round trip between port and disposal
facility in the Gulf of Mexico and 300 miles round trip between port and disposal facility in California
(estimated mileage between Ventura and Bakersfield). Trucking costs were estimated for California, 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 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
clay-like 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
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
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gas field wastes.10 This is more than sufficient capacity to manage the nearly 225 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 and
Alaska.
EPA updated current disposal facility costs for the Gulf of Mexico and offshore California. 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 baseline unit disposal cost of $12.53 per barrel plus a handling cost of $5.89 per barrel.
Handling costs were not included in the disposal cost provided for California. As an estimate, EPA used
Gulf of Mexico data and pro rata calculated California handling costs based on the percentage of Gulf of
Mexico-per-barrel costs relative to per barrel disposal costs (47%). EPA's per barrel disposal cost for
California was cost based on a price of $35 per ton for a disposal facility located near Bakersfield51, and the
calculated density of 716 Ibs/bbl for cuttings with 10.2% by weight adhering SBF/OBF (see Table VII-4). A
BAT/NSPS Option 2 per barrel disposal cost of $12.41, and a handling cost of $5.83 per barrel were
derived using the same assumptions as for the baseline case except a density of 709 Ib/bbl cuttings with a
10.7% SBF/OBF retention. Disposal costs for WBF in the Gulf of Mexico, because they are based on a per
barrel basis, are the same as for SBF/OBF. In California, WBF disposal costs were estimated at $8.41 per
barrel based on a wet cuttings density of 566 Ibs/bbl (543 Ibs/bbl cuttings plus 5%, or 2.1 gal/bbl, adherent
WBF at 11 Ibs/gal); the handling charge was estimated to be $3.95 per barrel.
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 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 states
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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 Subsurface 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, and has become more available since the
1996 coastal oil and gas rulemaking. 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. An 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 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 estimates that 20% of the waste is
injected offshore and 80% of the waste is land disposed in the Gulf of Mexico.
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
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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. Information concerning
one commercial injection operation in Cook Inlet concerned the amount of cuttings injected through one
well. 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 programs,10'16 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 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 per minute.58
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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 day,44 $2,500 per day,58 and $2,500-$3,000 per day.60 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 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 SBF Discharges Not Associated with Cuttings
In the February 1999 proposal, EPA proposed BPT, BCT, BAT, and NSPS as zero discharge for
SBFs not associated with drill cuttings. In the April 2000 NODA, EPA published two options for the final
rule for the BAT limitation and NSPS for controlling SBFs not associated with SBF drill cuttings: (1) zero
discharge; or (2) allowing operators to choose either zero discharge or an alternative set of BMPs with an
accompanying compliance method. Industry supported the second option stating that the first option (zero
discharge) would result in the costly and potentially dangerous collection, shipping, and disposal of large
quantities of rig site wash water containing only a small quantity of SBF.57 Industry also stated that BMPs
would be extremely effective at reducing the quantity of non-cuttings related SBF and would focus
operators' attention on reducing these discharges.
EPA is promulgating BPT, BCT, BAT, and NSPS of zero discharge for SBFs not associated with
drill cuttings. This waste stream consists of neat SBFs that are intended for use in the downhole drilling
operations (e.g., drill bit lubrication and cooling, hole stability). This waste stream is transferred from
supply boats to the drilling rig and can be released during these transfer operations. This waste stream is
often spilled on the drill deck but contained through grated troughs, vacuums, or squeegee systems. This
waste stream is also held in numerous tanks during all phases of the drilling operation (e.g., trip tanks,
storage tanks). EPA received information that rare occurrences of improper SBF transfer procedures (e.g.,
no bunkering procedures in place for rig loading manifolds) and improper operation of active mud system
equipment (e.g., no lock-out, tag-out procedures in place for mud pit dump valves) has the potential for the
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discharge of tens to hundreds of barrels of neat SBF, or SBF not associated with cuttings, if containment is
not practiced.41
Current practice for control of SBF not associated with drill cuttings is zero discharge (e.g., drill
deck containment, bunkering procedures), primarily due to the value of SBFs recovered and reused.
Therefore, zero discharge for SBF not associated with drill cuttings is technologically available and
economically achievable. Moreover, these controls generally allow the re-use of SBF in the drilling
operation and has no unacceptable NWQIs.
EPA has also decided that solids accumulated at the end of the well ("accumulated solids") and
wash water used to clean out accumulated solids or on the drill floor are associated with drill cuttings and
are therefore not controlled by the zero discharge requirement for SBFs not associated with drill cuttings
(see Section 5.3.7 of this Chapter).
5.7 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 base BAT limitations or NSPS on this technology because its
application is at land-based rather than offshore facilities and therefore would result in far greater non-water
quality environmental impacts than the technologies EPA selected as a basis for BAT/NSPS.
6. REFERENCES
1. American Petroleum Institute, responses to EPA's "Technical Questions for Oil and Gas
Exploration and Production Industry Representatives," attached to E-mail from M. Parker, Exxon
Company, U.S.A., to J. Daly, EPA. 8/7/98.
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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. 4/9/96.
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." 10/26/98.
6. Baker-Hughes Inteq, Product information sheet featuring "Typical Formulation, 14.0 Ib/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-TEQโข," 1994.
9. Brandt/EPI, "The Handbook on Solids Control and Waste Management," 4th edition, 1996.
10. EPA. 1993. 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. (Record I.A.a.l)
11. The Pechan-Avanti Group, Worksheet regarding "Calculation of Organics in Waste Cuttings Due to
Crude Contamination." 1/20/99.
12. SAIC, Worksheet regarding "Calculations for Average Density of Dry Solids in Cook Inlet Drilling
Mud." 6/6/94.
13. Baker-Hughes Inteq, Material Safety Data Sheet for "MIL-BAR" (Barite). 3/21/94.
14. Baker-Hughes Inteq, Case history information featuring synthetic-based drilling fluid properties,
1995.
15. Daly, J., EPA, Memorandum regarding "Contamination of Synthetic-Based Drilling Fluid (SBF)
with Crude Oil." 1/14/99.
16. EPA. 1996. 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. (Record No. I.A.a.2)
17. The Pechan-Avanti Group, "Demonstration of the 'Mud 10' Drilling Fluid Recovery Device at the
Amoco Marlin Deepwater Drill Site." 8/7/98.
18. Annis, M.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. 8/29/97.
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19. White, C.E., and H.D. Kahn, EPA, Statistics Analysis Section, Memorandum to J. Daly, 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," 1/29/99.
20. Mclntyre, J., Avanti Corporation, Memorandum to Joseph Daly, EPA, regarding "Summary of
December 2 Meeting with D. Wood, Mud Recovery Systems." 12/15/97.
21. Annis, M.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. 8/19/98.
22. Daly, J., EPA, Memorandum regarding "Data Showing the Performance of the Mud 10 with North
Sea Oil Wells," 1/14/99.
23. EPA. 2000. Statistical Analyses Supporting Final Effluent Limitations Guidelines and Standards
for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas
Extraction Point Source Category. EPA-821-B-00-015. (Record No. IV.C.a.3)
24. Daly, J., EPA, Memorandum regarding "Cost of Synthetic-Based Drilling Fluids (SBF)," 1/15/99.
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. 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, J., 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,
D.F. Jacques, Ph. D., 6/25/96, and 2) Letter from M.E. Parker, P.E., Exxon Company U.S.A., to
M.B. Rubin, EPA, 9/17/96.
28. Hood, C.A., Baker-Hughes Inteq, Letter to J. Daly, EPA, with unpublished sediment toxicity data
from Baker-Hughes Inteq, 7/9/97.
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. 9/11/98.
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. 12/11/98.
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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. 7/29/96.
33. Munro, P.O., 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. EPA. 1999. 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.
35. Angelle, R. and P. Scott. 2000. Rig Survey Related to Installation Cost and Operational Costs of
"Cuttings Dryers" to Reduce the Retention of Synthetic Based Mud on Cuttings Discharge. (Record
No. IV.B.b.33)
36. Mclntyre, J., Avanti Corporation, Telephone Communication Report on conversation with P.
Matthews, Newpark Drilling Fluids, regarding '"Centrifugal Dryer' for Drill Cuttings," May 29,
1998.
37. Derrick Equipment Company, Product brochure entitled "Derrick HI-Gโข Dryer with Optional
Hydrocyclone Packages," October 1997.
38. O'Donnell, K., Unocal. 2000. Letter to M. Rubin, EPA transmitting additional information.
10/26/00. (Record No. IV.B.b.31)
39. Ressler, J., Unocal, Email to M. Rubin, EPA. 10/27/00. (Record No. IV.A.a.36)
40. Mclntyre, J., Avanti Corporation, Telephone Communication Report on conversations with P.
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. 4/15/98.
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, H., "Dewatering of Drilling Fluids," mPetroleum Engineer International, February 1991.
44. Veil, J.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.
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46. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with
personnel at Frances Torque Service, regarding "Cuttings box rental costs (Gulf of Mexico area)."
6/4/98.
47. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with J.
Belsome, Seabulk Offshore Ltd., regarding "Offshore supply boat costs and specifications." 6/3/98.
48. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with George
Bano, Sea Mar Management, regarding "Offshore supply boat costs and specifications." 6/3/98.
49. EPA, "Trip Report to Campbell Wells Land Treatment, Bourg, Louisiana, March 12, 1992."
5/29/92.
50. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with Frank
Lyon, Newpark Environmental, regarding "Drilling Waste Zero Discharge Disposal Costs."
51119/98.
51. Mclntyre, J., 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." 10/16/98.
52. Candler, J., M-I. Email to C. Johnston, EPA concerning ability of service companies to place
cuttings dryers on rigs. 11/10/00. (Record No. IV.B.b.32)
53. Montgomery, R., 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." 5/9/98.
54. Weideman, A., EPA, "Trip Report to Alaska Cook Inlet and North Slope Oil and Gas Facilities,
August 25-29, 1993." 8/31/94.
55. Newpark Environmental Services, Facsimile of Price List, Effective May 1, 1998, from L.L.
Denman to K. Kennedy. 5/26/98.
56. U.S. Liquids of Louisiana, Facsimile of Price List, from "Betty" to J. Mclntyre. 5/26/98.
57. Moran, R., National Ocean Industries Association, Re: National Ocean Industries Association,
American Petroleum Institute, Offshore Operators Committee, and Petroleum Equipment Suppliers
Association Comments on "Effluent Limitations Guidelines for Oil and Gas Extraction Point Source
Category," Proposed Rule 65 FR 21548 (April 21, 2000). 6/20/00. (Record No. IV.A.a.13)
58. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with T.
Franklin, Apollo Services, regarding "Apollo Services drilling waste zero discharge practices and
cost." 5/19/98.
59. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with Nubon
Guidry, National Injection Services, regarding "Zero discharge practices for OEM and SBM."
4/29/98.
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60. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with Gene
Kraemer, National Injection Services, regarding "Zero discharge costs and space requirements:
Onsite injection." 5/19/98.
61. Daly, J., EPA, Memorandum regarding "October 13, 1998 Teleconference Regarding SBF Use,"
10/20/98
62. Henry, L., Chevron. Memorandum to C.A. Johnston, EPA. Response to EPA Request for
Additional Input Parameter for EPA Modeling. 9/11/00. (Record No. IV.B.a.9)
63. Avanti Corporation. 2000. Memorandum to B. Vanatta, ERG, Engineering Review of SBF
Retention-on-Cuttings Data. 12/12/00. (Record No. IV.C.a.2)
64. Van Slyke, Don, Unocal. Unocal Comments; Effluent Limitations Guidelines for the Oil and Gas
Extraction Point Source Category; Proposed Ruling (40 CFR 435). 6/9/00. (Record No. IV.A.a.3)
65. Xiao, L. and C. Piatti, Biodegradable Invert Oil Emulsion Drilling Fluids for Offshore Operations: A
Comprehensive Laboratory Evaluation and Comparison, SPE 29941, 1995. (Record No.
IV.A.a.13)
66. Young, S, Anchor Drilling Fluids, Life After Oil Based Muds? - The Technical and Environmental
Benefits of "Pseudo-Oil Based Muds," 1994. (Record No. IV.A.a.13)
67. Patel, A.D., J.M. Wilson, B.W. Loughridge, Impact of Synthetic-Based Drilling Fluids on Oilwell
Cementing Operations, SPE 50726, 1999. (Record No. IV.A.a.13)
68. Friedheim, J.E. and R.M. Pantermuehl, M-I Drilling Fluids, Superior Performance with Minimal
Environmental Impact: A Novel Nonaqueous Drilling Fluid, SPE/IADC 25753, 1993. (Record No.
IV.A.a.13)
69. Friedheim, J.E. and H.L. Conn, M-I Drilling Fluids, Second Generation Synthetic Fluids in the
North Sea: Are They Better? SPE 35061, 1995. (Record No. IV.A.a.13)
70. Hall, John, Baroid Drilling Fluids, Re: Effluent Limitations Guidelines for the Oil and Gas Extraction
Point Source Category; Proposed Rule 40 CFR Part 435 April 21, 2000. 6/19/00. (Record No.
IV.A.a.7)
71. Avanti Corporation. 2000. WBF Failure Rate Ancillary Cost Analysis. 12/27/00. (Record No.
IV.C.b.3)
72. Candler, J.E., S.P. Rabke, A.J.J. Leuterman, Predicting the Potential Impact of Synthetic-Based
Muds with the Use of Biodegradation Studies, SPE 52742, 1999. (Record No. IV.A.a.13)
73. Steber, J., C.-P. Ilerold and J.M. Limia. 1995. Comparative Evaluation of Anaerobic
Biodegradability of Hydrocarbons and Fatty Derivatives Currently Used as Drilling Fluids.
Chemosphere, Vol. 31, No. 4, pp. 3105-3118. (Record No.I.D.b.26)
74. Neff, J.M., S. McKelvie and R.C. Ayers. 2000. A Literature Review of Environmental Impacts of
Synthetic Based Drilling Fluids, Draft. Report to USDOI, MMS. 4/27/00. (Record No. IV.F. 1)
75. Candler, J., M-I Drilling Fluids. Email to C.A. Johnston RE: unit costs for various muds. 10/23/00.
(Record IV.B.a. 13)
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76. Meeting Summary Notes from July 20, 2000 SBF Stakeholders Meeting, Washington, DC. July
20,2000 meeting notes - (Record No. IV.A.b.l).
77. Angelle, R. and P. Scott. 2000. Rig Survey Update Focusing on the Number of Rigs/Platforms
Where Cuttings Dryers Could Not be Installed. Prepared by the Technology Assessment
Workgroup of Synthetic Based Mud Research Consortium (API and NOIA) in Conjunction with
Cuttings Dryer Equipment Vendor Representatives. 11/9/00. (Record No. IV.B.b.34).
78. Carter, M.W., Phillips Petroleum. 2000. Responses to questions concerning SBF usage in Cook
Inlet. (Record No. III.B.a. 11)
79. Johnston, C.A., EPA. 2000. Memorandum to File regarding January 19, 2000 Telephone
Conversation with Alaska Oil and Gas Conservation Commission (AOGCC), with attached AOGCC
regulations. 1/20/00. (Record No. III.B.a.23)
80. Sullivan, F., Unocal. Email to C. Johnston, EPA, SBF Usage in CI - Reply. 1/28/00. (Record No.
III.B.a.53)
81. (Docket No. W-98-26, Record No. IV.A.a.26, QTECH LTD Reports for Ocean America and
Discoverer 534).
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CHAPTER VIII
COMPLIANCE COST AND POLLUTANT REDUCTION
DETERMINATION OF DRILLING FLUIDS AND DRILL CUTTINGS
1. INTRODUCTION
This chapter presents the cost, pollutant loadings, and effluent reductions (removals) analyses for
the final rule. These analyses include the incremental costs or cost savings and incremental pollutant
removals or increases that accrue from the technology-based options considered for the control of SBF drill
cuttings. Incremental compliance costs or savings, beyond current industry practices and NPDES permit
requirements, were developed for three control options for the Gulf of Mexico, offshore California, and
coastal Cook Inlet, Alaska. Although there currently is no drilling activity in other parts of the United States
(e.g., offshore Alaska, offshore East Coast), EPA believes that the costs/savings and effluent
loadings/removals for any such projects would be comparable to those presented here.
2. OPTIONS CONSIDERED AND SUMMARY COSTS
Three main technology-based options were considered for control and treatment of SBF drill
cuttings for this rule. These options are:
BAT/NSPS Option 1 (Controlled Discharge Option): (1) Limitations on stock synthetic
base fluid (PAH content, biodegradation rate, and sediment toxicity); (2) limitations on
discharged SBF-cuttings (no free oil, formation oil contamination, sediment toxicity,
aqueous toxicity, and retention of SBF on cuttings) based on discharges from cuttings dryer
units and fines removal units; (3) limitations on Hg and Cd in stock barite; and (4)
prohibition of diesel oil discharge.
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BAT/NSPS Option 2 (Controlled Discharge Option): Same as BAT/NSPS Option 1 except
the retention of SBF on cuttings is based solely on the discharge from the cuttings dryer
units, and does not include an allowance for the discharge of the fines removal units.
โข BAT/NSPS Option 3 (Zero Discharge Option): Zero discharge of SBF-cuttings for all
areas.
Table VIII-1 presents annual technology costs and pollutant loadings calculated for each option, for
both existing and new sources. These technology (and monitoring) costs and pollutant loadings are
estimated based on the installation, operation, and maintenance of control technology and monitoring along
with the number of wells drilled annually. To determine the incremental compliance cost for each, both
costs and savings and pollutant increases and removals are estimated by considering: (1) projected annual
drilling activity in the three geographic regions; (2) model well volumes and waste characteristics; (3)
technology and monitoring costs; and (4) reductions in drilling days and recovery of SBFs. The derivation
of the costs/savings and pollutant increases/removals is described in the remainder of this chapter.
3. COMPLIANCE COST METHODOLOGY
The costs considered as part of the compliance cost analysis are those that will be affected by this
rule. This includes 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 two
BAT controlled discharge options (BAT/NSPS Option 1 and 2) and the zero discharge option (BAT/NSPS
Option 3), and various subsets of these options related to incentives for esters use. WBF wells that do not
convert to SBF wells or from SBF wells do not incur compliance costs because they are subject to
technology requirements EPA promulgated in 1993 (the Offshore Guidelines). As an ancillary analysis,
however, EPA also evaluated the costs associated with WBF wells that convert to or from SBF wells and
are projected to fail their toxicity or sheen limitation and be subject to a zero discharge restriction. The
reason for this analysis was to provide an assessment of zero discharge costs that would be avoided (or
more accurately, converted to SBF compliance costs) for WBF wells that would be projected to fail either
of their sheen or toxicity limitations but that instead converted to SBF. The only readily available data for
this analysis is the failure rate projections provided in the offshore development document (a weighted
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TABLE VIII-1
ANNUAL TECHNOLOGY COSTS AND POLLUTANT LOADINGS
FOR DRILL CUTTINGS BAT AND NSPS OPTIONS
Option
Technology Cost
(1999$/yr)
Total Effluent
Loadings
(Ibs/yr)
BA T Options for Existing Sources
BAT Option 1: Discharge with 4.03% retention of base
drilling fluid on cuttings
BAT Option 2: Discharge with 3.82% retention of base
drilling fluid on cuttings
BAT Option 3: Zero Discharge
$42,592,088
$42,772,221
$69,134,303
2,241,707,804
2,234,130,139
2,162,146,796
NSPS Options for New Sources
NSPS Option 1: Discharge with 4.03% retention of base
drilling fluid on cuttings
NSPS Option 2: Discharge with 3.82% retention of base
drilling fluid on cuttings
NSPS Option 3: Zero Discharge
$2,013,387
$2,017,491
$2,749,981
107,704,029
107,185,411
100,387,607
Total Costs and Pollutant Removals (BA T + NSPS)
BAT/NSPS Option 1: Discharge with 4.03% retention of
base drilling fluid on cuttings
BAT/NSPS Option 2: Discharge with 3.82% retention of
base drilling fluid on cuttings
BAT/NSPS Option 3: Zero Discharge
$44,605,476
$44,789,712
$71,884,284
2,349,411,833
2,341,315,550
2,262,534,403
average that calculated to 10.7%). EPA does not consider this information sufficiently reliable to include in
its formal cost analysis. In as much as this consideration represents a potential cost savings to industry,
EPA used a conservative approach to this issue and instead simply projected a 0% WBF failure rate (i.e., no
net savings to industry from this factor) in its cost analysis.
The following sections describe 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.
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Chapter IV of this document has presented an 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
of this document). For the purposes of calculating compliance costs, pollutant removals, and non-water
quality environmental impacts, a sub-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. For proposal, only SBF wells
or OBF wells (all of which EPA anticipated would convert to SBF) were included in the analysis. For
proposal, wells using OBF and not converting to SBF were considered not to incur costs or realize savings
in the analysis. EPA further assumed, at proposal, only those wells that were using SBF or OBF would
potentially use SBF in the future, so all WBF wells were considered not to incur costs or realize savings in
the analysis. Based on information in the record demonstrating that drilling with SBFs was far more
efficient than drilling with WBFs, EPA examined whether certain options would create incentives for
operators to switch from WBFs to SBFs or from SBFs to WBFs.
3.1 Drilling Activity Projections and Allocations for the Final Rule
For the final rule, all SBF, OBF and WBF wells are included in the well count. EPA was able to
conduct a more detailed analysis because of increased detail in the well count data supplied by industry,
specifically, including detail on projected conversions of WBF and OBF to and from SBF under various
regulatory options. Another reason for including all wells in this well count is to maintain an overall accurate
"balance sheet" of all wells estimated to convert into or out of various model well types.
The allocation of wells among the three well types is more complicated for the final rule than for the
proposal because under BAT/NSPS Option 1 and BAT/NSPS Option 2, the conversion of WBF to SBF
wells is not a 1:1 relationship due to an increased directional drilling ability and a more rapid drilling rate for
SBF compared to WBF. Although 54 WBF wells are projected to convert to SBF, only 36 SBF wells are
projected to result from this conversion (a reduction of 18 wells, or one-third of the WBF wells converting
to SBF). Another complicating factor is that BAT/NSPS Option 3 is not simply a zero discharge analysis of
baseline well counts because 207 of the 221 new and existing source SBF wells currently in existence will
convert into 183 OBF and 24 WBF well categories. Thus, the analysis of costs and loadings for the final
rule includes all three well types to accurately present comparative data for all of the options considered.
A detailed discussion of the methodology used to apportion the different well types and estimate the
well counts for each type for this final rule is contained in Chapter IV of this document.
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3.2 Model Well Characteristics
Sections 3 and 4 of Chapter VII of this Development Document present the pollutant characteristics
and drilling waste volumes that EPA calculates on a per-well basis for four model wells. Table VII-1
presents SBF and OBF drilling waste characteristics. Table VII-2 presents the development of SBF and
OBF discharge volumes for each of the four model wells. Table VII-3 presents the input data and equations
used to generate per well volumes and loadings for SBF and OBF wastes. Table VII-4 lists the SBF and
OBF drilling fluid and drill cuttings waste volumes, based on the data and methodology in Table VII-3, that
are the basis for the compliance cost, pollutant loading, and non-water quality environmental impact
analyses. Section 4 of Chapter VII of this Development Document also presents the data and methodology
used to develop volume and loadings projections for WBF wells.
In addition to per-well waste volumes, for proposal EPA estimated the number of drilling days for
each model well over the SBF interval, using the per-well retort data provided by API.2'3 These estimated
durations represented the number of days of "active drilling" (i.e., the amount of time actually drilling) using
SBF or OBF. The estimated number of active drilling days for the well sections drilled with SBF or OBF,
at proposal, were: 3.6 days for the shallow water development (SWD) model well, 7.5 days for the shallow
water exploratory (SWE) model well, 5.4 days for the deep water development (DWD) model well, and
12.0 days for the deep water exploratory (DWE) model well. Active drilling days, however, do not
represent the entire time that the drilling rig and associated equipment are onsite. Active drilling days
comprise approximately 40% of the total time to drill, during which equipment is onsite.4 The total days to
drill (i.e., 2.5 times the number of active drilling days) are the rental periods used in equipment rental cost
estimates.
Active drilling days also were the basis for estimating waste hauling equipment requirements. Waste
hauling requirements (i.e., container rental and supply boat costs) referred to as the number of days required
to "fill and haul." This period is estimated at a duration between the active drilling days and the total time to
drill because, although this period is required for a longer time than the number of active drilling days, this
period is not required for the entire time of the drilling program. The number of days to "fill and haul" takes
into consideration, for example, the transit time for container or supply boat rental going to or from shore.
For the final rule, these estimates are revised, based on data received from industry following the
proposal. The revised number of SBF or OBF active drilling days for SWD, SWE, DWD, and DWE well
types are, respectively, 5.2 days, 10.9 days, 7.9 days, and 17.5 days. (These estimates result in an
VIII - 5
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estimated number of SBF/OBF total days to drill, respectively, of 13.0 days, 27.3 days, 19.8 days, and 43.8
days.) The number of SBF/OBF days to fill and haul for SWD, SWE, DWD, and DWE wells, respectively,
are 7.3 days, 14.2 days, 9.9 days, and 22.8 days. WBF drilling proceeds at a rate approximately half that
observed for SBF/OBF wells, therefore, these estimated drilling-related durations are doubled for cost
estimates related to WBF wells.
3.3 Onsite Solids Control Technology Costs
Costs associated with the onsite treatment of drill cuttings are estimated for the baseline and all
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 constitute the line-items in the solids control technology costs.
3.3.1 Baseline Solids Control Technology Costs
For the purpose of calculating incremental compliance costs, EPA has 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 particle sized 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
from the drilling fluid 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
determination that standard solids control systems for wells drilled with SBF most often consist of primary
and secondary shale shakers.3 As discussed in Chapter VII, EPA estimates that the OBF- or SBF-cuttings
discharged by a standard solids control system have a long-term average of 10.2% base fluid retained on
wet cuttings on a mass basis.
The line item in the baseline cost analysis for Gulf of Mexico wells for this final rule consists of the
cost of SBF/OBF/WBF lost with the discharged cuttings. [Note: The cost of WBF lost on cuttings
represents only this cost for WBF wells projected to fail their toxicity or sheen limitations.] The baseline
unit cost of SBF lost, based on the discharge of cuttings following baseline treatment (shale shakers), is
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estimated to be $221 per barrel (see below for derivation), based on current prices for IO and ester SBFs30
(compared to the estimated cost of $200 per barrel, using internal olefin as the base fluid, that was used at
proposal6'7). The volume of SBF adhering to the discharged cuttings, included in Table VII-4 for each
model well, is based on the weighted average 10.2% (g/g) 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) are attributed to the operation of solids control equipment that EPA considers to be standard in all
drilling operations, since these costs are occurring regardless of the mud type used.
3.3.2 BAT/NSPS Compliance Solids Control Technology Costs
Both BAT/NSPS Option 1 and Option 2 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 and
secondary shale shakers. The difference between Option 1 and Option 2 is not based on the use of differing
treatment technologies, which are identical for both options. The distinction between these options is based
on the inclusion (Option 1) or exclusion (Option 2) of the final fines removal units (FRUs) in developing the
Agency's long-term average SBF retention limitation. The set of technologies that are together considered
under the category of "cuttings dryers" includes vibrating centrifuges (horizontal or vertical) and for the
esters limitations also include the squeeze press units and High-G linear shakers. The technologies receive
drill cuttings from the primary shale shakers and remove additional drilling fluid from the cuttings before
they are discharged.8 These units are an add-on rather than a replacement technology.37 As discussed in
Chapter VII, retention on cuttings (ROC) data submitted to EPA for various solids control equipment yield
the long-term averages: (1) primary shale shakers have a ROC long-term average of 9.32% (g/g); (2)
secondary shale shakers have a ROC long-term average of 13.8% (g/g); (3) FRUs have a ROC long-term
average of 10.7% (g/g); (4) combined data from horizontal centrifuge and vertical centrifuge cuttings dryers
has a ROC long-term average of 3.82% (g/g); and (5) combined data from horizontal centrifuge, vertical
centrifuge, squeeze press, and High-G linear shaker cuttings dryers has a ROC long-term average of 4.8%
(g/g). The ROC limitation for SBFs with the environmental performance of internal olefins is based on
combined data from horizontal centrifuge and vertical centrifuge cuttings dryers (long-term average of
3.82%) and the ROC limitation for SBFs with the environmental performance of esters is based on
combined data from horizontal centrifuge, vertical centrifuge, squeeze press, and High-G linear shaker
cuttings dryers (long-term average of 4.8%). When added to a baseline solids control system, cuttings
dryers reduce the system-wide (i.e., cuttings dryer and FRU waste streams) long-term average retention of
base fluid on discharged cuttings to 4.03% (g/g; based on combined data from horizontal centrifuge and
vertical centrifuge cuttings dryers; see Section VII.4.2.2). Although cuttings dryers were not in wide-spread
VIII - 7
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use in the domestic U.S. offshore industry at the time of proposal, they were proven technologies with
widespread use in the North Sea. The effectiveness of this technology in pollutant removals has been
clearly demonstrated and their increased use in the Gulf of Mexico further demonstrates their effectiveness.
This equipment has been directly observed by EPA in a 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 several solids
control companies that serve the Gulf of Mexico region to develop and market a cuttings dryer 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 controlled 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 based on the daily rental cost for the cuttings dryer devices, and for the final rule is
estimated to be $2,400 per day,1 revised upwards from the $1,200 per day estimate used in the
proposal.7 The rental cost includes all equipment, labor and materials. The number of rental days
is calculated based on the assumption that active drilling days are approximately 40% of the time the
drilling equipment is onsite.4
Platform retrofit costs/installation and downtime costs: Retrofit costs were assigned to all existing
sources but not to new sources. For the final rule, EPA revised these costs from proposal in light of
more recent information as the industry has gained more experience with these technologies as wells
as a broader understanding of BAT technology installation costs, especially for deep water
operators1.1 For the final rule, an installation cost of $32,500 (the midpoint of the range of
installation costs) and a downtime cost of $24,000 (based on a downtime of 4 hours and rig time
cost of $6,000 per hour). The revised installation cost estimate is a reasonable approach as this
estimate relies on the midpoint of a range of actual cuttings dryer installation costs that cover a
variety of different cuttings dryer installations from easy to difficult and more expensive. These
costs are modified using geographic multipliers for California and Cook Inlet operations (respectfully
1.6x and 2. Ox multipliers).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
1 At proposal, the unit retrofit costs were based on an updated unit retrofit cost of $340/ft2, u a unit
footprint of 45.7 ft2, a drilling fluid holding tank footprint of 20 ft2, and a one-foot perimeter of free space around
both footprints of 8 ft2 (a total of 75 ft2 of retrofit space required).7'8
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Mexico (whose multiplier, then is I12). These multipliers primarily reflect shipping costs for
materials manufactured in the Gulf of Mexico area.
At proposal these costs were applied to each SBF well drilled. For this final rule, however, the
costs for installation and downtime were further revised to account for multiple wells drilled from
the same structure. The number of exploratory wells and development wells per structure were
developed based on the rig identifiers, well numbers, and dates of drilling provided in retention data
files submitted by industry.34 This analysis resulted in an estimated 1.6 exploratory wells per
structure and 2.2 development wells per structure.
Value of the SBF/OBF/WBF discharged with cuttings: The unit cost of SBF lost with discharged
cuttings varies between the geographic areas. In the Gulf of Mexico, the cost at proposal was $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. The
unit SBF cost in Cook Inlet was estimated to be $400/bbl, based on a multiplier of 2.
For the final rule, cost estimates for SBF, OBF, and WBF are developed from recent information
provided by industry.30 WBF is quoted at $45/bbl. OBF is quoted at $90/bbl for mineral oil and
$70/bbl for diesel. SBF costs quoted are $160/bbl, $250/bbl, and $300/bbl for IO, vegetable ester,
and low viscosity vegetable ester, respectively.
No reliable frequency of usage was available so usage is assumed simply to be inversely related to
price. Thus, a weighted average price, with the weight inversely proportional to cost, is used. The
weighted average cost per barrel is calculated as
X =
J_ J_ J_
Xl XI Xi
where x, is the cost per barrel of a given mud. Based on this analysis, the costs used for the final
rule were: $45/bbl (WBF), $221/bbl (SBF), and $79/bbl (OBF).
The unit costs of these muds are applied to the volume of SBF, OBF, or WBF lost. For SBF and
OBF, this volume reflects mud that adheres to cuttings and is discharged (SBF) or disposed (OBF);
the remainder of SBF and OBF are recovered, recycled, and reused. For WBF, this volume is the
WBF adhering to discharged cuttings, plus bulk WBF discharged during drilling operations. The
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volume of SBF and OBF adhering to the cuttings, included in Table VII-4, is based on the weighted
average retention value calculated for the add-on solids control systems, and varies with the model
well size. The volume of OBF adhering to cuttings with baseline control is estimated at 5%, based
on information from the Offshore Development Document.
โข Cost of performing the waste monitoring analyses: Analytical monitoring costs are included for the
proposed test for formation oil contamination of drill cuttings and retort analysis for SBF retention
on cuttings. The formation contamination test, estimated to cost $50 per test,13 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. A cost of $575 per sediment toxicity test, assuming one test per well, is included.
โข Cost of compliance with stock base fluid limitations: EPA has not explicitly included the monitoring
costs related to the stock limitations on synthetic base fluids (e.g., PAH content and sediment
toxicity). These costs were excluded because such costs are highly related to the number of
products brought to market, which are very difficult to predict, and because EPA considers these as
routine costs of product development.
3.4 Transportation and Onshore Disposal Costs
Costs associated with the transportation and land-based disposal of drill cuttings are 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 for the line-items in transport and land disposal costs.
3.4.1 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 onsite. As discussed in section VIII.3.1, EPA's baseline scenario
estimates that 69 Gulf of Mexico wells (67 existing sources and 2 new sources); 2 offshore California wells
(existing sources); and 2 Cook Inlet wells (existing sources) are drilled annually using OBF (see Table VIII-
4). The line-item costs in the baseline transport and disposal analysis include the following:
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Supply Boat Costs: For proposal, drill cuttings transported in supply boats were costed at a day rate
of $8,500 per day in all three geographic areas.15> 16 This cost estimate has not been revised for the
final rule. 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 effort,17 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. The number of supply boat days required has been
revised, and is given by the number of "days to fill and haul," described above.
Trucking Costs: For proposal, trucking costs were included as a separate line item for the offshore
California and coastal Cook Inlet baselines; this cost was 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 $355 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 boxes.1S Thus, for
example, a DWD model well would require an estimated 28 truckloads (1,387 bbl/50 bbl per
truckload). For the final rule, this cost estimate for California operations was not revised.
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, at proposal
costs were developed for trucking the cuttings to a facility in Oregon. This approach to zero-
discharge cost estimating for Cook Inlet was adopted from the Coastal Oil and Gas Rulemaking
effort.20 The trucking rate for Cook Inlet was calculated to be $1,917 per truckload (updated from
the 1995 cost of $1,800 per truckload used in the Coastal guidelines effort20) using an ENR CCI
ratio of 1997$/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 had a capacity of 22 tons21 and could carry eight 8-bbl cuttings
boxes. This approach has been eliminated for the final rule. Based on industry and State of Alaska
information, EPA is projecting that Cook Inlet operators will grind and inject these wastes (the
current practice).31 The final rule requires zero discharge in coastal Cook Inlet. However, the final
rule also provides that if an operator can demonstrate onsite injection is not a viable option, onsite
controlled SBF-cuttings discharges are allowed at the same level of control for Offshore operators.
The NPDES permit authority in cooperation with AOGCC will evaluate each application for a
controlled SBF-cuttings discharge on a case-by-case basis (see Appendix 1 to Subpart D of 40 CFR
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435). Thus, for the final rule, no trucking costs are included in the cost analysis for coastal Cook
Inlet wells.
Disposal and Handling Costs: In the Gulf of Mexico, at proposal an average unit disposal cost of
$10.13/bbl was calculated from 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 only includes 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
These cost estimates are not revised for the final rule.
The unit disposal cost for offshore California, for the proposal, was calculated to be $12.32/bbl,
based on a unit cost of $35/ton18 and a density (based on specified model well characteristics) of
704 Ibs/bbl cuttings. Because this disposal cost was comparable 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.,
$4.75/$10.13, or 0.47). For the final rule, these costs are been revised to reflect a change in
cuttings density (due to changed SBF base fluid retention) from 704 Ibs/bbl to 716 Ibs/bbl. The
costs used in the analysis for the final rule are $12.53/bbl for disposal and $5.89/bbl for handling.
The unit disposal cost for drilling wastes generated in coastal Cook Inlet and transported to Oregon,
at proposal 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). As was the case for trucking costs, disposal and handling costs are eliminated in the cost
analysis for the final rule due to both current industry practice and the requirements of the final rule.
Container Rental Costs: For proposal, in both the Gulf of Mexico and offshore California, 25-bbl
reusable storage boxes were found customary for transporting waste cuttings.15> 17> 24 In the Gulf of
Mexico, 25-bbl cuttings boxes rented 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 (1.6x) for California.12 For the final rule, these estimates are
unchanged.
In coastal Cook Inlet, at proposal EPA found that cuttings boxes, holding eight barrels of waste
cuttings each, had to be purchased and could not be reused.20 The purchase price was estimated at
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$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 the final rule, this cost element is eliminated from the
cost analysis, for the same reasons as discussed for trucking, disposal, and handling costs.
For both the Gulf of Mexico and offshore California, the number of cuttings boxes needed per well
varies with model well size. The number of cuttings box rental days is estimated to be equal to the
supply boat transport days, i.e., the number of "days to fill and haul."
Retention value and unit costs for SBF/OBF/WBF disposed with cuttings: In the baseline analysis at
proposal, EPA assumed that SBF/OBF cuttings transported to shore for disposal would first be
treated onsite by the baseline solids control technology to an estimated long-term average (LTA)
11% (g/g) retention of SBF/OBF on the disposed cuttings. The unit costs of OBF were estimated,
at proposal, to be $75/bbl for OBF and $200/bbl for SBF in the Gulf of Mexico,6 adjusted by
geographic multipliers12 for offshore California and coastal Cook Inlet. The volume of SBF/OBF
adhering to the disposed cuttings, based on a percentage of the retained oil varied with the model
well size as a function of cuttings volumes. For the final rule the volume of disposed muds is
revised to reflect a different projected LTA retention value (10.2% vs. 11%) and revised costs for
SBF ($221/bbl) and OBF ($79/bbl) as well as costs for disposed WBF ($45/bbl).
3.4.2 BA T/NSPS Transport and Disposal Costs
Based on information provided by the industry, at proposal 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. For the final rule, industry provided specific information on the number of SBF,
OBF, and WBF wells projected under each of the regulatory options considered, eliminating the assumption
regarding deep water wells used in the proposal.10 Using these well counts, unit transport and disposal costs
remained unchanged from proposal, and are applied to SBF and OBF wells.
3.5 Onsite Grinding and Injection Costs
Costs associated with onsite grinding and injection of drill cuttings are estimated for both baseline
and BA T/NSPS compliance levels of control. At proposal, only Gulf of Mexico operators were projected to
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employ onsite injection, although it was noted that it was an emerging technology in both offshore California
and coastal Cook Inlet.25 Based on information provided by industry sources, EPA estimated that 20% of
zero discharge wells in the Gulf of Mexico used onsite injection,25 while 80% hauled their wastes to shore.
This split remains unrevised for the final rule. Since proposal, EPA has received additional information and
is revising its zero discharge onsite:onshore allocations (see Chapter VII, Section 5.4) for offshore California
and coastal Cook Inlet. For offshore California operations, 80% of DWD, SWD, and SWE wells are
assumed to inject onsite; no DWE wells are projected to inject onsite. In addition, 100% of Cook Inlet,
Alaska operations are projected to use onsite injection to dispose of their drilling wastes.
The line-item and unit costs associated with onsite injection, at proposal, were identical for the
baseline and all BAT/NSPS compliance cost analyses. Line-item costs for the proposal included 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. At proposal, the injection system cost of $4,280 per day included all equipment, labor, and
associated services.29 At proposal, the rental days for injection equipment were calculated by the same
method used for rental of cuttings dryers (see section VIII.3.3.2), 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 model well size. At proposal, the unit cost of drilling fluid injected with the cuttings was
$75/bbl6 for wells using OBF and $200/bbl for wells using SBF.6'7 For the final rule, the day rate for the
turnkey injection unit is not changed; nor was the method for estimating the number of rental days.
However, for the final rule, the cost per barrel of SBF, OBF, and WBF have been revised (see Section
3.3.2 above).
4. DETAILED ANALYSES OF TECHNOLOGY AND INCREMENTAL COMPLIANCE
COSTS
EPA has analyzed the technology costs and incremental costs (or savings) beyond current industry
practices and requirements, as well as pollutant loadings and incremental loadings or removals. EPA has
performed these analyses for the Gulf of Mexico, offshore California, and coastal Cook Inlet, Alaska, for
baseline (current) costs and three control option costs. (Compliance costs were not developed for other
offshore regions in Alaska where oil and gas production activity exists because discharges of drill cuttings is
not expected to occur in these areas.) The three technology-based options considered are: (1) BAT/NSPS
Option 1 (controlled discharge option with discharges from the cuttings dryer and fines removal unit); (2)
BAT/NSPS Option 2 (controlled discharge option with discharges from the cuttings dryer but not the fines
removal unit); and (3) BAT/NSPS Option 3 (Zero Discharge Option). Compliance costs/savings and
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pollutant increases/removals are based on: (1) projected annual drilling activity in the three geographic
regions; (2) model well volumes and waste characteristics; and (3) technology and monitoring costs; and (4)
reductions in drilling days and recovery of SBFs.
The compliance cost analysis begins with the development of defined populations of wells on a
regional and well-type basis, develops per-well estimates from an analysis of line-item costs, and then
aggregates costs into total regional and well-type costs by applying per well costs to appropriate populations
of wells. EPA estimates baseline costs for current industry waste management practices and for compliance
with each regulatory option. EPA then calculates incremental compliance costs, which reflect the difference
between compliance costs for a regulatory option and baseline costs and the net compliance costs or savings
which incorporate the costs along with savings realized by recovering drilling fluids and more efficient
drilling. Tables VIII-2 and VIII-3, for existing and new sources respectively, list the total annual baseline
costs, compliance costs, incremental compliance costs, cost savings, and net incremental compliance costs,
calculated for each geographic area and regulatory option.
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TABLE VIII-2
SUMMARY ANNUAL AND INCREMENTAL COSTS
FOR MANAGEMENT OF SBF-CUTTINGS FROM EXISTING SOURCES
(1999$/year)
Technology Basis
Gulf of Mexico
Offshore
California
Cook Inlet,
Alaska
Total
Total Operational Costs
Baseline Costs: (Costs to Meet
Current Requirements)
BAT/NSPS Option 1: Discharge with
4.03% retention of base fluid on
cuttings
BAT/NSPS Option 2: Discharge with
3.82% retention of base fluid on
cuttings; zero discharge fines
BAT/NSPS Option 3: Zero Discharge
$39,472,159
$41,562,237
$41,742,369
$68,204,419
$413,282
$413,282
$413,282
$413,282
$516,602
$616,570
$616,570
$516,602
$40,402,042
$42,592,088
$42,772,221
$69,134,303
Costs (Savings) Due to Retention Limit
BAT/NSPS Option 1: Discharge with
4.03% retention of base fluid on
cuttings
BAT/NSPS Option 2: Discharge with
3.82% retention of base fluid on
cuttings
BAT/NSPS Option 3: Zero Discharge
$2,090,078
$2,270,210
$28,732,260
$0
$0
$0
$99,968
$99,968
$0
$2,190,046
$2,370,178
$28,732,260
Costs (Savings) Due to Efficiencies of SBF Drilling over WBF Drilling
BAT/NSPS Option 1: Discharge with
4.03% retention of base fluid on
cuttings
BAT/NSPS Option 2: Discharge with
3.82% retention of base fluid on
cuttings
BAT/NSPS Option 3: Zero Discharge
($48,832,540)
($48,832,540)
$0
$0
$0
$0
$0
$0
$0
($48,832,540)
($48,832,540)
$0
Net Incremental Costs (Savings)
BAT/NSPS Option 1: Discharge with
4.03% retention of base fluid on
cuttings
BAT/NSPS Option 2: Discharge with
3.82% retention of base fluid on
cuttings
BAT/NSPS Option 3: Zero Discharge
($46,742,462)
($46,562,330)
$28,732,260
$0
$0
$0
$99,968
$99,968
$0
($46,642,494)
($46,462,362)
$28,732,260
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TABLE VIII-3
SUMMARY ANNUAL AND INCREMENTAL COSTS FOR
MANAGEMENT OF SBF-CUTTINGS FROM NEW SOURCES
(1999$/year)
Technology Basis
Costs
(Savings)
Baseline Costs: (Costs to Meet
Current Requirements)
Discharge with 10.2% retention of base fluid
on cuttings
$2,373,970
Total NSPS Operational Costs
BAT/NSPS Option 1: Discharge with 4.03%
retention of base fluid on cuttings
BAT/NSPS Option 2: Discharge with 3.82%
retention of base fluid on cuttings; zero
discharge fines
BAT/NSPS Option 3: Zero Discharge
$2,013,387
$2,017,491
$2,749,981
Costs (Savings) Due to Retention
Limit
BAT/NSPS Option 1: Discharge with 4.03%
retention of base fluid on cuttings
BAT/NSPS Option 2: Discharge with 3.82%
retention of base fluid on cuttings; zero
discharge fines
BAT/NSPS Option 3: Zero Discharge
($360,583)
($356,479)
$376,011
Costs (Savings) Due to Efficiencies
of SBF Drilling over WBF Drilling
BAT/NSPS Option 1: Discharge with 4.03%
retention of base fluid on cuttings
BAT/NSPS Option 2: Discharge with 3.82%
retention of base fluid on cuttings; zero
discharge fines
BAT/NSPS Option 3: Zero Discharge
($2,123,505)
($2,123,505)
$0
Net Incremental Costs (Savings)
BAT/NSPS Option 1: Discharge with 4.03%
retention of base fluid on cuttings
BAT/NSPS Option 2: Discharge with 3.82%
retention of base fluid on cuttings; zero
discharge fines
BAT/NSPS Option 3: Zero Discharge
($2,484,088)
($2,479,984)
$376,011
The compliance cost analysis was a step-wise process that begins with the development of well
counts that define the well-type populations (i.e., SBF, OBF, WBF) for each geographic region in the
analysis. As discussed in section VIII. 3.1 above, 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
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three geographic areas. Table VIII-4 shows the numbers of wells, per model well type, that EPA identified
as within the scope of the cost analysis, shown separately for existing and new sources.
The next step of the analysis is the calculation of per-well costs developed from the line-item costs
detailed in section VIII.3.1 above. Referring to Table VIII-4, each component of the table represents a set
of wells for which a distinct per-well cost is calculated, based on the line-items appropriate to each set. The
per-well costs are then multiplied by the number of wells in each set, the results of which are then
aggregated to calculate the industry-wide baseline, operational costs under each regulatory scenario, and
incremental compliance costs. Appendix VIII-2 consists of the detailed worksheets that calculate the per-
well costs, organized as follows:
Worksheets 1 through 3: SBF/OBF baseline costs for existing sources in the Gulf of Mexico,
offshore California, and coastal Cook Inlet, respectively.
Worksheets 4 through 6: SBF/OBF BAT/NSPS Option 1 total discharge option costs for existing
sources in the three geographic areas (in the same order as Worksheets 1-3).
Worksheets 7 through 9: SBF/OBF BAT/NSPS Option 2 total discharge option costs for existing
sources in the three geographic areas (in the same order as Worksheets 1-3).
Worksheets 10 through 12: SBF/OBF total zero discharge option costs for transport and land-
disposal, for onsite injection, and for weighted average zero discharge costs, respectively, for
existing sources in the Gulf of Mexico.
Worksheets 13 through 15: SBF/OBF baseline, BAT/NSPS Option 1 and BAT/NSPS Option 2
total costs for new sources in the Gulf of Mexico.
Worksheets 16 through 18: SBF/OBF total zero discharge option costs for transport and land
disposal, for onsite injection, and for weighted average costs, respectively, for new sources in the
Gulf of Mexico.
Worksheet 19: SBF/OBF Zero discharge costs for small volume wastes.
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TABLE VIII-4
ESTIMATED NUMBER OF WELLS DRILLED ANNUALLY8
Cost Analysis Framework
Shallow Water
( 1,000 ft)
Develop.
Explor.
Total
Wells
Gulf of Mexico: Existing Sources
Baseline
BAT/NSPS Option I/
BAT/NSPS Option 2
BAT/NSPS Option 3 Zero
Discharge
SBF Wells
OBFWellsb
WBF Wells
SBF Wells
OBF Wells
WBF Wells
SBF Wells
OBF Wells
WBF Wells
86
42
511
124
25
479
0
128
511
51
25
298
74
15
279
0
76
298
16
0
12
17
0
11
3
8
17
48
0
36
49
0
34
8
25
51
201
67
857
264
40
803
11
237
877
Offshore California: Existing Sources e
Baseline and All Options
SBF Wells
OBFWellsb
WBF Wells
0
1
3
0
1
2
0
0
0
0
0
0
0
2
5
Coastal Cook Inlet: Existing Sources e
Baseline
BAT/NSPS Option I/
BAT/NSPS Option 2
BAT/NSPS Option 3 Zero
Discharge
SBF Wells
OBFWellsb
WBF Wells
SBF Wells
OBFWellsb
WBF Wells
SBF Wells
OBFWellsb
WBF Wells
0
1
3
1
0
3
0
1
3
0
1
1
0
1
1
0
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2
4
1
1
4
0
2
4
Gulf of Mexico: New Sources d
Baseline
BAT/NSPS Option I/
BAT/NSPS Option 2
BAT/NSPS Option 3 Zero
Discharge
SBF Wells
OBFWellsb
WBF Wells
SBF Wells
OBFWellsb
WBF Wells
SBF Wells
OBFWellsb
WBF Wells
5
2
27
8
1
25
0
7
27
0
0
0
0
0
0
0
0
0
15
0
11
16
0
10
3
8
15
0
0
0
0
0
0
0
0
0
20
2
38
24
1
35
3
15
42
The numbers in this table are a subset of the estimated number of wells drilled annually, shown in Table
IV-2.
EPA estimates that 40% of wells currently drilled using OBF and 6% of wells currently using WBF in the
Gulf of Mexico will convert to SBF use under the discharge option; 96% will convert to OBF or WBF
under NSPS Option 3 (zero discharge). See Chapter IV, Section 3 of this document.
Of the SW wells drilled in the Gulf of Mexico, EPA estimates that 5% are "new source" wells, and of the
DW wells, 50% are "new source" wells. (See Development Document for proposed SBF rule.)
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EPA estimates that no "new source" wells will be drilled in offshore California and coastal Cook Inlet.
(See Development Document for proposed SBF rule.)
Worksheets 20 through 22: WBF Zero discharge baseline costs for the Gulf of Mexico, offshore
California, and Cook Inlet, Alaska, respectively, including costs for transport and land disposal and
for onsite injection.
Worksheets 20A and 22A: WBF Zero discharge BAT/NSPS Option 1 and BAT/NSPS Option 2
costs for the Gulf of Mexico (costs for transport and land disposal and for onsite injection) and for
Cook Inlet, Alaska (onsite injection), respectively.
Worksheet 23: WBF Cost Savings Analysis.
The following sections describe the development of the per-well costs and the calculations used for each
regulatory option.
4.1 BAT Baseline Operational Costs
The cost analysis for the baseline consisted of all baseline wells listed in Table VIII-4, including
WBF,2 SBF, and OBF wells. Worksheets 1, 2, 3, 20, 21, and 22 in Appendix VIII-2 show the detailed
calculations of per well costs for each of the mud types (i.e., SBF-, OBF-, and WBF-wells) and area-wide
baseline costs for the Gulf of Mexico, offshore California, and coastal Cook Inlet, Alaska. As in all other
per well calculations, per-well costs vary proportionately with the volume of waste generated per model
well. For baseline SBF wells in the Gulf of Mexico (Worksheet No. 1), the line-item costs for discharge
following solids control to a long-term average 10.2% (g/g) retention of synthetic base fluid (section
VIII.3.3.1) is the basis of cost (this is for the cost of SBF adhering to discharge cuttings). The resulting per-
well costs are: $77,792 for an SWD well; $117,572 for a DWD well; $162,877 for an SWE well; and
$261,664 for a DWE well. There are no baseline SBF wells projected for either offshore California or
coastal Cook Inlet, Alaska.
Costs for baseline OBF wells in the Gulf of Mexico also are calculated based on a 10.2% (g/g)
retention estimate and two assumptions. The first, based on industry-provided well count projections, is
that no OBF wells are drilled in deep water. The second is that 80% of shallow water OBF wells transport
2 Note that the number of WBF wells provided in the well count enumeration contribute to effluent
loadings. However, for the cost analysis, these wells do not contribute to compliance costs because this rule
imposes no additional controls on WBF discharges.
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cuttings to shore for disposal while 20% inject cuttings onsite.25 For development and exploratory baseline,
shallow-water OBF well types, per-well costs are calculated for both disposal alternatives, i.e., both
transport and disposal and for onsite injection. Then, for each model well type, a weighted average, per
well cost is also calculated as follows:
Baseline GOM/OBF well cost = (0.8 x per well transport & disposal cost) + (0.2 x per well onsite injection
cost)
This same methodology is also used to obtain per well and weighted average per well costs of zero discharge
for Gulf of Mexico SBF wells (BAT/NSPS Option 2 and BAT/NSPS Option 3) and OBF wells
(BAT/NSPS Option 1, BAT/NSPS Option 2, and BAT/NSPS Option 3) presented below. The per well
cost for a Gulf of Mexico SWD well is $110,715 for transport and disposal and $83,448 for onsite injection;
for an SWE well, these respective costs are $236,406 and $174,853 per well. The weighted average per-
well costs for baseline OBF wells in the Gulf of Mexico (Worksheet No. 1) are $107,536 for a SWD well
and $219,201 for a SWE well. The total annual discharge option OBF baseline cost for the Gulf of Mexico
is $10,034,296.
There are no deep water wells projected for either offshore California or coastal Cook Inlet, Alaska.
EPA is revising its allocation between the two zero discharge alternatives (transport and land disposal; onsite
grind and inject), in response to information received from industry, to an onsite:onshore allocation of 80:20
for shallow water wells in offshore California and 100:0 for shallow water wells in coastal Cook Inlet. In
California, because only two baseline OBF wells are projected, both wells are costed on the basis of grind
and inject technology. Offshore California baseline costs are $133,517 for an SWD well and $279,765 for
an SWE well (Worksheet No. 2). For the same reason, both of the projected baseline wells in coastal Cook
Inlet are costed on the basis of grind and inject technology. Baseline Cook Inlet costs are estimated at
$166,896 for an SWD well and $349,706 for an SWE well (Worksheet No. 3).
The total annual baseline costs for lost SBF on cuttings from SBF wells in the Gulf of Mexico is
$29,437,863; for OBF wells it is $10,034,296. Offshore California there are no baseline SBF wells
projected; the total cost of waste disposal from OBF wells is $413,282 (Worksheet No. 2). In coastal Cook
Inlet, Alaska there also are no SBF baseline wells projected; the cost of disposal for OBF wells is $516,602
(Worksheet No. 3).
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The total baseline cost of SBF lost on cuttings is $29,437,863; the baseline (zero discharge) OBF
cost is $10,964,179. The total baseline cost for the Gulf of Mexico is $39,472,159; for offshore California
it is $413,282; for coastal Cook Inlet, Alaska it is $516,602 for a total, combined aggregate baseline cost of
$40,402,042 (Table VIII-2).
4.2 BAT/NSPS Option 1 Discharge Option Costs
The BAT/NSPS Option 1 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 long-term average retention from 10.2% to 4.03% base fluid
on wet cuttings. Worksheets 4, 5, 6, 20A, and 22A in Appendix VIII-2 present the detailed calculations of
per well costs for each of the mud types (i.e., SBF- and OBF-wells) and area-wide discharge option
compliance costs for the Gulf of Mexico, offshore California, and coastal Cook Inlet.
In the Gulf of Mexico, the unadjusted per-well discharge costs for the four model wells drilled with
SBF are $116,124 (SWD); $145,605 (DWD); $179,554 (SWE); and $252,225 (DWE). For the
BAT/NSPS Option 1 and BAT/NSPS Option 2 discharge options cost analyses for the final rule, EPA is
using an adjusted per well cost for SBF wells based on a multiple-well-per-structure factor applied to
installation and downtime costs of additional treatment technologies (see following paragraph for a
discussion of this approach). Multiple-well-per-structure, adjusted per well BAT/NSPS Option 1
compliance costs for SBF wells in the Gulf of Mexico are $85,306 per SWD well; $114,787 per DWD well;
$158,367 per SWE well; and $231,038 per DWD well. These are the costs used to develop aggregate
compliance costs (Worksheet No. 4). The total annual SBF discharge compliance cost for Gulf of Mexico,
SBF existing wells is $35,569,256 (see Table VIII-2). This increased aggregate SBF compliance cost
(approximately $6 million above the baseline cost) reflects the migration of OBF and WBF wells into the
SBF well pool.
Under the BAT/NSPS Option 1 discharge option, EPA is using the concept of an adjusted cost-per-
well, based on a multiple well-per-structure adjustment to installation and downtime costs. For the proposal,
EPA included installation and downtime costs for every SBF well drilled. For this final rule, EPA considers
this assumption to be questionable and to over-estimate compliance costs to the industry. From data
submitted with ROC data provided by industry, EPA has examined the occurrences of multiple wells being
drilled from the same structure. Based on this record information it is reasonable to estimate that some
number of wells will be drilled from structures that have already incurred installation and downtime costs for
VIII - 22
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add-on cuttings dryer technologies that can be used for subsequent wells drilling by the same operator
because the record indicates that this occurs. EPA's analysis of ROC data files suggests that on average 1.6
exploratory wells may be drilled per structure, while for development activities 2.2 wells per structure may
be drilled.34 For the final rule, EPA is adjusting the aggregate costs of installation and downtime by these
multiple well per structure factors.
EPA has calculated the installation and downtime costs as for the proposal (i.e., for every SBF well
drilled) but has divided these costs by using a factor of 1.6 (for exploratory wells) or 2.2 (for development
wells) to proportion the cost over the number of wells drilled. These adjusted aggregate installation and
downtime costs are allocated over all SBF wells drilled (of a given well type, i.e., deep, shallow,
development, exploratory) to determine an adjusted cost-per-well. This same approach is used in the cost
analysis for the BAT/NSPS Option 2 discharge option.
There are no projected existing source SBF wells in offshore California. The line-item BAT/NSPS
Option 1 discharge compliance cost elements for coastal Cook Inlet3 are the same as those estimated for the
Gulf of Mexico, adjusted by a geographic area multiplier (see section VIII.3.3.2). The per-well discharge
compliance cost for the single coastal Cook Inlet SBF well is $266,864 for a SWD well (Worksheet No. 6);
the per well cost of the single OBF well is $349,706 (unchanged from the baseline). The total annual SBF
BAT/NSPS Option 1 discharge option compliance cost for Cook Inlet is, therefore, $616,570; this reflects
the conversion of one OBF well to SBF and thus reflects a net increase of the same amount above Cook
Inlet baseline SBF costs.
Costs for OBF wells in the Gulf of Mexico show a decrease in the aggregate under the BAT/NSPS
Option 1 discharge option compared to baseline. This reflects the conversion of OBF wells to SBF wells.
The per well cost estimate stays the same as baseline costs under each option; it is the shifting between the
3 Note that the Cook Inlet SBF well projected under BAT/NSPS Option 1 and BAT/NSPS Option 2 is
projected to incur compliance costs based on zero discharge. The reason is that the costs of discharge are greater
than those to grind and inject. Installation and downtime costs (approx. $208,000), cuttings dryer rental costs
(approx. $62,000), and the cost of discharged SBF (approx. $53,000) total approximately $323,000, whereas
injection is projected to cost $267,000. Whether this single SBF well will be drilled is highly questionable. The
cost differential versus OBF resolves into the cost of the fluid. With OBF at about $160/bbl and SBF at about
$442/bbl, the additional cost for SBF amounts to about $100,000 per well. Without a substantial cost savings to
offset this added cost, there is little technical advantage of SBF over OBF. EPA believes it quite likely that there
will be no discharge of SBF in Cook Inlet even under BAT/NSPS discharge options. Instead, EPA believes
operators will very likely choose to manage SBF wastes as they now manage OBF wastes, and at no additional cost
under the discharge options. However, the increased costs of drilling an SBF well have been included in this
analysis as a conservative factor in the assessment of the cost of this regulation to the industry.
VIII - 23
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types of wells that causes the changes in total costs under each regulatory option. The total annual OBF
(zero discharge) cost for Gulf of Mexico existing sources is $5,992,981 (Worksheet No. 4).
Costs for OBF wells offshore California, for the same reason, do not change from baseline costs.
The aggregate offshore California, OBF cost is $413,282 (the same as baseline; Worksheet No. 5). In
coastal Cook Inlet, Alaska there is a reduction in aggregate compliance costs for OBF wells that reflects the
conversion of one (SWD) OBF well to SBF. The per-well cost for an SWE well, as well as total aggregate
OBF cost, is $349,706, based on grind and inject technology.
Thus, for BAT/NSPS Option 1, the Gulf of Mexico costs, by well type, are $35,569,256 (SBF);
and $5,992,961 (OBF) for a total Gulf of Mexico BAT cost of $41,562,237. The BAT/NSPS Option 1
cost for offshore California is $413,282 (OBF); there are no BAT/NSPS Option 1 SBF wells offshore
California, thus the BAT/NSPS Option 1 total cost for offshore California is $413,282. Cook Inlet
BAT/NSPS Option 1 costs are $266,864 (SBF); $349,706 (OBF); the BAT/NSPS Option 1 total cost for
BAT/NSPS Option 1 for coastal Cook Inlet, Alaska is $616,570.
4.3 BAT/NSPS Option 2 Discharge Option Costs
Under the BAT/NSPS Option 2 discharge option, the discharge limitation is based on 3.82%
retention of SBF on cuttings as the demonstrated, long-term average retention of cuttings dryer technologies.
EPA recognizes operators may well be able to choose and operate cuttings dryer technologies whose
performance exceeds that required by this limitation, and thus be able to include the fines removal unit
(FRU) wastestream and still comply with the above requirement. However, for this cost analysis EPA has
included costs of zero discharge of FRU wastes. No difference in the well counts of WBF, SBF, or OBF
wells is projected between BAT/NSPS Option 1 and BAT/NSPS Option 2. Per-well and aggregate costs
are only slightly increased as a result of the zero discharge costs for FRU wastes, which are relatively
minimal because of the small waste volumes from FRUs.
The per well BAT/NSPS Option 2 costs for SBF wells in the Gulf of Mexico ranged from $82,346
in discharge-related (cuttings dryer) costs and $2,712 in zero discharge-related (FRU) costs for an SWD
well to $223,116 in discharge-related costs and $10,541 in zero discharge-related costs for a DWE well
(Worksheet No. 7). The per well and aggregate costs for Gulf of Mexico OBF and WBF wells are
unchanged from BAT/NSPS Option 1 estimates.
VIII - 24
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As is the case for BAT/NSPS Option 1, there are no BAT/NSPS Option 2 SBF wells projected for
offshore California, and the BAT/NSPS Option 2 compliance costs for OBF, and WBF wells offshore
California identical to costs for BAT/NSPS Option 1 and the baseline.
In coastal Cook Inlet, SBF BAT/NSPS Option 2 costs are identical to BAT/NSPS Option 1 costs.
An increase in the BAT/NSPS Option 2 costs due to additional FRU zero discharge disposal costs does not
occur in Cook Inlet as it does in the Gulf of Mexico. The reason is the projected SBF well is expected to
inject onsite, thus disposing of the FRU fines along with other cuttings dryer wastes (see footnote 3, page 23
for further explanation of costing onsite injection).
Thus, the BAT/NSPS Option 2 costs for Gulf of Mexico SBF and OBF wells are: $35,749,388
(SBF) and $5,992,981 (OBF) resulting in a total, aggregate Gulf of Mexico BAT/NSPS Option 2 cost of
$41,742,369. For offshore California there is no BAT/NSPS Option 2 SBF cost; the OBF cost is $413,282.
In coastal Cook Inlet, Alaska, the projected BAT/NSPS Option 2 cost is $266,864; the OBF BAT/NSPS
Option 2 cost is $349,706; and the total, aggregate Cook Inlet BAT/NSPS Option 2 cost is $616,570.
The total BAT/NSPS Option 2 SBF cost is $35,749,388; and the total BAT/NSPS Option 2 OBF
cost is $5,992,981. The combined, total cost for BAT/NSPS Option 2 is $41,742,369.
4.4 BAT/NSPS Option 3 Zero Discharge Option Costs
The zero discharge option cost analysis considers Gulf of Mexico wells identified as being drilled
with SBF or OBF. (These same well types are also included in the offshore California and coastal Cook
Inlet cost analyses.) Costs for the BAT/NSPS Option 3 zero discharge option are presented in detail in
Worksheets 10, 11, 12, and 20 for the Gulf of Mexico; in Worksheets 2 and 21 for offshore California; in
Worksheets 3 and 22 for coastal Cook Inlet, Alaska.
The costs for zero discharge in the Gulf of Mexico are based on costs of two alternatives - transport
and land disposal ("onshore") and grind and inject ("onsite") - allocated per well on a 0:100 onsite:onshore
basis for deep water wells and on a 20:80 onsite:onshore basis for shallow water wells. The zero discharge,
per-well SBF cost for DWD wells is $236,963 for onshore disposal; for DWE wells the cost is $575,921 per
well; there are no shallow water SBF wells projected under BAT/NSPS Option 3 in the Gulf of Mexico.
VIII - 25
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For OBF wells, the BAT/NSPS Option 3 per well DWD operational cost is $161,419 for onshore
disposal; for DWE wells the onshore disposal cost is $407,793 per well. For SWD wells the costs are
$110,715 for onshore disposal and $83,448 for onsite injection; for SWE wells these costs respectively, are
$236,406 and $174,853 per well.
For WBF wells, costs for transport and land disposal in the Gulf of Mexico ranged from $627,810
for an SWD well to $2,724,495 for a DWE well; costs to grind and inject ranged from $387,454 for an
SWD well to $1,235,566 for a DWE well.
The BAT/NSPS Option 3 aggregate cost for Gulf of Mexico SBF wells is $5,318,258. For OBF
wells, it is $62,886,162, for a total combined BAT/NSPS Option 3 Gulf of Mexico cost of $68,204,419.
For offshore California, the estimated cost of the two SWD OBF wells projected to grind and inject
OBF wastes show a total estimated cost of $413,282; one SWD at $133,517; and one SWE at $279,765.
In coastal Cook Inlet, Alaska projected OBF wells are also projected to use onsite grind and inject
technology. BAT/NSPS Option 3 costs in coastal Cook Inlet are the same as for the baseline. The
estimated cost for BAT/NSPS Option 3 OBF wells is $166,896 (SWD) and $349,706 (SWE) for an
aggregate cost of $516,602.
The aggregate BAT/NSPS Option 3 costs for all geographic regions are: $5,318,258 for SBF wells
and $63,816,045 for OBF wells. The total aggregate BAT technology cost is $69,134,303.
4.5 Retention on Cuttings Incremental Costs (Including Fluid Recovery/Re-use)
The incremental cost of the retention on cuttings limitations and standards is the difference between
the baseline cost and the operational costs of each option projected under the control options, as presented
in Table VIII-2. The major components of this incremental costs are: (1) the costs associated with the
treatment/disposal technology (discussed above); (2) the value of the drilling fluid discharged or disposed
with the cuttings along with the projected savings from the recovery and re-use of the drilling fluid; and (3)
the improved efficiency of drilling (reduced drilling time and hole size). The analysis also incorporates
effects of operators switching from WBF to SBF if discharge is authorized and switching from SBF to OBF
if EPA were to select zero discharge.
VIII - 26
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The incremental cost of the BAT/NSPS Option 1 discharge option that is attributable to the
retention limitation is projected to be $2,190,046. Several factors combine to produce this result. The
average per well costs of SBF wells under BAT/NSPS Option 1 are lower under baseline (approximately
$135,000 versus $146,000). This is largely due to the costs of improved cuttings dryer technologies being
offset by the cost savings from SBF lost on cuttings, which results from lower SBF retention on cuttings
achievable by the improved cuttings dryer technologies. However, these lower per well costs do not
translate into a lower aggregate cost because of an increased SBF well count if BAT/NSPS Option 1 versus
baseline (264 versus 201 SBF wells, respectively) that includes the conversion of WBF wells to SBF if SBF
discharges are authorized. Because of EPA's costing methodology, WBF wells have no associated
compliance costs related to this rule because there are no new controls established for WBF wells by this
rule. However, for WBF wells that convert to SBF wells, costs are accrued related to the control of SBF
discharges promulgated by this rule.
The BAT/NSPS Option 2 incremental cost that is attributable to the retention limitation is
$2,370,178 and thus are somewhat increased compared to BAT/NSPS Option 1. This increased cost
results from the modest costs related to zero discharge from FRUs that not incurred under BAT/NSPS
Option 1.
The BAT/NSPS Option 3 incremental cost that is attributable to the retention limitation is
$28,732,260 and reflects the costs of zero discharge of all SBF wastes.
4.6 Costs (Savings) Due to Efficiencies of SBF Drilling over WBF Drilling
4.6.1 Costs (Savings) for Operators Converting from WBF to SBF
For the proposal, EPA considered the costs of only SBF and OBF wells. An explicit assumption at
that time was that all OBF wells would convert to SBF wells; an unstated assumption of the cost analysis
was that no WBF wells would convert to SBF. This approach results in an accounting of treatment and
disposal costs for SBF wells above those modeled in the baseline analysis, but does not consider the
reduction in WBF costs associated with the WBF wells converting to SBF. Stated differently, any well
would only use one mud system over a given interval. The approach used at proposal recognized only the
additional costs related to using SBF for a given well interval but failed to recognize the cost savings of not
using WBF for that same well over the same interval. Based on information provided by industry regarding
VIII - 27
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the efficiency of SBF over WBF, projections of well counts by drilling fluid type for this final rule present a
different, and more complicated picture.10
Based on these revised well count projections, EPA estimates under either discharge option
BAT/NSPS Option 1 or BAT/NSPS Option 2, only a subset (approximately 40%) of OBF wells are
projected to convert to SBF wells. Also, there will be a subset (approximately 6%) of WBF wells that
convert to SBF wells under BAT/NSPS Option 1 or BAT/NSPS Option 2. For the final rule EPA includes
an explicit consideration of WBF wells in addition to SBF and OBF wells and these wells have been
included in the well count allocation.
With the inclusion of WBF wells into the cost analysis, EPA noted that several additional factors,
beyond those considered at proposal, needed to be addressed if EPA was to avoid double counting of WBF-
related cost elements. Three cost saving elements were identified: (1) a higher volume of WBFs discharged
than SBF; (2) reduced SBF rig time compared to WBF; and (3) zero discharge costs if WBF fail the toxicity
or sheen limitations. The first of these elements is a savings of the cost of WBF that would have been
discharged overboard during the drilling of the SBF well interval. WBFs are much less expensive than SBF
(i.e., $45/bbl versus $221/bbl). However, because discharging both WBF-cuttings (including some 5%
adherent drilling fluid) and bulk drilling fluid are current practice and authorized under NPDES permits, a far
greater volume of WBF is discharged than SBF. For example, for a DWE/SBF well, a total of 1,184 bbl of
SBF is projected to be discharged; for a DWE/WBF well, some 19,314 bbl of bulk WBF discharges, and
223 bbl of discharge fluids adhering to 4,468 bbl of wet cuttings, are projected to be discharged. Thus, the
cost of discarded SBF is $261,664 (1,184 bbl x $221/bbl). In contrast, the cost of discarded WBF is
$879,165 (19,537 bbl x $45/bbl). Converting to SBF, therefore, saves $617,501 in drilling fluid cost per
conversion.
A second cost factor that is associated with operational characteristics of WBF- versus SBF-related
wells is that SBF programs are much shorter than WBF programs. This results from several factors: a
higher rate of penetration (ROP); fewer technical difficulties (e.g., stuck pipe, severe washout); and the
ability to drill at higher deviations during directional drilling. The end result of this difference between WBF
and SBF systems is reflected in an approximately two-fold increase in the overall drilling rate afforded by
SBF.10 These factors translate into shorter drilling programs that lower rig costs (normally a day-rate
expense for offshore operators) and/or fewer wells to be drilled due to greater directional drilling capabilities.
VIII - 28
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The third factor related to the WBF system is that a certain percentage of WBF wells can be
expected to fail their sheen or aquatic toxicity limitations. These wells require onsite injection or onshore
disposal. These are WBF zero discharge-related disposal costs that would not be incurred for wells
converting to SBF. Information available on the failure rate of WBF wells could be found in the
Development Document for the offshore effluent limitations guidelines. Based on information in the
Development Document, a weighted average failure rate of 10.7% can derived. EPA, however, considers
the information upon which this parameter is based insufficiently reliable for application to current drilling
operations and for inclusion as a formal element in its cost analysis. The Agency has, instead, considered
this Offshore Development Document-derived failure rate as the maximum possible value, and has only
assessed its impact in ancillary analyses.32 In the cost analysis presented in this document, this cost element
has been omitted. The net effect of this factor is to reduce overall costs to the industry. Thus, omitting this
factor effectively constitutes a 0% failure rate, presenting a conservative approach to EPA's cost analysis.
The analysis of these three factors are presented in Worksheet No. 23, Appendix VIII-2. A savings
of $15,552,540 in the cost of discharged WBF is projected. The reduction in rig time-associated costs is
projected at $33,280,000 (based on WBF well intervals requiring twice as long to complete per well, times
the number of WBF projected to convert to SBF wells, and an estimated average day rate of $80,000 (a
conservative estimate for the spectrum of offshore rig costs likely in the Gulf of Mexico). A total aggregated
cost savings of $48,832,540 is projected from these three factors related to WBF versus SBF systems.
4.6.2 Cost Impacts to Operators Currently Using SBFs
Operators currently using certain SBFs may not be able to pass all stock base fluid and SBF-
cuttings limitations for discharge. These operators will not be afforded the cost savings described above for
operators converting from WBF to SBF. EPA has evaluated the costs to these operators. Costs per well
were calculated for conversion from the least expensive SBF EPA has used in its cost analyses (i.e., IO at
$160/bbl) to the most expensive SBF (i.e., low viscosity ester at $300/bbl). These incremental per well
costs are $43,887 (DWD); $63,567 (OWE); $48,018 (SWD); and $60,118 (SWE) under BAT/NSPS
Option 1. For BAT/NSPS Option 2 the incremental per well costs are $44,267 (DWD); $65,857 (OWE);
$47,685 (SWD); and $61,129 (SWE).
In addition, EPA considered these operators as part of the Economic Analysis conducted for the
final rule. In this analysis, only shallow water SBF wells show a cost increase because the additional
recovery of SBF is not sufficient to offset the cost of the equipment; shallow wells use less drilling fluid than
VIII - 29
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deeper wells. The increase, however, is three-tenths of one percent. A certain percentage of wells might
incur a higher cost for SBFs that meet the stock limitations over SBFs that do not. EPA also examined this
type of increase by modeling a cost increase from $160/bbl for the SBF and a primary shale shaker to
$300/bbl for the SBF and a cuttings dryer4. For shallow water wells, the incremental cost was $48,000 for
a development well (compared to a $2.9 million total baseline drilling cost) and $61,000 for an exploratory
well (compared to a $4.9 million total baseline drilling cost).
In other words, the extremely conservative assumptions lead to no more than a 1.7 percent increase
in the total drilling cost. It is unlikely that such a small increase in total drilling cost would affect the decision
whether or not to drill. It would only make sense not to drill a well if the difference in estimated net present
values of a project with and without that well is less than the incremental cost of the more expensive fluid
for that well. This might happen when wells are drilled into marginal fields. To examine the highest number
of operations that might be affected by increased drilling fluid costs, EPA examined the number of wells per
year that have been drilled recently using SBFs in shallow water operations, i.e, where SBF formulations
might have to be changed to meet the BAT requirements. EPA identified about 40 wells in this category,
about 3 percent of all wells drilled annually in the Gulf of Mexico. Thus, no more than 3 percent of Gulf
wells would not be drilled. Because it is likely that any wells not drilled would be in marginal fields, lost
production would most likely be far less than 3 percent of Gulf production. There is the social cost of the
lost production as well (which does not affect the operator), but that should be small relative to the total
recoverable production in the Gulf, since it would affect a relatively small number of wells and these are
wells drilled into marginal fields.
4.7 Net Incremental BAT Costs/Savings
Net incremental BAT costs/savings are determined for this final rule. The net BAT incremental
cost for any option considered is the sum of the savings accruing from the retention limit and the savings
from using SBF instead of WBFs. Net incremental compliance costs for both discharge options reflect a
cost savings to industry. For BAT/NSPS Option 1, the net incremental cost is an overall savings of
$46,642,494. For BAT/NSPS Option 2, the net incremental cost is an overall savings of $46,462,362.
However, for BAT/NSPS Option 3, there is a net incremental cost of $28,732,260.
4The cost analysis uses a weighted average of SBF fluid costs (over $200/bbl).
VIII - 30
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4.8 NSPS Compliance Cost Analysis
Table VIII-3 lists the summary results for the NSPS cost analysis, which is conducted using the
same methodology and cost data used in the BAT cost analysis. Certain assumptions related to well count
allocations were made at proposal that are specific to the NSPS analysis, however. As shown in Table VIII-
4, EPA projects 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, offshore Alaska, and coastal Cook Inlet. New source wells are
defined in the offshore guidelines, 40 CFR 435.1 l(q). With respect to drilling, these include only
development wells; exploratory wells are excluded by definition.12'20 EPA also 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 slower expansion in Gulf of Mexico shallow water areas, EPA estimated that only 5% of
SWD wells would be new sources. These assumptions have not changed in the cost analysis for the final
rule.
The NSPS cost analysis consists of the same line-item costs as in the analysis for existing sources
with the exception for retrofit costs for the add-on, cuttings dryer technology. These retrofit costs are not
included for new platforms as these new platforms will be designed to incorporate cuttings dryers in the
solids control equipment system. Appendix VIII-2 includes six SBF/OBF/WBF worksheets that present
baseline compliance costs (Worksheet NSPS-13), BAT/NSPS Option 1 and BAT/NSPS Option 2 discharge
option costs (Worksheets NSPS-14 and NSPS-15), and zero discharge option costs (Worksheets NSPS-17,
-18 and -19) for new source wells. The per-well baseline costs for NSPS SBF wells are $117,572 for a
DWD well and $77,792 for a SWD well. For NSPS OBF wells, the cost for an SWD well (the only OBF
well type projected under NSPS) is $110,715. The total NSPS baseline cost for SBF wells is $2,152,540;
for OBF wells is $221,430; and for WBF wells is $2,714,235. The total NSPS Gulf of Mexico baseline
cost is $2,373,970.
For the BAT/NSPS Option 1 discharge option, the per-well NSPS total costs (including baseline
costs and costs of this rule) for SBF wells are $89,105 for a DWD well and $59,624 for a SWD well. For
OBF wells the cost for an SWD well (the only OBF well type projected for NSPS) is unchanged versus the
baseline cost of $110,715. The aggregate NSPS costs for BAT/NSPS Option 1 are $1,902,672 for SBF
wells and $110,715 for OBF wells. The combined aggregate cost for BAT/NSPS Option 1 is $2,013,387.
For the BAT/NSPS Option 2 discharge option the per-well NSPS operational costs for SBF wells
are $89,486 ($85,361 for the discharge portion costs; $4,125 for the zero discharge portion) for a DWD
VIII-31
-------
well and $59,370 ($56,664 for the discharge portion; $2,712 for the zero discharge portion) for an SWD
well. For OBF wells, the cost for an SWD well (the only OBF well type projected for NSPS) is unchanged
versus the baseline or BAT/NSPS Option 1 compliance cost of $110,715. The aggregate NSPS costs for
BAT/NSPS Option 2 are $1,906,776 for SBF wells and $110,715 for OBF wells. The combined aggregate
cost for BAT/NSPS Option 2 is $2,017,491.
The BAT/NSPS Option 3 zero discharge NSPS per-well costs (under existing requirements and
BAT/NSPS Option 3 requirements) for the Gulf of Mexico are based on 100% transport and land disposal
for deep water wells and 80% onshore disposal/20% onsite injection for shallow water wells. For an
SBF/DWD well, the average cost per well is $236,963 (there are no SBF/SWD wells projected under NSPS
BAT/NSPS Option 3). For OBF, the costs per well are $161,416 for a DWD well; for an SWD well costs
are $110,715 (onshore disposal) and $83,448 (onsite injection). The aggregate NSPS costs for BAT/NSPS
Option 3 are $710,889 for SBF wells and $2,039,092 for OBF wells. The combined aggregate cost for
BAT/NSPS Option 3 is $2,749,981.
The incremental costs of the NSPS options considered for this rule result in the savings of $360,583
and $356,479 under BAT/NSPS Option 1 and Option 2, respectively. However, for the BAT/NSPS Option
3 zero discharge option, there is an incremental cost of $376,011.
Also, similar to existing sources, new sources will accrue the same cost benefits of SBF over WBF,
as discussed above in Section 4.5, related to discharged WBF cost savings and rig time-related cost savings.
These projected WBF-related NSPS cost savings are $683,505 in WBF-discharge savings and $1,440,000
in rig time-related savings. (There are no projected WBF zero discharge savings, even in EPA's ancillary
analysis, because there are too few NSPS wells converting from WBF to SBF to statistically project any
sheen or aquatic toxicity limitation failures. The net incremental NSPS costs, i.e., the sum of incremental
costs and WBF-related cost savings are ($2,484,088) for BAT/NSPS Option 1 technology and ($2,479,984)
for BAT/NSPS Option 2 technology. These net incremental costs reflect a net cost savings under either
discharge option. Under BAT/NSPS Option 3 zero discharge, the net incremental NSPS cost is $376,011.
5. POLLUTANT LOADINGS (REMOVALS)
The methodology for estimating pollutant loadings and incremental pollutant loadings (removals)
effectively parallels that of the compliance cost analysis. The pollutant loadings analysis is based on the
waste volumes and number of the four model wells identified in Table VIII-4, and on the pollutant
VIII - 32
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characteristics of the drilling fluid and cuttings waste stream compiled from EPA and industry sources. The
following sections first describe the estimates and input data on which the pollutant loadings (removals)
analysis is based, followed by a detailed discussion of the methodology used to calculate the annual
incremental removals for both BAT and NSPS levels of regulatory control, and concluding with a
presentation of the results and conclusions of this analysis.
For this final rule, EPA identifies effluent removals as a distinct category of pollutant loadings
because the pollutants that are not discharged are either injected onsite or disposed onshore, and EPA is
combining effluent removals with these "zero discharge" waste loadings for the purposes of the NWQEIs.
Table VIII-5 presents a summary of total, industry-wide results, by region, for baseline loadings, both
discharge options and the zero discharge option, their compliance loadings, and incremental loadings
(removals). These results are discussed in Sections 5.2 through 5.6, which respectively present baseline and
the BAT and NSPS options.
5.1 Input Data and Methodology
5.1.1 SBF and OBF Pollutant Loadings (Removals) in Effluent Discharges, Land Disposal, and
Injected Waste
To calculate pollutant loadings and incremental pollutant loadings (or removals), EPA characterizes
the drilling fluid cuttings waste stream in terms of pollutant concentrations, estimates per well pollutant
loadings, and projects regional and industry-wide loadings based on per well loadings and well count
projections. Incremental pollutant loadings (or removals) are the projected loadings of the various
regulatory options under consideration minus the projected baseline pollutant loadings. Effluent loadings are
considered separate and distinct from "zero discharge" loadings, which are wastes managed via onsite
injection and land disposal. These latter types of waste are included in this section to provide a multi-media
perspective of waste generation under each SBF-cuttings regulatory option. These waste volumes are also
described in the NWQEI section, Chapter IX.
Pollutants in SBF and OBF derive from three sources: the base fluid, i.e., mineral oil-based drilling
fluid or internal olefin synthetic-based drilling fluid; drill cuttings; and formation oil. Section VII. 3 of this
document presents detailed discussions of the characteristics of these sources that EPA considered in its
analysis of pollutant loadings and removals. Table VII-1 lists the pollutant concentrations that EPA uses to
calculate pollutant loadings.
VIII - 33
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In addition to pollutant concentrations, EPA estimated per-well waste volumes, as presented in
Section VII.4. EPA's derivation of model well volumes is described in Chapter VII, Section 4.2 and is
summarized in Table VII-2. Based on the drilling fluid characteristics and model well volumes, EPA derives
per well SBF/OBF waste volumes. The input data and calculations used to derive these waste volumes are
given in Table VI-3. Table VII-4 lists EPA's projected waste volumes and loadings for the four model
wells. For each model well, three sets of calculations are developed for the long-term average SBF ROC: at
10.2% (baseline), at 4.03% (BAT/NSPS Option 1), and at 3.82% (BAT/NSPS Option 2). These
calculations derive the per well volumes of mineral oil or synthetic base fluid, water, barite, dry cuttings and
formation oil in the waste stream.
VIII - 34
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TABLE VIII-5
SUMMARY TOTAL POLLUTANT LOADINGS AND INCREMENTAL LOADINGS (REMOVALS)
FOR LARGE VOLUME WASTES FROM EXISTING SOURCES
(Ibs/year)
Loadings
Gulf of
Mexico
California
Cook Inlet,
Alaska
Total
Incremental Loadings (Removals)
Gulf of
Mexico
Califo
r-nia
Cook
Inlet,
Alaska
Total
Baseline
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
2,330,975,121
11,862,178
47,448,711
2,390,286,010
9,617,040
1,945,148
0
11,562,188
8,407,772
1,945,148
0
10,352,920
2,348,999,932
15,752,474
47,448,711
2,412,201,117
BAT/NSPS Option 1 (4.03% SBF Retention)
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
2,223,130,197
7,092,172
28,368,689
2,258,591,058
9,617,040
1,945,148
0
11,562,188
8,960,568
1,316,784
0
10,277,352
2,241,707,804
10,354,104
28,368,689
2,280,430,597
(107,844,924)
(4,770,006)
(19,080,022)
(131,694,952)
0
0
0
0
552,796
(628,364)
0
(75,568)
(107,292,128)
(5,398,370)
(19,080,022)
(131,770,520)
BAT/NSPS Option 2 (3.82% SBF Retention)
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
2,215,568,632
7,092,172
35,930,254
2,258,591,058
9,617,040
1,945,148
0
11,562,188
8,944,468
1,332,884
0
10,277,352
2,234,130,139
10,370,204
35,930,254
2,280,430,597
(115,406,489)
(4,770,006)
(11,518,457)
(131,694,952)
0
0
0
0
536,696
(612,264)
0
(75,568)
(114,869,793)
(5,382,270)
(11,518,457)
(131,770,520)
BA T/NSPS Option 3 (Zero Discharge SBF)
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
2,144,121,984
36,101,236
224,633,126
2,404,856,346
9,617,040
1,945,148
0
11,562,188
8,407,772
1,945,148
0
10,352,920
2,162,146,796
39,991,532
224,633,126
2,426,771,454
(186,853,137)
24,239,058
177,184,415
14,570,336
0
0
0
0
0
0
0
0
(186,853,137)
24,239,058
177,184,415
14,570,336
VIII - 35
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The general assumptions EPA uses to develop SBF/OBF model well waste volumes and pollutant
concentrations are summarized as follows:
โข 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 SBF washout (see Section
VII.4.2.1).
Solids control equipment perform equally for both OBF- and SBF-cuttings (see Section VII.5.3).5
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);
mud density is 9.65 Ib/gal based on the above composition.
โข 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).
โข Model long-term average retention values for drilling fluid on cuttings is 10.2% for baseline wells,
4.03% for BAT/NSPS Option 1 wells, and 3.82% for BAT/NSPS Option 2 wells (see Section
VIII.4.2.3).
For SBF and OBF, the per-well waste volume and loading estimates listed in Table VII-4 are
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 for conventional pollutants (TSS; oil and grease) are then
multiplied by the numbers of wells in each option and each geographic area, as listed in Table VIII-4, to
determine total, industry-wide pollutant loadings. Incremental pollutant loadings or removals are then
calculated as the difference between baseline loadings and option loadings.
Appendix VIII-4 contains of the detailed worksheets that calculate the per well loadings (which are
the same for both existing and new sources) and the regional and industry-wide loadings and incremental
loadings (removals). All worksheets (SBF-, OBF-, or WBF-related) that are mentioned in the remainder of
Section 5 (Sections 5.2 through 5.6) are from Appendix VIII-4. The SBF/OBF analyses presented in
Appendix VIII-4 are organized as follows:
Worksheets 1 through 4: Baseline SBF/OBF effluent loadings, BAT/NSPS Option 1 effluent
loadings, BAT/NSPS Option 2 effluent loadings, and BAT/NSPS Option 3 effluent loadings for
discharges from DWD, DWE, SWD, and SWE wells, respectively.
VIII - 36
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The costs and non-water quality environmental impacts of the wastes covered by this rule are
important factors in the final determinations of this rule. As such, the quantity and fate of wastes subject to
zero discharge are important considerations in the loadings analysis for this final rule. Zero discharge wastes
have two fates: they are ground onsite and injected into compatible sub-seabed formations or they are
placed into containers, transported to shore, and disposed via landfarming or (onshore) subsurface injection.
The quantities of SBF and OBF that are subject to zero discharge are also detailed in Appendix VIII-4
worksheets. These zero discharge quantities are determined identically to discharge loadings, i.e., loadings
per well times the number of wells. These worksheets are organized as follows:
Worksheets 5 through 7: SBF/OBF onsite injection/onshore disposal loadings for existing sources in
the Gulf of Mexico, offshore California, and Cook Inlet, Alaska, respectively, including baseline,
BAT/NSPS Option 1, BAT/NSPS Option 2, and BAT/NSPS Option 3 options
Worksheets 8 through 10: SBF/OBF onsite injection/onshore disposal loadings for new sources in
the Gulf of Mexico, offshore California, and Cook Inlet, Alaska, respectively, including baseline,
BAT/NSPS Option 1, BAT/NSPS Option 2, and BAT/NSPS Option 3 options.
The per well loadings in Appendix VIII-4 are multiplied by the corresponding numbers of wells presented in
Table VIII-4.
5.1.2 WBF Well Loadings (Removals)
The derivation of waste volumes and pollutant characterization for WBF, Chapter VII, Section
4.2.5, is discussed in detail. These WBF volumes and characterizations are based on data contained in the
Development Document for the final offshore subcategory effluent limitations guidelines (EPA 821-R-93-
003).
For this final rule, EPA presents projected WBF waste volumes, conventional pollutant
concentrations (TSS and oil and grease), and nonconventional and toxic pollutant concentrations (Chapter
VII, Section 4.2.5); projected frequency of mineral oil usage for lubricity or as a spotting fluid; and
projected and the frequency of WBF failures to meet sheen or aquatic toxicity limitations. Appendix VIII-4
contains the detailed worksheets that calculate per well loadings, regional and industry-wide loadings, and
incremental loadings (removals). The organization of these WBF worksheets in Appendix VIII-4 is as
follows:
VIII - 37
-------
Worksheets 11 through 13: WBF effluent loadings from existing sources, respectively for
conventional pollutants from discharged WBF cuttings, for conventional pollutants from discharged
drilling fluid, and for nonconventional and toxic pollutants from discharged drilling fluid.
Worksheets 14 through 16: WBF effluent loadings from new sources, respectively for conventional
pollutants from WBF cuttings, for conventional pollutants from drilling fluid, and nonconventional
and toxic pollutants from drilling fluids.
5.2. Baseline Pollutant Loadings for Existing Sources
As in the cost analysis, EPA establishes a loadings baseline by calculating pollutant loadings for the
baseline wells identified in Table VIII-4. Table VIII-6, which presents the analysis for the BAT/NSPS
Option 1 discharge option, includes a presentation of projected annual baseline effluent loadings for SBF,
OBF, and WBF. For wells that currently discharge SBF (baseline SBF wells), effluent pollutant loadings are
calculated assuming current technology that treats cuttings to 10.2% retention. The total annual baseline
effluent discharge loading for SBF wells in the Gulf of Mexico is 237,890,828 Ibs; for offshore California
and coastal Cook Inlet, there are no SBF effluent loadings. Baseline OBF wells in the Gulf of Mexico,
offshore California, and coastal Cook Inlet all have baseline effluent discharge loadings of zero because
OBF wells require zero discharge. Baseline effluent loading from WBF wells in the Gulf of Mexico is
2,093,084,293 Ibs/yr; for offshore California is 9,617,040 Ibs/yr; for coastal Cook Inlet, Alaska is 8,407,772
Ibs/yr; and, in aggregate, totals 2,111,109,104 Ibs/yr. The combined SBF/OBF/WBF baseline discharge
loading for the Gulf of Mexico is 2,330,975,121 Ibs/yr; for offshore California it is 9,617,040 Ibs/yr; for
coastal Cook Inlet it is 8,407,772 Ibs/yr; and in aggregate totals 2,348,999,932 Ibs/yr.
At present no SBF operators are practicing zero discharge via onsite injection for the Gulf of
Mexico, offshore California, or coastal Cook Inlet. For OBF, the zero discharge baseline loading via onsite
injection for the Gulf of Mexico is 11,862,178 Ibs; for offshore California it is 1,945,148 Ibs; for coastal
Cook Inlet it also is 1,945,148 Ibs; and in the aggregate onsite injection of OBF totals 15,752,474 Ibs.
VIII - 38
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TABLE VIII-6
SBF, OBF, AND WBF ANNUAL BAT/NSPS OPTION 1 POLLUTANT LOADINGS AND
INCREMENTAL LOADINGS (REMOVALS) FOR LARGE VOLUME WASTES
FROM EXISTING SOURCES
(Ibs/year)
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
Total
Baseline Technology Loadings
Discharge with 10.2% retention
of SBF base fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
237,890,828
0
2,093,084,293
2,330,975,121
0
11,862,178
0
11,862,178
0
28,368,689
0
28,368,689
0
0
9,617,040
9,617,040
0
1,945,148
0
1,945,148
0
0
0
0
0
0
8,407,772
8,407,772
0
1,945,148
0
1,945,148
0
0
0
0
237,890,828
0
2,111,109,104
2,348,999,932
0
15,752,474
0
15,752,474
0
28,368,689
0
28,368,689
BAT/NSPS Option 1 Loadings
Discharge with 4.03% retention
of SBF base fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
259,628,314
0
1,963,501,883
2,223,130,197
0
7,092,172
0
7,092,172
0
47,448,711
0
47,448,711
0
0
9,617,040
9,617,040
0
1,945,148
0
1,945,148
0
0
0
0
552,796
0
8,407,772
8,960,568
0
1,316,784
0
1,316,784
0
0
0
0
260,181,110
0
1,981,526,694
2,241,707,804
0
10,354,104
0
10,354,104
0
47,448,711
0
47,448,711
Incremental Pollutant Loadings (Removals)
Discharge with 4.03% retention
of SBF base fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
21,737,486
0
(129,582,410)
(107,844,924)
0
(4,770,006)
0
(4,770,006)
0
(19,080,022)
0
(19,080,022)
0
0
0
0
0
0
0
0
0
0
0
0
552,796
0
0
552,796
0
(628,364)
0
(628,364)
0
0
0
0
22,290,282
0
(129,582,410)
(107,292,128)
0
(5,398,370)
0
(5,398,370)
0
(19,080,022)
0
(19,080,022)
VIII - 39
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There are no zero discharge baseline loading via onshore disposal of SBF for the Gulf of Mexico,
offshore California, or coastal Cook Inlet. For OBF, the zero discharge baseline loading via onshore
disposal for the Gulf of Mexico is 47,448,711 Ibs/yr; there are no offshore California or coastal Cook Inlet
OBF loadings via onshore disposal.
5.3 BAT Option 1 Pollutant Loadings (Removals) for Existing Sources
As the next step in the analysis, EPA calculated pollutant loadings resulting from a discharge
limitation based on the combined wastes of cuttings dryer add-on technology and FRUs (i.e., based on an
SBF-cuttings retention of 4.03%). As in the cost analysis, EPA estimates BAT Option 1 pollutant loadings
for the BAT Option 1 wells identified in Table VIII-4. Total annual BAT Option 1 discharge option
loadings for the Gulf of Mexico, offshore California, and coastal Cook Inlet, Alaska are shown in Table
VIII-6. Incremental pollutant loadings (removals) are calculated by subtracting baseline loadings from the
BAT Option 1 loadings.
The total annual BAT Option 1 effluent loadings for SBF wells in the Gulf of Mexico is
259,628,314 Ibs/yr; for offshore California there are no SBF effluent loadings; for coastal Cook Inlet it is
552,796 Ibs/yr; in the aggregate, SBF annual effluent loadings are 260,181,110 Ibs/yr. BAT Option 1 OBF
wells in offshore California, coastal Cook Inlet, and the Gulf of Mexico all have BAT Option 1 effluent
loadings of zero because OBF wells require zero discharge. BAT Option 1 effluent loadings from WBF
wells in the Gulf of Mexico are 1,963,501,883 Ibs/yr; for offshore California are 9,617,040 Ibs/yr; for Cook
Inlet, Alaska, are 8,407,772 Ibs/yr; and in aggregate, totals 1,981,526,694 Ibs/yr. The combined
SBF/OBF/WBF BAT Option 1 effluent loadings for the Gulf of Mexico are 2,223,130,197 Ibs/yr; for
offshore California are 9,617,040 Ibs/yr; for coastal Cook Inlet are 8,960,568 Ibs/yr; and in aggregate, the
total is 2,241,707,804 Ibs/yr.
There are no zero discharge BAT Option 1 loadings via onsite injection of SBF for the Gulf of
Mexico, offshore California, or coastal Cook Inlet. For OBF, the zero discharge BAT Option 1 loading via
onsite injection for the Gulf of Mexico is 7,092,172 Ibs/yr; for offshore California it is 1,945,148 Ibs/yr; for
coastal Cook Inlet it is 1,316,784 Ibs/yr; and in the aggregate, onsite injection of OBF totals 10,354,104
Ibs/yr.
There are no zero discharge BAT Option 1 loadings via onshore disposal of SBF for the Gulf of
Mexico, offshore California, or coastal Cook Inlet. For OBF, the zero discharge BAT Option 1 loading via
VIII - 40
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onshore disposal for the Gulf of Mexico is 28,368,689 Ibs/yr; there are no onshore disposal loadings for
offshore California and coastal Cook Inlet.
The total annual BAT Option 1 incremental effluent discharge loading for SBF wells in the Gulf of
Mexico is 21,737,486 Ibs/yr; for coastal Cook Inlet it is 552,796 Ibs/yr; in the aggregate, SBF annual loading
is 22,290,282 Ibs/yr. BAT Option 1 incremental loading from WBF wells in the Gulf of Mexico is
(129,582,410) Ibs/yr. The combined SBF/OBF/WBF BAT Option 1 incremental discharge loading for the
Gulf of Mexico is (107,844,924) Ibs/yr; for coastal Cook Inlet is 552,796 Ibs/yr; and in aggregate, the total is
(107,292,128) Ibs/yr.
There are no zero discharge BAT Option 1 incremental loadings via onsite injection of SBF for the
Gulf of Mexico, offshore California, or coastal Cook Inlet. For OBF, the zero discharge BAT Option 1
incremental loading via onsite injection for the Gulf of Mexico is (4,770,006) Ibs/yr; for coastal Cook Inlet it
is (628,364) Ibs/yr; and in the aggregate onsite injection of OBF totals (5,398,370) Ibs/yr.
There are no zero discharge BAT Option 1 incremental loadings via onshore disposal of SBF for
the Gulf of Mexico, offshore California, or coastal Cook Inlet. For OBF, the zero discharge BAT Option 1
incremental loading via onshore disposal for the Gulf of Mexico is (19,080,022) Ibs/yr.
5.4 BAT Option 2 Pollutant Loadings (Removals) for Existing Sources
In addition to baseline and BAT Option 1 loadings, EPA calculated pollutant loadings resulting from
a discharge limitation based solely on the wastes of cuttings dryer add-on technology (i.e., based on an SBF-
cuttings retention of 3.82%). As in the cost analysis, EPA establishes BAT Option 2 pollutant loadings for
the BAT Option 2 wells identified in Table VIII-4. Total annual BAT Option 2 discharge option loadings
for the Gulf of Mexico, offshore California, and coastal Cook Inlet, Alaska are shown in Table VIII-7.
Incremental pollutant loadings (removals) are calculated by subtracting baseline loadings from the BAT
Option 2 loadings.
The total annual BAT Option 2 effluent loadings for SBF wells in the Gulf of Mexico is
252,066,749 Ibs/yr; for offshore California it is zero; for coastal Cook Inlet it is 536,696 Ibs/yr; in the
aggregate, SBF annual effluent loadings are 252,603,445 Ibs/yr. BAT Option 2 OBF wells in offshore
California, coastal Cook Inlet, and the Gulf of Mexico all have BAT Option 2 loadings of zero because OBF
wells require zero discharge. BAT Option 2 effluent loadings from WBF wells in the Gulf of Mexico are
VIII - 41
-------
1,963,501,883 Ibs/yr; for offshore California are 9,617,040 Ibs/yr; for Cook Inlet, Alaska, are 8,407,772
Ibs/yr; and in aggregate totals 1,981,526,694 Ibs/yr. The combined SBF/OBF/WBF BAT Option 2 effluent
loadings for the Gulf of Mexico are 2,215,568,632 Ibs/yr; for offshore California are 9,617,040 Ibs/yr; for
coastal Cook Inlet are 8,944,468 Ibs/yr; and in aggregate, the total is 2,234,130,139 Ibs/yr.
The zero discharge BAT Option 2 loading via onsite injection of SBF is zero for the Gulf of Mexico
and offshore California; for coastal Cook Inlet it is 16,100 Ibs/yr. For OBF, the zero discharge BAT Option
2 loading via onsite injection for the Gulf of Mexico is 7,092,172 Ibs/yr; for offshore California it is
1,945,148 Ibs/yr; for coastal Cook Inlet it is 1,316,784 Ibs/yr; and in the aggregate onsite injection of OBF
totals 10,354,104 Ibs/yr. The combined SBF/OBF/WBF BAT Option 2 zero discharge via onsite injection
loadings for coastal Cook Inlet are 1,332,884 Ibs/yr; and in aggregate totals 10,370,204 Ibs/yr.
VIII - 42
-------
TABLE VIII-7
SBF, OBF, AND WBF ANNUAL BAT OPTION 2 POLLUTANT LOADINGS AND
INCREMENTAL LOADINGS (REMOVALS) FOR LARGE VOLUME WASTES
FROM EXISTING SOURCES
(Ibs/year)
Gulf of Mexico
Offshore
California
Cook Inlet,
Alaska
Total
Baseline Technology Loadings
Discharge with 10.2% retention
of SBF base fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
237,890,828
0
2,093,084,293
2,330,975,121
0
11,862,178
0
11,862,178
0
28,368,689
0
28,368,689
0
0
9,617,040
9,617,040
0
1,945,148
0
1,945,148
0
0
0
0
0
0
8,407,772
8,407,772
0
1,945,148
0
1,945,148
0
0
0
0
237,890,828
0
2,111,109,104
2,348,999,932
0
15,752,474
0
15,752,474
0
28,368,689
0
28,368,689
BAT/NSPS Option 2 Loadings
Discharge with 3.82% retention
of SBF base fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
252,066,749
0
1,963,501,883
2,215,568,632
0
7,092,172
0
7,092,172
7,561,565
28,368,689
0
35,930,254
0
0
9,617,040
9,617,040
0
1,945,148
0
1,945,148
0
0
0
0
536,696
0
8,407,772
8,944,468
16,100
1,316,784
0
1,332,884
0
0
0
0
252,603,445
0
1,981,526,694
2,234,130,139
16,100
10,354,104
0
10,370,204
7,561,565
28,368,689
0
35,930,254
Incremental Pollutant Loadings (Removals)
Discharge with 3.82% retention
of base fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
14,175,921
0
(129,582,410)
(115,406,489)
0
(4,770,006)
0
(4,770,006)
7,561,565
(19,080,022)
0
(11,518,457)
0
0
0
0
0
0
0
0
0
0
0
0
536,696
0
0
536,696
16,100
(628,364)
0
(612,264)
0
0
0
0
14,712,617
0
(129,582,410)
(114,869,793)
16,100
(5,398,370)
0
(5,382,270)
7,561,565
(19,080,022)
0
(11,518,457)
VIII - 43
-------
The zero discharge BAT Option 2 loading via onshore disposal of SBF, OBF, or WBF only occur
in the Gulf of Mexico. For SBF, the BAT Option 2 loading via onshore disposal is 7,561,565 Ibs/yr; for
OBF, BAT Option 2 loading via onshore disposal is 28,368,689 Ibs/yr. The combined SBF/OBF/WBF
BAT Option 2 zero discharge via onshore disposal loadings for the Gulf of Mexico is 35,930,254 Ibs/yr.
The total annual BAT Option 2 incremental effluent discharge loading for SBF wells in the Gulf of
Mexico is 14,175,921 Ibs/yr; for coastal Cook Inlet it is 536,696 Ibs; in the aggregate, SBF annual effluent
loading is 14,712,617 Ibs/yr. There are no OBF BAT Option 2 incremental effluent discharge loadings
because OBF wells require zero discharge. BAT Option 2 incremental effluent loadings from WBF wells in
the Gulf of Mexico are (129,582,410) Ibs/yr. The combined SBF/OBF/WBF BAT Option 2 incremental
effluent discharge loadings for the Gulf of Mexico are (115,406,489) Ibs/yr; for coastal Cook Inlet are
536,696 Ibs; and in aggregate totals (114,869,793) Ibs/yr.
The zero discharge BAT Option 2 incremental loading via onsite injection of SBF for coastal Cook
Inlet is 16,100 Ibs/yr. For OBF, the zero discharge BAT Option 2 incremental loading via onsite injection
for the Gulf of Mexico is (4,770,006) Ibs/yr; for coastal Cook Inlet it is (628,364) Ibs/yr; and in the
aggregate onsite injection of OBF totals (5,398,370) Ibs/yr. The combined SBF/OBF/WBF BAT Option 2
incremental zero discharge via onsite injection loadings for coastal Cook Inlet are (612,264) Ibs/yr; and in
aggregate totals (5,382,270) Ibs/yr.
Zero discharge BAT Option 2 incremental loadings via onshore disposal of SBF, OBF, or WBF
only occurs for the Gulf of Mexico. For SBF, the zero discharge BAT Option 2 incremental loading via
onshore disposal for the Gulf of Mexico is 7,561,565 and for OBF it is (19,080,022) Ibs/yr. The combined
SBF/OBF/WBF BAT Option 2 incremental zero discharge via onshore disposal loading for the Gulf of
Mexico is (11,518,457) Ibs/yr.
5.5 BAT Option 3 Zero Discharge Pollutant Loadings (Removals) for Existing Sources
As in the compliance cost analysis, EPA establishes BAT Option 3 pollutant loadings for the BAT
Option 3 wells identified in Table VIII-4. Table VIII-8 summarizes the results for SBF, OBF, and WBF
BAT Option 3 compliance and incremental loadings. WBF drilling has a washout rate approximately 6
times greater than either SBF or OBF drilling due to the properties of WBF (e.g., hole stability, lack of shale
VIII - 44
-------
inhibition). Therefore, operators that switch from SBF to WBF under the zero discharge option for SBF-
cuttings will discharge more cuttings.
The total annual BAT Option 3 loading for WBF wells in the Gulf of Mexico are 2,144,121,984
Ibs/yr; for offshore California, are 9,617,040 Ibs/yr; for Cook Inlet, Alaska, are 8,407,772 Ibs/yr; and in
aggregate, the total is 2,111,109,104 Ibs/yr.
The zero discharge BAT Option 3 loading via onsite injection of SBF is zero for the Gulf of
Mexico, offshore California, and coastal Cook Inlet. For OBF, the zero discharge BAT Option 3 loading via
onsite injection for the Gulf of Mexico is 36,101,236 Ibs/yr; for offshore California it is 1,945,148 Ibs/yr; for
coastal Cook Inlet it is 1,945,148 Ibs/yr; and in the aggregate onsite injection of OBF totals 39,991,532
Ibs/yr.
The zero discharge BAT Option 3 loading via onshore disposal of SBF, OBF, and WBF occurs
only in the Gulf of Mexico. For SBF, it is 19,766,219 Ibs/yr and for OBF it is 204,866,907 Ibs/yr. The
combined SBF/OBF/WBF BAT Option 3 zero discharge via onshore disposal loading for the Gulf of
Mexico is 224,633,126 Ibs/yr.
The total annual BAT Option 3 incremental loading for SBF, OBF, and WBF wells, whether for
discharge, zero discharge via onsite injection, or zero discharge via onshore disposal, only occur in the Gulf
of Mexico. For SBF, BAT Option 3 incremental discharge loading is (237,890,828) Ibs/yr. For OBF, there
is no incremental loading because OBF wells require zero discharge. BAT Option 3 incremental loading
from WBF wells in the Gulf of Mexico is 51,037,691 Ibs/yr. The combined SBF/OBF/WBF BAT Option 3
incremental discharge loadings for the Gulf of Mexico is (186,853,137) Ibs/yr.
The zero discharge BAT Option 3 incremental loading via onsite injection of SBF for the Gulf of
Mexico is zero; for OBF, the zero discharge BAT Option 3 incremental loading via onsite injection for the
Gulf of Mexico is 24,239,058 Ibs/yr.
VIII - 45
-------
TABLE VIII-8
SBF, OBF, AND WBF ANNUAL BAT OPTION 3 POLLUTANT LOADINGS AND
INCREMENTAL LOADINGS (REMOVALS) FOR LARGE VOLUME WASTES
FROM EXISTING SOURCES (Ibs/year)
Gulf of
Mexico
Offshore
California
Cook Inlet,
Alaska
Total
Baseline Technology Loadings
Discharge with 10.2% retention
of SBF base fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
237,890,828
0
2,093,084,293
2,330,975,121
0
11,862,178
0
11,862,178
0
28,368,689
0
28,368,689
0
0
9,617,040
9,617,040
0
1,945,148
0
1,945,148
0
0
0
0
0
0
8,407,772
8,407,772
0
1,945,148
0
1,945,148
0
0
0
0
237,890,828
0
2,162,146,796
2,348,999,932
0
15,752,474
0
15,752,474
0
28,368,689
0
28,368,689
BA T Option 3 Loadings
Zero discharge of SBF base
fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
0
0
2,144,121,984
2,144,121,984
0
36,101,236
0
36,101,236
19,766,219
204,866,907
0
224,633,126
0
0
9,617,040
9,617,040
0
1,945,148
0
1,945,148
0
0
0
0
0
0
8,407,772
8,407,772
0
1,945,148
0
1,945,148
0
0
0
0
0
0
2,162,146,796
2,162,146,796
0
39,991,532
0
39,991,532
19,766,219
204,866,907
0
224,633,126
Incremental Pollutant Loadings (Removals)
Zero discharge of SBF base
fluid on cuttings
Zero Discharge via onsite
injection
Zero Discharge via land
disposal
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
(237,890,828)
0
51,037,691
(186,853,137)
0
24,239,058
0
24,239,058
19,766,219
157,418,196
0
177,184,415
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
(237,890,828)
0
51,037,691
(186,853,137)
0
24,239,058
0
24,239,058
19,766,219
157,418,196
0
177,184,415
VIII - 46
-------
The zero discharge BAT Option 3 incremental loading via onshore disposal of SBF for the Gulf of
Mexico is 19,766,219 Ibs/yr; for OBF, it is 157,418,196 Ibs/yr; for WBF it is 4,931,441. The combined
SBF/OBF/WBF BAT Option 3 incremental zero discharge via onshore disposal loadings for the Gulf of
Mexico totals 182,115,856 Ibs/yr.
5.6 Pollutant Removals Analysis for New Sources
The method of estimating pollutant loadings and removals for new sources is the same as described
above for existing sources. As shown in Table VIII-4, EPA projects that 60 new source wells will be
annually drilled in the Gulf of Mexico. Table VIII-9 summarizes the baseline loadings, regulatory option
loadings, and incremental compliance pollutant loadings (removals) for new source wells. Table VIII-10
details the SBF, OBF, and WBF NSPS loadings for discharge and zero discharge options, for the baseline
and the three options considered.
The total annual baseline NSPS effluent discharge loading for SBF wells in the Gulf of Mexico is
17,405,127 Ibs/yr. Baseline OBF wells in the Gulf of Mexico have NSPS baseline discharge loadings of
zero because OBF wells require zero discharge. Baseline loading from WBF wells in the Gulf of Mexico is
92,903,606 Ibs/yr. The combined SBF/OBF/WBF baseline NSPS discharge loading for the Gulf of Mexico
is 110,308,733 Ibs/yr.
The zero discharge NSPS baseline loading via onsite injection for SBF and OBF in the Gulf of
Mexico is zero. The zero discharge NSPS baseline loading via onshore disposal of SBF for the Gulf of
Mexico is zero; for OBF it is 1,256,728 Ibs/yr.
VIII - 47
-------
TABLE VIII-9
SUMMARY TOTAL POLLUTANT LOADINGS AND INCREMENTAL LOADINGS (REMOVALS)
FOR LARGE VOLUME WASTES FROM NEW SOURCES
(Ibs/year)
Loadings
Gulf of
Mexico
California
Cook Inlet,
Alaska
Total
Incremental Loadings (Removals)
Gulf of
Mexico
California
Cook
Inlet,
Alaska
Total
Baseline
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
110,308,733
0
1,256,728
111,565,461
0
0
0
0
0
0
0
0
110,308,733
0
1,256,728
111,565,461
NSPS Option 1 (4.03% SBF Retention)
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
107,704,029
0
628,364
108,332,393
0
0
0
0
0
0
0
0
107,704,029
0
628,364
108,332,393
(2,604,704)
0
(628,364)
(3,233,068)
0
0
0
0
0
0
0
0
NSPS Option 2 (3.82% SBF Retention)
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
107,185,411
0
1,146,982
108,332,393
0
0
0
0
0
0
0
0
107,185,411
0
1,146,982
108,332,393
(3,123,322)
0
(109,746)
(3,233,068)
0
0
0
0
0
0
0
0
NSPS Option 3 (Zero Discharge SBF)
Effluent Discharge
Zero Discharge
Onsite Injection
Onshore Disposal
Total
100,387,607
879,710
13,978,597
115,245,913
0
0
0
0
0
0
0
0
100,387,607
879,710
13,978,597
115,245,913
(9,921,126)
879,710
12,721,869
3,680,452
0
0
0
0
0
0
0
0
(2,604,704)
0
(628,364)
(3,233,068)
(3,123,322)
0
(109,746)
(3,233,068)
(9,921,126)
879,710
12,721,869
3,680,452
VIII - 48
-------
TABLE VII-10
SUMMARY SBF, OBF, AND WBF ANNUAL BASELINE, BAT/NSPS OPTION 1,
BAT/NSPS OPTION 2, AND BAT/NSPS OPTION 3 POLLUTANT LOADINGS AND
INCREMENTAL LOADINGS (REMOVALS) FOR LARGE VOLUME WASTES
FROM NEW SOURCES (Ibs/year)
Baseline
BAT/NSPS
Option 1
BAT/NSPS
Option 2
BAT/NSPS
Option 3
Annual Loadings
Discharge with 10.2%
retention of SBF base fluid on
cuttings
Zero discharge via onsite
injection
Zero discharge via onshore
disposal
Totals
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
17,405,127
0
92,903,606
110,308,733
0
0
0
0
0
1,256,728
0
1,256,728
17,405,127
1,256,728
92,903,606
111,565,461
20,241,106
0
87,462,923
107,704,029
0
628,364
0
628,364
0
628,364
9,041,262
9,669,626
20,241,106
628,364
77,805,785
98,675,255
19,722,488
0
87,462,923
107,185,411
0
0
0
0
518,618
628,364
0
1,146,982
20,241,106
628,364
77,805,785
98,675,255
0
0
100,387,607
100,387,607
0
879,710
0
879,710
2,852,661
11,125,935
0
13,978,597
2,852,661
12,005,645
89,393,659
104,251,965
Incremental Pollutant Loadings (Removals)
Discharge with 10.2%
retention of SBF base fluid on
cuttings
Zero discharge via onsite
injection
Zero discharge via onshore
disposal
Totals
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
SBF
OBF
WBF
Total
2,835,979
0
(5,440,683)
(2,604,704)
0
0
0
0
0
(628,364)
0
(628,364)
2,835,979
(628,364)
(5,440,683)
(5,785,068)
2,317,361
0
(5,440,683)
(3,123,322)
0
0
0
0
518,618
(628,364)
0
(109,746)
2,835,979
(628,364)
(5,440,683)
(3,133,068)
(17,405,127)
0
7,484,001
(9,921,126)
0
879,710
0
879,710
2,852,661
9,869,207
0
12,721,869
(14,552,466)
10,748,917
7,484,001
3,680,453
VIII - 49
-------
The total annual NSPS 1 effluent discharge loading for SBF wells in the Gulf of Mexico is 20,241,106 Ibs/yr;
for OBF it is zero; for WBF it is 87,462,923 Ibs/yr. The combined SBF/OBF/WBF baseline effluent discharge
loading for the Gulf of Mexico is 107,704,029 Ibs/yr.
The zero discharge NSPS 1 loading via onsite injection of SBF and OBF in the Gulf of Mexico is zero. The
zero discharge NSPS 1 loading via onshore disposal of SBF in the Gulf of Mexico is zero and for OBF it is 628,364
Ibs/yr.
The NSPS 2 effluent discharge loading for SBF wells in the Gulf of Mexico is 19,722,488 Ibs/yr; for OBF it
is zero; for WBF it is 87,462,923 Ibs/yr; in aggregate, SBF/OBF/WBF discharge loadings total 107,185,411 Ibs/yr.
For the zero discharge NSPS 2 loading via onsite injection, SBF and OBF have zero loadings. The zero discharge
NSPS 2 loading via onshore disposal of SBF for the Gulf of Mexico is 518,618 Ibs/yr and for OBF it is 628,364
Ibs/yr; the aggregate onshore disposal loading of SBF/OBF/WBF is 1,146,982 Ibs/yr.
The total annual NSPS 3 zero discharge loading for SBF and OBF wells in the Gulf of Mexico is zero; for
WBF wells it is 100,387,607 Ibs/yr. For the zero discharge NSPS 3 loadings via onsite injection, there are no SBF
loadings; OBF loading is 879,710 Ibs/yr; WBF loading is 1,661,120 Ibs/yr. NSPS zero discharge loading via onshore
disposal from SBF wells in the Gulf of Mexico is 2,852,661 and for OBF it is 11,125,935 Ibs/yr. The combined
SBF/OBF/WBF NSPS 3 zero discharge loading via onshore disposal for the Gulf of Mexico is 13,978,597 Ibs/yr.
The total annual NSPS 1 incremental effluent discharge loading for SBF wells in the Gulf of Mexico is
2,835,979 Ibs/yr; for OBF it is zero; for WBF it is (5,440,683) Ibs/yr; in the aggregate, SBF/OBF/WBF incremental
loading is (2,604,704) Ibs/yr. NSPS 1 zero discharge incremental loadings via onsite injection for all SBF and OBF
wells are zero. NSPS 1 zero discharge incremental loadings via onshore disposal for SBF are zero; for OBF it is
(628,364) Ibs/yr.
The total annual NSPS 2 incremental effluent discharge loading for wells in the Gulf of Mexico is 2,317,361
Ibs/yr; for OBF it is zero; for WBF it is (5,440,683) Ibs/yr; in the aggregate, SBF/OBF/WBF loadings total
(3,123,322) Ibs/yr. There are no NSPS 2 incremental zero discharge loadings via onsite injection for SBF, OBF, or
WBF wells.
The zero discharge NSPS 2 incremental loading via onshore disposal of SBF for the Gulf of Mexico is
518,618 Ibs/yr and for OBF it is (628,364) Ibs/yr. The combined SBF/OBF/WBF NSPS 2 incremental zero discharge
via onshore disposal loading for the Gulf of Mexico is (109,746) Ibs/yr.
VIII - 50
-------
The total annual NSPS 3 effluent discharge incremental loading for SBF wells in the Gulf of Mexico is
(17,405,127) Ibs/yr; for OBF it is zero; for WBF it is 7,484,001. The combined SBF/OBF/WBF NSPS 3 zero
effluent discharge loading for the Gulf of Mexico is (9,921,126) Ibs/yr.
The zero discharge NSPS 3 incremental loading via onsite injection of SBF for the Gulf of Mexico is zero.
For OBF, the zero discharge NSPS 3 incremental loading via onsite injection is 879,710 Ibs/yr.
The zero discharge NSPS 3 incremental loading via onshore disposal of SBF for the Gulf of Mexico is
2,852,661 Ibs/yr and for OBF it is 9,869,207 Ibs/yr. The combined SBF/OBF/WBF NSPS 3 incremental zero
discharge via onshore disposal loading for the Gulf of Mexico is 12,721,869 Ibs/yr.
6. REFERENCES
1. Mclntyre, J., Pechan. 2000. Memorandum to K. Mahsman, ERG, Revised Engineering Models and
Compliance Costs for SBF Rulemaking. 2/23/00. (Record No. III.C.b.2)
2. The Pechan-Avanti Group, Worksheet regarding "Number of Days to Drill Model SBF Wells," 10/27/98
3. Annis, M.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. 8/29/97.
4. Daly, J., EPA, Memorandum regarding "October 13, 1998 Teleconference Regarding SBF Use," 10/20/98.
5. Johnston, C.A., EPA. 1999. Memorandum to File regarding Meeting Summary Notes from Newpark
Resources, Inc. Facilities Visit and Safeguard SWACO Presentation at the Louisiana Gulf Coast Oil
Exposition (LAGCOE) on 10/26/99.
6. Daly, J., EPA, Memorandum regarding "Cost of Synthetic-Based Drilling Fluids (SBF)," 1/15/99.
7. The Pechan-Avanti Group, "Demonstration of the 'Mud 10' Drilling Fluid Recovery Device at the Amoco
Marlin Deepwater Drill Site." 8/7/98.
8. Mud Recovery Systems, Ltd., Product brochure entitled "M.U.D. 10 and M.U.D. 6 Mud Recovery and
Cuttings Cleaning System," undated.
9. Mclntyre, J., Avanti Corporation, Telephone Communication Report on conversation with P. Matthews,
Newpark Drilling Fluids, regarding '"Centrifugal Dryer' for Drill Cuttings," 5/29/98.
10. Henry, L., Chevron. Memorandum to C.A. Johnston, EPA. Response to EPA Request for Additional Input
Parameter for EPA Modeling. 9/11/00. (Record No. IV.B.a.9)
11. Engineering News Record, "Construction Cost Index History (1908-1997)," website address
http://www.enr.com/cost/costcci.htm, June 8, 1998.
VIII-51
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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, J., The Pechan-Avanti Group, Telecommunication Report on conversation with J. Candler, M-I
Drilling Fluids, regarding "Cost Estimates for Proposed RPE Method," 10/16/98.
14. Annis, M.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, K., 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, K., The Pechan-Avanti Group, Telecommunications Report on conversation with George Bano,
Sea Mar Management, regarding "Offshore supply boat costs and specifications," 6/3/98.
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, J., The Pechan-Avanti Group, Telecommunications Report on conversation with D. Stankey,
McKittrick Solid Waste Disposal Facility, regarding "California Prices for Land Disposal of Drilling Wastes,"
October 16,1998.
19. Montgomery, R., The Pechan-Avanti Group, Telecommunication Report on conversation with S. 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." 5/9/98.
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, J., SAIC, Telecon on conversation with Josh Stenson, Carlisle Trucking, regarding "Costs to Truck
Wastes from Kenai, Alaska to Arlington, Oregon." 5/23/95.
22. Newpark Environmental Services, Facsimile of Price List, Effective May 1, 1998, from L.L. Denman to K.
Kennedy. 5/26/98
23. U.S. Liquids of Louisiana, Facsimile of Price List, from "Betty" to Jamie Mclntyre. 5/26/98.
24. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with personnel at
Frances Torque Service, regarding "Cuttings box rental costs (Gulf of Mexico area)," 6/4/98.
25. Veil, J.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 J.
Daly, EPA. 8/7/98
VIII - 52
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27. Daly, J., 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)." 1/14/99.
28. Avanti. 2000. Memorandum to File, Assessment of Numbers of Wells Drilled per Structure in the Gulf of
Mexico. 9/18/00. (Record No. IV.B.a.14)
29. The Pechan-Avanti Group, Worksheet regarding "Calculation of Daily Onsite Injection Cost. 10/30/98.
30. Candler, J., M-I Drilling Fluids. Email to C.A. Johnston RE: unit costs for various muds. 10/23/00. (Record
No. IV.B.a.13)
31. Mahan, W., AOGCC. Email to C.A. Johnston, EPA, Re: two more questions concerning Cook Inlet disposal
practices. 8/2/00. (Record No. IV.B.b.23)
32. Avanti Corporation. Memorandum to B. Vanatta, ERG. WBF Failure Rate Ancillary Cost Analysis.
12/27/00. (Record No. IV.C.B.3)
VIII - 53
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CHAPTER IX
NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND
OTHER FACTORS
1. 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
evaluates 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 are also considered. For these regulations, EPA also evaluates non-water quality
environmental impacts on a geographic as well as an industry-wide basis.
2. SUMMARY OF NON-WATER QUALITY ENVIRONMENTAL IMPACTS
For the baseline and regulatory options developed for these regulations, EPA analyzes the costs and
pollutant loadings/removals for water-based drilling fluids (WBF) and WBF cuttings, oil-based drilling fluid
(OBF) cuttings, and synthetic-based drilling fluid (SBF) cuttings in the three geographic areas: the Gulf of
Mexico, offshore California, and coastal Cook Inlet, Alaska (see Chapter VIII). Non-water quality
environmental impacts (NWQEI) are estimated for the technologies that are the basis for the baseline and all
regulatory options and geographic areas. The control technologies considered for drill cuttings treatment and
disposal are 1) use of add-on solids control devices to reduce the amount of adhering SBF in the cuttings
waste stream (for both discharge options); and 2) a combination of transportation of drill cuttings to shore
for disposal and/or onsite grinding and subsurface injection for the zero discharge option. To assess
incremental impacts of each option, baseline impacts of current solids control technologies and practices for
WBF, OBF, and SBF are determined. The incremental reductions of NWQEI associated with the treatment
and control of these wastes from existing sources and new sources are summarized in Table IX-1.
IX-1
-------
For both existing and new sources combined, EPA estimates air emissions to be reduced from
baseline levels by a total of 3,579 tons per year under BAT/NSPS Option 1 and 3,483 under BAT/NSPS
Option 2; under BAT/NSPS Option 3 (zero discharge) air emissions would increase by 2,389 tons per year.
As compared to the zero discharge option (BAT/NSPS Option 3) air emissions are reduced by 5,968 tons
per year under BAT Option 1 or 5,872 tons per year under BAT/NSPS Option 2. In addition, EPA
projects that 37,519 BOB or 381,321 BOB less fuel are used under BAT/NSPS Options 1 or 2 than under
BAT/NSPS Option 3 (zero discharge), respectively (see Table IX-1).
EPA assumed for the proposal and NODA analyses that SBFs replaced all OBF usage. The
inclusion of WBF use into the analysis for the final rule is based on information provided by industry
indicating that not all OBF wells are projected to convert to SBF. Furthermore, this information indicated
that SBFs are used to replace WBFs in certain drilling situations and are even used to drill the entire well as
opposed to just specific intervals.: Industry also has commented that drilling can occur faster using SBFs
instead of WBFs, thereby reducing drilling time and associated fuel and air emissions.1
Other reductions in NWQEIs 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 discharges under BAT/NSPS Options 1 and 2, respectively compared to BAT/NSPS
Option 3 (zero discharge) would decrease the amount of cuttings disposed at land-based facilities by 37.4
million tons and 36.2 million tons per year; and the amount disposed by injection by 197 million tons and
190 million tons per year. The methodology used to arrive at these results is described in the sections that
follow.
3. 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 loadings analyses presented in Chapter VIII.
In general, EPA estimated energy requirements by calculating the fuel consumption (in terms of fuel
usage rate) of the equipment and activities associated with each of the regulatory options. Fuel usage rate is
expressed as barrels of oil equivalents (BOE) because the fuel source for cuttings management can
IX-2
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TABLE IX-1
SUMMARY OF ANNUAL NWQEI FOR DRILL CUTTINGSa
Option
Increased Air
Emissions
(tons/yr)
Increased
Fuel Usage
(BOE/yr) b
Increased Solid Waste Disposed
(MM pounds/yr) c
Existing Sources
BAT/NSPS Option 1
BAT/NSPS Option 2
Zero Discharge
(3,172)
(3,073)
5,602
(202,165)
(195,124)
358,664
(24,478,392)
(16,900,727)
201,423,473
New Sources
BAT/NSPS Option 1
BAT/NSPS Option 2
Zero Discharge
136
145
528
(6,330)
(5,693)
18,067
(628,364)
(109,746)
12,721,869
Total (Existing and New Sources)
BAT/NSPS Option 1
BAT/NSPS Option 2
Zero Discharge
(3,036)
(2,928)
6,130
(208,495)
(200,817)
376,731
(25,106,756)
(17,010,473)
214,145,342
The positive numbers in this table represent increased impacts as measured from the baseline, and the
numbers in parentheses represent decreased 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.
Landfill and subsurface injection.
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 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 byfirst determining the
power requirement of the equipment (expressed in horsepower) and multiplying it by the natural gas usage
rate (see Section 3.2.3 for details). For natural gas, the conversion factor to BOE is 1,000 standard cubic
feet (scf) = 0.178 BOE.2
EPA estimated air emissions of operations associated with the baseline and each of the regulatory
options and daily drilling rig operations 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.
IX-3
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As in the cost analysis, energy requirements and air emissions are estimated using a step-wise
methodology. First, impacts are determined for current baseline activities (see sections VIII.3.1.1 and
VIII.3.2 for full discussions of baseline activities). Then compliance impacts are estimated from the
activities associated with each of the regulatory options (two controlled discharge options and zero
discharge). Finally, the incremental impacts for each of the options are calculated by subtracting the
baseline impacts from the compliance impacts. Table IX-2 presents the results of each of these steps for
both air emissions and fuel usage.
TABLE IX-2
SUMMARY OF BASELINE AND BAT/NSPS OPTIONS AIR EMISSIONS AND FUEL USAGE
FOR EXISTING SOURCES
Option
Air Emissions (tons/yr)
Gulf of
Mexico
Offshore
CA
ci,
Alaska
Total
Fuel Usage (BOE/yr)
Gulf of
Mexico
Offshore
CA
CI,
Alaska
Total
Baseline Emissions and Fuel Usage
SBF and WBF Wells
OBF Wells (Zero
Discharge)
Total Baseline
88,310
3,026
91,336
434
94
528
307
93
400
89,051
3,213
92,264
5,632,162
193,280
5,825,442
27,662
6,138
33,800
19,600
6,067
25,667
5,679,42
4
205,485
5,884,90
9
BA T/NSPS Option Emissions and Fuel Usage
BAT/NSPS Option 1
BAT/NSPS Option 2
BAT/NSPS Option 3
88,164
88,262
93,724
528
528
528
400
401
401
89,092
89,191
94,653
5,597,319
5,604,102
5,978,621
33,800
33,800
33,800
25,648
25,667
25,667
5,656,76
7
5,663,56
9
6,038,08
8
BAT/NSPS Incremental Compliance Emissions & Fuel Usage Increases (Reductions)
Appendix IX-1 consists of the detailed worksheets that present the per-well energy requirements
and air emissions calculations and are referred to throughout the following sections.
IX-4
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3.1 Water Based Drilling Fluids
EPA includes WBF wells in the NWQEI analyses for the final rule based on information submitted
by industry that certain WBF wells are projected to convert to SBF and that SBFs are more efficient than
WBFs. Wells drilled with SBFs have less washout (7.5% compared to 45% for WBF), decreasing the
amount of waste generated and discharged and drilling rates using SBF are greater than for WBFs. Table
IX-3 presents a summary of the NWQEFs for baseline and each option for SBFs, OBFs, and WBFs.
Under the controlled discharge options, total air emissions and fuel usage decreases compared to baseline.
Under these discharge scenarios, industry projects that some 39 Gulf of Mexico WBF wells will switch to
SBFs due to the operational benefits of SBFs (in particular those related to improved directional drilling
capabilities that reduces total footage drilled and/or well counts). EPA projects WBF usage, based on data
provided by industry, will not change in either offshore California or Cook Inlet, Alaska; in addition, no
offshore California wells are projected to use SBFs, even under a discharge option. Tables IV-3 and IV-4
summarize the well counts for the baseline and each regulatory option.
3.2 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.
3.2.1 Drilling Rig Activity
One of the significant advantages of using SBFs is increased drilling rate. According to industry
information, wells can be drilled twice as fast using SBFs as with WBFs.: The decreased drilling time
results in fewer days to drill than necessary to support WBF drilling operations. In order to reflect this
benefit of SBF usage, EPA included the effect less of daily rig activity into the NWQI calculations.
Specifically, the daily fuel consumption rate and air emissions of a drilling rig and one helicopter trip per day
per model well are included in the calculations for the baseline and each regulatory option. The average
drilling rig fuel consumption rate is 650 gallons diesel per hour.1 The average helicopter flight is two hours
to the rig and two hours back to shore with a fuel consumption rate of 97 gallons diesel per hour.1'3
IX-5
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X
ON
TABLE IX-3
SUMMARY OF NWQEI BY DRILLING FLUID TYPE FOR BASELINE AND BAT/NSPS OPTIONS FOR EXISTING SOURCES
Technology Basis
SBF
Air
Emissions
(tons/yr)
Fuel
Usage
(BOE/yr)
OBF
Air
Emissions
(tons/yr)
Fuel
Usage
(BOE/yr)
WBF
Air
Emissions
(tons/yr)
Fuel
Usage
(BOE/yr)
Total
Air
Emissions
(tons/yr)
Fuel
Usage
(BOE/yr)
Baseline/Current Practice
Discharge w/10.20% ROC a
Zero Discharge
Total Baseline
11,420
0
11,420
728,340
0
728,340
NA
3,213
3,213
NA
205,485
205,485
77,631
0
77,631
4,951,084
0
4,951,084
89,051
3,213
92,264
5,679,424
205,485
5,884,909
Technology Options
BAT/NSPS Option 1
BAT/NSPS Option 2
BAT/NSPS Option 3
14,323
14,422
1,016
913,836
920,877
64,849
1,967
1,967
12,504
125,802
125,802
798,790
72,802
72,802
81,133
4,643,106
4,643,106
5,174,449
89,092
89,191
94,653
5,682,744
5,689,785
6,038,088
ROC = retention on cuttings (by weight)
-------
In order to assess SBF NWQEIs relative to total impacts from drilling operations, EPA included
estimates of the daily drilling rig impacts from SBF-related activities. The additional impacts consist of fuel
use and air emissions resulting from the various drilling rig pumps and motors as well as impacts of a daily
helicopter trip for transporting personnel and/or supplies. Impacts were assessed for the number of days
that an SBF interval is drilled versus the number of days well intervals are drilled using WBFs and OBFs
and for the number of wells drilled using each of the drilling fluids.
3.2.2 Baseline Energy Requirements
Total baseline energy requirements are determined by summing the individual energy-consuming
activities currently performed using each of the three drilling fluids on a well-type specific and per-day basis.
These per-well, per-day values are multiplied by the number of wells in each geographic area and the
number of days to drill each model well type (i.e, SWD, SWE, DWD, DWE). 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 daily 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 3.1.3, "Zero
Discharge Option Energy Requirements," presents the detailed line-item assumptions and data applicable to
both baseline and zero discharge analyses.
In developing baseline energy requirements, EPA projects that the 201 SBF wells drilled annually in
the Gulf of Mexico, using standard solids control equipment, will discharge SBF-cuttings at an average
10.20% retention of synthetic base fluid. Also, 857 WBF wells and 67 OBF wells are included in the
baseline (all OBF wells currently practice zero discharge by either hauling waste to shore or by onsite
injection).
Daily per-well baseline fuel usage rates for OBF wells in offshore California and coastal Cook Inlet
derive from activities associated with transporting drill cuttings to shore or injecting the cuttings onsite. For
this analysis, EPA applies methods developed to estimate zero discharge impacts for the offshore effluent
limitations guidelines for offshore California wells4 and under the coastal effluent limitations guidelines for
coastal Cook Inlet wells.5 Appendix IX-1 present the calculation of daily per-well fuel usage for baseline
wells in offshore California and coastal Cook Inlet, respectively.
IX-7
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EPA uses the volumes of drilling waste requiring onshore disposal in offshore California to calculate
the number of supply boat trips necessary to haul the waste to shore. Projections made regarding boat
usage includes the 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 calculates
fuel requirements for cranes operations at the drill site and in port based on projections of crane usage.
EPA determines crane usage by considering the waste volumes to be handled and estimates of crane
handling capacity. EPA also uses 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,
enables a calculation of fuel usage. The use of land-spreading equipment at the disposal site is 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 are
calculated as 1,987 BOB for a SWD OBF well and 4,152 BOB for a SWE OBF well. For coastal Cook
Inlet, all zero discharge waste is injected onsite. The baseline fuel usage rate for a SWD OBF well is 1,960
BOB and 4,108 BOB for a SWE OBF well. For both regions, the SWD WBF per well fuel usage is 3,846
BOB and the SWE WBF fuel usage is 8,062 BOE. The total annual baseline fuel usage rates for these
geographic areas (33,800 BOE for offshore California and 25,667 BOE for Cook Inlet) are calculated by
multiplying the per-well rates for each fluid type by the corresponding numbers of baseline wells.
Daily 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 zero discharge
and the remaining 20% use onsite injection to dispose of OBF cuttings. In addition, EPA estimates 80% of
the waste brought to shore is disposed via subsurface injection and 20% via landfilling. These projections
were presented in Chapter VII, Section 5.4. As in the per-well zero discharge compliance cost analysis
discussed in Section 4.4 of Chapter VIII, the per-well zero discharge environmental impacts for Gulf of
Mexico wells are calculated as weighted averages reflecting these distributions of zero discharge compliance
methods. For the OBF model wells in the baseline (SWD and SWE), per-well impacts are calculated both
for transport and onshore disposal and for onsite injection. Then, for each model well, a weighted average
per-well impact is calculated as follows:
Baseline GOM OBF Well Impact = (0.8 x [(0.8 per-well transportation & onshore injection impact) +
(0.2 per-well transportation & landfilling impact)]) + (0.2 x per-well injection impact)
Per-well baseline fuel usage rates for land disposal in the Gulf of Mexico are calculated using the
same line-items as described above for offshore California 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
IX-8
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estimate that 85% of wells use diesel and 15% use natural gas as primary power sources in the Gulf of
Mexico.6 Appendix IX-1 shows the detailed per-well calculations for baseline wells in the Gulf of Mexico.
EPA calculates a per-well baseline fuel usage rate for each drilling fluid type. These per-well rates,
multiplied by the corresponding numbers of baseline wells using each of the three drilling fluids and the
number of days to drill each model well, result in a total annual baseline fuel usage of 5,825,442 BOB for
Gulf of Mexico existing sources. The total baseline fuel usage rate of existing sources in all three geographic
areas is 5,884,909 BOB per year (Table IX-2).
3.2.3 Energy Requirements for BAT/NSPS Discharge Options
Energy consumption for the discharge options is calculated by identifying the equipment and
activities associated with the addition of a cuttings dryer to reduce the retention of the synthetic base fluid
on drill cuttings from an average 10.20% to 4.03% for BAT/NSPS Option 1 and from 10.20% to 3.82% for
BAT/NSPS Option 2, measured on a wet-weight basis.
BAT/NSPS Option 2 requires that fines generated from the fines removal unit are not to be
discharged. The fines comprise approximately 3% of the total volume of waste generated from the solids
control equipment. To determine the energy requirements for BAT/NSPS Option 2, the energy
requirements for both the volume of waste discharged and the volume of waste hauled to shore or injected
onsite is summed. The assumptions used for zero discharge of fines are the same as used under the zero
discharge option and are detailed in Section 3.2.4 below. Because the cuttings dryer is added onto existing
solids control equipment, the fuel consumption of the baseline technology was included in the calculation of
each of the controlled discharge options. A summary of the total energy requirements for existing sources in
the three geographic regions under each of the discharge options is presented in Table IX-2. The remainder
of this section presents the calculations specific to each of the three geographic regions.
Per-well fuel usage rates are calculated for the four model well types in the Gulf of Mexico. As
stated in Section 3.2.2, EPA estimates that 85% of Gulf of Mexico wells use diesel as their primary source
of fuel, and 15% use natural gas.6 Therefore, the per-well fuel usage rates for the Gulf of Mexico are
weighted average per-well rates based on diesel usage and natural gas usage, respectively. These rates are
identified in Appendix IX-1 worksheets as separate line-items for each model well. For example, the per-
well diesel usage rate is calculated by multiplying the cuttings dryer operating time (equal to the number of
active drilling days) by the consumption rate for diesel generators, estimated to be 6 gal/hr.7 An example
diesel usage calculation for a DWD model well under BAT/NSPS Option 1 follows.
IX-9
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BAT (add-on) equipment: (7.9 days) x (24 hr/day) x (6 gal/hr) = 1,137.6 gal diesel/well
Baseline (existing) equipment: (7.9 days) x (24 hr/day) x (6 gal/hr) = 1,137.6 gal diesel/well
Total diesel usage = 2,275.2 gal/well
(Note in this example, as well as for the next below, the BAT usage is added to baseline usage because
BAT equipment is add-on technology, i.e., operating in addition to current practice, baseline
technologies.)
The per-well natural gas usage rate is 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.8 Multiplying the turbine consumption rate by the
power demand of the cuttings dryer (112.97 hp)9 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 under BAT Option
lis:
BAT (add-on) equipment: (112.97 hp) x (7.9 days) x (24hrs/day) = 21,419 hp-hr
Baseline (existing) equipment: (67.5 hp) x (7.9 days) x (24hrs/day) = 12,798 hp-hr
Total natural gas usage = (21,419 hp-hr + 12,798 hp-hr) x (9.5 scf/hp-hr) = 325,062 scf
Under the BAT/NSPS options, EPA projects that there will not be any SBF wells drilled offshore
California. Thus, the fuel usage for existing sources under BAT/NSPS Options 1 and 2 for this geographic
region is attributed to the same WBF and OBF wells as for the baseline scenario.
One SBF SWD well, one OBF SWE well, three WBF SWD wells, and one WBF SWE well are
projected for the discharge option fuel usage analysis for Cook Inlet, Alaska. Appendix IX-1 shows the per-
well, and total BAT/NSPS option fuel usage for Cook Inlet existing sources.
3.2.4 Energy Requirements for BAT/NSPS Option 3 Zero Discharge
Energy consumption for compliance with the BAT/NSPS Option 3 zero discharge is calculated only
for Gulf of Mexico wells that currently discharge SBF cuttings because wells in other areas are currently at
zero discharge and will not contribute impacts under this option. Fuel usage rates are estimated by
identifying the equipment and activities associated with the following zero discharge technologies currently in
use in the Gulf of Mexico: 1) transporting waste cuttings to shore for disposal via subsurface injection or
landfill; and 2) onsite injection. As stated in Section 3.2.2, EPA estimates that 80% of all Gulf of Mexico
wells employing zero discharge technology use land disposal for waste cuttings, while 20% use onsite
IX-10
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injection. Of the waste brought to shore, 80% is injected onshore and 20% is disposed at a landfill.10
Appendix IX-1 worksheets list the line-item activities associated with land disposal and onsite injection
technologies and present the weighted average energy requirements based on this proportion of wells 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. Although zero discharge for SBF wells is
not determined for offshore California and Cook Inlet, Alaska, zero discharge of OBF wells for baseline and
each of the regulatory options is estimated using information presented below.
3.2.4.1 Transportation and Onshore Disposal Energy Requirements
The per-well energy requirements associated with the transportation and onshore disposal of drill
cuttings varies between model well types and geographic areas. Variations between model wells are due to
differences in the per-well waste volumes calculated for each model well (see Table VII-4). The model well
waste volumes determine the frequency of boat and truck trips required to transport the waste. Variations
between geographic areas are due to differences in travel distances. For the proposed rule, some wells in
Cook Inlet were assumed to haul and land dispose waste. However, for the final rule, all wells in Cook Inlet
inject waste onsite. Below are the assumptions and data that constitute the line-items specific to the
transportation and onshore disposal of cuttings in Appendix IX-1 worksheets:
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. The volume of waste generated varies not only on a
per model well basis but also on a per regulatory option basis due to the changes in the number of
wells requiring zero discharge. Under baseline in the Gulf of Mexico, 69 OBF wells zero discharge.
Under the zero discharge option, 266 GOM wells would zero discharge, whereas under the
discharge options only 41 wells would be zero discharging. Assuming 80% of GOM wells would
haul, the number of supply boat trips under the discharge options would decrease, resulting in a
40% decrease in the amount of air pollutants and fuel used.
Based on information compiled in the offshore guidelines Development Document, EPA uses a
cuttings box capacity of 25 bbl for the Gulf of Mexico and offshore California areas.7 These
capacities determine the number of cuttings boxes to be filled, transferred to the supply boats, and
hauled to shore per model well type and 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 estimates dedicated supply boats will provide service solely for offloading SBF or OBF
cuttings. Dedicated supply boats are used for all model well types 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
IX-11
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cuttings boxes).11 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 materials no longer needed. EPA
estimates that regularly scheduled supply boats arrive at a drilling platform every four days.7 For
the purposes of the NWQEI analysis, EPA estimates that a regularly scheduled supply boat will be
used only after the capacity of a dedicated supply boat (see below) is reached and additional
cuttings still need to be hauled to shore. This is 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).7
Transit Fuel Consumption: Supply boats consume 130 gallons of diesel per hour while in transit.12
Average supply boat speed is 11.5 miles per hour.7 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: 111 miles for dedicated supply boats; 77 miles for regularly scheduled
supply boats7
Offshore California: 200 miles for dedicated supply boats7
Maneuvering Fuel Consumption: Supply boats maneuver at the platform for an average of one
hour per visit.13 The maneuvering fuel use factor is 15% of full throttle fuel consumption (169
gal/hr), or 25.3 gallons of diesel per hour.13
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.4 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.
Auxiliary Electrical Generator: An auxiliary generator is needed for electrical power when
propulsion engines are shut down. This only occurs when a supply boat is in port. The average in-
port time for unloading drill cuttings, tank cleanout, and demurrage is 24 hours per supply boat trip.7
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.7
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.14 Barges consume fuel at a rate of 24
gallons of diesel per hour and travel an average of 6 miles per hour.4
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 in 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.7
Cranes make 10 lifts per hour.7 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 type as follows:
Gulf of Mexico and Offshore California (cuttings box capacity = 25 bbl)
Deep Water Development: (37 boxes to unload & load at drill site)/(10 litts/hr) = 3.7 hrs
IX-12
-------
Deep Water Exploratory: (77 boxes to unload & load at drill site)/(10 lifts/hr) = 7.7 hrs
Shallow Water Development: (56 boxes to unload & load at drill site)/(10 lifts/hr) = 5.6 hrs
Shallow Water Exploratory: (124 boxes to unload & load at drill site)/(10 lifts/hr) = 12.4 hrs
โข Trucks: Trucks transport drill cuttings from port to the disposal site. For the Gulf of Mexico area,
truck fuel usage is estimated to be 4 miles per gallon5 and for California, 7 miles per gallon.15 The
truck capacity and distance traveled vary by geographic area as follows (see also Appendix VIII-1):
Gulf of Mexico: capacity =119 bbls7; distance = 20 miles5
Offshore California: capacity = 50 bbls16; distance = 300 miles (Appendix VIII-1)
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.
โข Land Disposal Equipment: Estimates regarding energy-consuming land disposal equipment are as
follows:
Wheel Tractor: Wheel tractors are used at disposal facilities 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.7
Track-Type Dozer/Loader: A track-type dozer/loader is required at facilities 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.7
3.2.4.2 Onsite and Onshore Grinding and Injection Energy Requirements
According to information available to EPA, zero discharge via onsite grinding and injection is
practiced by a growing number of operators in the Gulf of Mexico geographic area (see Section VII.5.5). In
addition, a significant proportion of drilling waste hauled to shore is injected by commercial disposal
companies. According to industry information, 80% of the waste brought to shore in the Gulf of Mexico
and offshore California is injected and 20% is sent to landfills for disposal.1S In Cook Inlet, Alaska, all
waste is injected offshore at the drill site.18 The waste volume of cuttings injected varies per model well
type and was presented in Table VII-4. Following are the identified equipment and activities required for
onsite or onshore injection and their corresponding power and fuel requirements.
Cuttings Transfer: Cuttings transfer equipment used both offshore and onshore consists of one
100-hp vacuum pump.10'17 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 were discussed in Section
V.2.2.
Cuttings Grinding and Processing: The equipment used for grinding and processing the drill
cuttings offshore and onshore consist of: one 75 hp grinding pump, two 10 hp mixing pumps, two
10 hp vacuum pumps, and one 5 hp shale shaker motor.17 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.
IX-13
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Cuttings Injection: One 600 hp injection pump rated at 2.5 barrels per minute is used for cuttings
injection in offshore drilling operations.17 In onshore injection facilities, one 1,225 hp injection
pump rated at 20.8 barrels per minute is used.10
Fuel Requirements: EPA calculates fuel requirements for both diesel and natural gas fuel sources
according to the assumption that 85% of Gulf of Mexico wells use diesel and 15% use natural gas.6
For diesel generators, the fuel usage rate for all of the grinding and injection equipment is 6 gallons
of diesel/hour of operation for both offshore and onshore injection.7'10 For natural gas, the fuel
requirements are 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.5
3.3 Air Emissions
The total air emissions for each of the regulatory options as presented in Table IX-1 are 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-2 presents the air emissions by geographic area for existing source wells. As for
the offshore guidelines, EPA uses 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 the different 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 discharge
options (BAT/NSPS 1 and 2), emission factors for either diesel generators or natural gas turbines are used
to calculate emissions associated with the vibrating centrifuge. These emission factors also are used to
calculate emissions associated with grinding and injection equipment. As mentioned above in Section 3.2.2,
85% of the Gulf of Mexico platforms utilize diesel as a fuel source and 15% utilize natural gas. This
proportion is applied to all model well types in the Gulf of Mexico and in offshore California. EPA projects
shallow water wells in coastal Cook Inlet to use natural gas exclusively (see Section 3.2.2). Detailed
calculations of the air emissions from each type of engine used are presented in Appendix IX-1.
EPA calculates the baseline and total compliance air emissions for both the discharge and zero
discharge options. The incremental air emissions for each of the options are determined by subtracting the
corresponding total compliance air emissions from baseline air emissions (see Table IX-3).
IX-14
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TABLE IX-4
UNCONTROLLED EMISSION FACTORS FOR
DRILL CUTTINGS MANAGEMENT ACTIVITIES
Category
Emission Factors
Units
NOx
THC
SO2
CO
TSP
Supply Boatsa
Transit
Maneuvering
Loading/Unloading
Demurrage
Barge Transit"
Supply Boat Cranes0
Barge Cranes0
Trucks'1
Wheel Tractor6
Dozer/Loader6
Diesel Generatorf
Natural Gas Fired Turbines8
Ib/gal
Ib/gal
Ib/gal
g/bhp-hr
Ib/gal
g/bhp-hr
g/bhp-hr
g/mile
Ib/hr
Ib/hr
g/bhp-hr
g/bhp-hr
0.3917
0.4196
0.4196
14
0.3917
14
14
11.23
1.269
0.827
14
1.3
0.168
0.226
0.226
1.12
0.168
1.12
1.12
2.49
0.188
0.098
1.12
0.18
0.02848b
0.02848b
0.02848b
0.931
0.02848
0.931
0.931
NA
0.09
0.076
0.931
0.00211
0.0783
0.0598
0.0598
3.03
0.0783
3.03
3.03
8.53
3.59
0.201
3.03
0.83
0.033
0.033
0.033
1
0.033
1
1
NA
0.136
0.058
1
NA
Source: Table II-3.3, AP-42 Volume II, September 1985.19
b Based on assumed 0.20% sulfur content of fuel and fuel density of 7.12 Ibs/gal (AP-42 Volume II,
September 1985).19
0 Source: Table 3.3-1, AP-42 Volume I, Supplement F, July 1993.20 Note: bhp is brake horsepower.
d Source: Table 1.7.1, AP-42 Volume II, September 1985.19
Source: Table II-7.1, AP-42 Volume II, September 1985.19
f Source: Table 3.2-1, AP-42 Volume I, Supplement F, July 1993.20
g Source: Table 3.3-1, AP-42 Volume I, January 1975.21 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).8
NA = Not Applicable
3.4 New Source Energy Requirements and Air Emissions
As described in Chapter IV, Section 3, EPA projects 20 new source SBF wells will be drilled
annually in the Gulf of Mexico under the baseline, consisting of 15 DWD wells and five SWD wells. Under
baseline, EPA also projects 38 WBF wells to be drilled (27 SWD and 11 DWD) and 2 SWD wells drilled in
the Gulf of Mexico. Under both BAT/NSPS discharge options, 24 new source SBF wells are projected,
IX-15
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with one OBF well and three WBF wells converting to SBF. 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 energy requirements (i.e., fuel usage) and air emissions for new source
wells in the Gulf of Mexico under the baseline and BAT/NSPS Options 1 and 2. The methods used to
calculate per-well impacts for new source wells are the same as for existing sources, described above in
Sections 3.2 and 3.3. The per-well impacts are multiplied by the corresponding number of wells using each
of the three drilling fluid types and summed for each of the options. Appendix VIII-2 includes three
worksheets that present the baseline impacts, the discharge option impacts, and the zero discharge option
impacts for new source wells. The incremental compliance impacts are calculated by subtracting
compliance impacts from the baseline impacts.
4. SOLID WASTE GENERATION
EPA received information that some operators use SBFs to drill an entire well (i.e., not just difficult
well intervals). These operators stated that SBFs facilitate faster, more efficient well drilling and therefore,
they have replaced WBFs with SBFs for drilling. EPA calculates the amount of waste cuttings that would
be land disposed, injected onshore, and/or injected onsite in each regulatory scenario, and determined there
would be a considerable reduction in the amount of drill cuttings land disposed and injected with the
implementation of a controlled discharge option.
Table IX-6 summarizes the total amounts of solid waste disposed by onshore disposal and onsite
injection for existing and new sources. Table VII-4 presented the model well data on which these solid
waste amounts are based. For each model well, the total waste generated (in pounds) is multiplied by the
number of wells affected for the corresponding option, base fluid type, and geographic area for the baseline
and regulatory options. EPA then calculates incremental compliance levels by subtracting the baseline solid
waste values from BAT/NSPS Options 1 and 2 values. For BAT/NSPS 3, the positive incremental values
indicate an increase in the amount of waste disposed by zero-discharge technologies as compared to the
baseline. Likewise, under the control options, the negative (parenthetical) incremental values indicate a
reduction in the amount of waste requiring subsurface injection or land-based disposal.
IX-16
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TABLE IX-5
SUMMARY AIR EMISSIONS AND FUEL USAGE FOR GULF OF MEXICO
NEW SOURCES
Baseline and Control Option
Air Emissions
(tons/yr)
Fuel Usage
(BOE/yr)
Baseline Emissions
Discharge w/ 10.2% retention of SBF cuttings
Zero Discharge (current OBF wells only)
Total Baseline
3,239
64
3,303
221,553
4,122
225,675
Total Emissions and Fuel Usage
BAT/NSPS Option 1
BAT/NSPS Option 2
BAT/NSPS Option 3 (Zero discharge)
3,439
3,448
3,767
219,345
219,982
239,620
Incremental Increase (Reduction) in Emissions and Fuel Usage
BAT/NSPS Option 1
BAT/NSPS Option 2
BAT/NSPS Option 3 (Zero discharge)
136
145
528
(6,330)
(5,693)
18,067
EPA's analyses show that compared to baseline, under the BAT/NSPS Option 3 (zero discharge)
for offshore existing sources, cuttings annually shipped to shore for disposal in non-hazardous oilfield waste
(NOW) sites increase of over 35 million pounds and increase over 166 million pounds for cuttings annually
injected. BAT/NSPS Option 3 leads to increased annual fuel usage of 358,664 BOB and an increase in
annual air emissions of 5,602 tons. Finally, BAT/NSPS Option 3 is projected to increase discharged WBF-
cuttings by 51 million pounds resulting from Gulf of Mexico operators switching from more efficient SBF to
less efficient WBF drilling.
IX-17
-------
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IX-18
-------
Additionally, EPA's analyses show that under BAT/NSPS Option 3 (zero discharge) as compared to
baseline, Gulf of Mexico new source cuttings annually shipped to shore for disposal in NOW sites increase
over 3.4 million pounds and increase over 10.2 million pounds for cuttings annually injected. BAT/NSPS
Option 3 leads to an increase in annual fuel use of 18,067 BOB and an increase in annual air emissions of
528 tons. Finally, BAT/NSPS Option 3 in the Gulf of Mexico is projected to increase WBF-cuttings being
discharged to offshore waters by 7.5 million pounds. Again, this pollutant loading increase is a result of Gulf
of Mexico operators using less efficient WBF for drilling instead of SBF.
5. CONSUMPTIVE WATER USE
Neither of the two regulatory options is projected to affect consumptive water use.
6. OTHER FACTORS
6.1 Impact of Marine Traffic
EPA estimates the changes in vessel traffic that would result from the implementation of the control
options 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 BAT/NSPS Option 3 (zero discharge), EPA estimates that 14 existing and new
source SBF wells in the Gulf of Mexico will implement zero discharge technologies. Based on the
assumption that 80% of these wells would transport waste drill cuttings to shore and each model well
requires one dedicated supply boat, except for DWE wells which require two dedicated supply boats, an
estimated total of 231 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 NSPS/BAT Options 1 and 2, 27 Gulf of Mexico OBF wells would convert to SBF usage,
thereby eliminating the need for hauling OBF cuttings to shore. Baseline supply boat trips are estimated as
55 trips per year for the 69 wells in the Gulf of Mexico where 55 wells transport drill cuttings to shore and
the other 14 inject onsite. Compared to the zero discharge option (BAT/NSPS Option 3) which led to 176
additional boat trips per year in the Gulf of Mexico, the discharge options reduce boat traffic in the Gulf of
IX-19
-------
Mexico by 22 boat trips per year. As cited in the offshore 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 baseline, the discharge options decrease commercial boat traffic by 0.01% in the
Gulf of Mexico.
6.2 Safety
EPA also considers the impact of the effluent limitations guidelines and standards on safety. EPA
has identified two safety issues related to drilling fluids: (1) deleterious vapors generated by organic materials
in drilling fluids; and (2) waste hauling activities that increase the risk of injury to workers.
One of the key concerns in exploration and production projects is the exposure of wellsite personnel
to vapors generated by organic materials in drilling fluids.22 Areas on the drilling location with the highest
exposure potentials are sites near solids control and open pits. These areas are often enclosed in rooms and
ventilated to prevent unhealthy levels of vapors from accumulating. If the total volume of organic vapors
can be reduced, then any potential health effects will also be reduced regardless of the nature of the vapors.
Generally speaking, the aromatic fraction of the vapors is the most toxic to the mammalian system.
The high volatility and absorbability through the lungs combined with their high lipid solubility serve to
increase their toxicity. Diesel OBFs have a high aromatic content and vapors generated from using these
drilling fluids include aromatics (e.g., alkybenzenes, naphthalenes, and alkyl-naphthalenes), alkanes (e.g.,
C7-C18 straight chained and branched), and alkenes. Some minerals oils (other than low aromatic content
mineral oils, often referred to as "low toxicity mineral oil"), also generate vapors that contain the same types
of chemical compounds, but generally at lower concentrations, as those found in the diesel vapors (e.g,
aromatics, alkanes, cyclic alkanes, and alkenes). Because SBFs are manufactured from compounds with
specifically defined compositions, the subsequent compound can exclude toxic aromatics. Consequently,
toxic aromatics can be excluded from the vapors generated by using SBFs.
In general, SBFs (e.g., esters, LAOs, PAOs, lOs) generate much lower concentrations of vapors
than do OBFs.22 Moreover, the vapors generated by these SBFs are less toxic than traditional OBFs
because they do not contain aromatics.
Industry has commented in previous effluent guidelines, such as the coastal subcategory
rulemaking, that a zero discharge requirement would increase the risk of injury to workers due to increased
IX-20
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waste hauling activities. These activities include vessel trips to and from the drilling platform to haul waste,
transfer of waste from the platform onto a service vessel, and transfer in port onto a barge or dock.
EPA has identified and reviewed additional data sources to determine the likelihood that imposition
of a zero discharge limitation on cuttings contaminated with SBF could increase risk of injury due to
additional waste hauling demands. The sources of safety data are the U.S. Coast Guard (USCG), the
Minerals Management Service (MMS), the American Petroleum Institute (API), and the Offshore Marine
Service Association (OMSA). The following is a summary of the findings from this review.
The data indicate there are reported incidents associated with the collection, hauling, and onshore
disposal of wastes from offshore. However, the data do not distinguish whether any of these incidents can
be attributed to specific waste management activities.
Most offshore incidents are due to human error or equipment failure. The rate at which these
incidents occur will not be changed significantly by increased waste management activities. However, if the
number of man hours and/or equipment hours are increased, there will be more reportable incidents given
an unchanged incident rate. These potential increases may be offset by reduced incident rates through
increased framing or equipment maintenance and inspection; but these changes cannot be predicted. One
indication that framing and maintenance can reduce incident rates is a 1998 API report entitled "1997
Summary of U.S. Occupational Injuries, Illnesses, and Fatalities in the Petroleum Industry," which
established that injury incident rates have been decreasing over the last 14 years. If this decrease continues,
there should be no increase in the number of safety incidents due to a requirement to haul SBF-
contaminated cuttings to shore for disposal.
7. AIR EMISSIONS MONETIZED HUMAN HEALTH BENEFITS
EPA estimated air emissions associated with each of the regulatory options as described above in
sections 3.3 and 3.4. The pollutants considered in the NWQI analyses are nitrogen oxides (NOX), volatile
organic carbon (VOC), participate matter (PM), sulfur dioxide (SO2), and carbon monoxide (CO). Of these
pollutants, EPA monetized the human health benefits or impacts associated with VOC, PM, and SO2
emissions using the methodology presented in the Environmental Assessment of the Final Effluent
Limitations Guidelines and Standards for the Pharmaceutical Manufacturing Industry (EPA-821-B-98-
008). Each of these pollutants have human health impacts and reducing these emissions can reduce these
impacts.
IX-21
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Several VOCs exhibit carcinogenic and systemic effects and VOCs, in general, are precursors to
ground-level ozone, which negatively affects human health and the environment. PM impacts include
aggravation of respiratory and cardiovascular disease and altered respiratory tract defense mechanisms. SO2
impacts include nasal irritation and breathing difficulties in humans and acid deposition in aquatic and
terrestrial ecosystems.
The unit values (in 1990 dollars) are $489 to $2,212 per megagram (Mg) of VOC; $10,823 per Mg
of PM; and $3,516 to $4,194 per Mg of SO2. Using the Engineering News Record Construction Cost Index
(see www.enr.com/cost/costcci.asp) these conversion factors are scaled up using the ratio of 6060:4732
(1999$: 1990$). EPA does not expect the alternate higher ROC limitation and standard for drilling fluids
with the stock base fluid performance of esters to affect monetized benefits because equipment used under
the ester option (e.g., shale shakers, cuttings dryer, fines removal unit) has the same or similar air emissions.
Following is a summary of the monetized benefits for each of the regulatory options for both existing and
new sources.
IX-22
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TABLE IX-7
SUMMARY OF MONETIZED HUMAN HEALTH BENEFITS OR IMPACTS ASSOCIATED WITH
VOC, PM, AND SO2 EMISSIONS, EXISTING SOURCES (1999S/YR)
Baseline/Current Practice Air Emissions, Mg/yr:
Discharge with 10 2% retention of SBF on cuttings
Zero Discharge (current OBF wells only)
Total Baseline Air Emissions Mg/yr
Compliance Air Emissions, Mg/yr:
(1) Discharge with 4 03% retention of SBF on cuttings
(2) Discharge with 3 82% retention of SBF on cuttings
(3) Zero Discharge a
Incremental Compliance Emission Reductions (Increases),
Mg/yr:
(1) Discharge with 4.03% retention of SBF on cuttings
(2) Discharge with 3.82% retention of SBF on cuttings
(3) Zero Discharge a
Unit Value of Poll. Reductions, 1990$/Mg: b
Unit Value of Poll Reductions 1999$/Mg-c
Incremental Compliance Benefits (Costs), 1998$/yr:
(1) Discharge with 4.03% retention of SBF on cuttings
(2) Discharge with 3.82% retention of SBF on cuttings
(3) Zero Discharge a
Criteria Air Pollutant
VOC
23,635
847
24,482
21,960
21,980
24,919
2,522
2,502
(437)
489 to 2,212
626 to 2,833
1,5 79,429 to
7,144,576
1,566,817 to
7,087,524
(273,777) to
(1,238,434)
PM
3,460
126
3,586
3,222
3,226
3,654
364
360
(68)
10,823
13,860
5,049,778
4,991,937
(948,091)
SO2
3,006
109
3,115
2,799
2,803
3,175
316
312
(59)
3, 516 to
4,194
4,503 to
5,371
1,423, 174 to
1,697,608
1,406,834 to
1,678,118
(267,560) to
(319,154)
Via land disposal or on-site offshore injection
Conversion factors from Environmental Assessment of the Final Effluent Limitations Guidelines and
Standards for the Pharmaceutical Manufacturing Industry (EPA-821-B-98-008)
Scaled from 1990$ using the Engineering News Record Construction Cost Index
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TABLE IX-8
SUMMARY OF MONETIZED HUMAN HEALTH BENEFITS OR IMPACTS ASSOCIATED WITH
VOC, PM, AND SO2 EMISSIONS, NEW SOURCES (1999S/YR)
Baseline/Current Industry Practice Air Emissions, Mg/yr:
Discharge with 10.2% retention of SBF on cuttings
Compliance Air Emissions, Mg/yr:
(1) Discharge with 4.03% retention of SBF on cuttings
(2) Discharge with 3.82% retention of SBF on cuttings
(3) Zero Discharge a
Incremental Compliance Emission Reductions (Increases),
Mg/yr:
(1) Discharge with 4 03% retention of SBF on cuttings
(2) Discharge with 3 82% retention of SBF on cuttings
(3) Zero Discharge a
Unit Value of Poll Reductions 1990$/Mg-b
Unit Value of Poll. Reductions, 1999$/Mg: c
Incremental Compliance Benefits (Costs), 1998$/yr:
(1) Discharge with 4 03% retention of SBF on cuttings
(2) Discharge with 3 82% retention of SBF on cuttings
(3) Zero Discharge a
Criteria Air Pollutant
VOC
589
813
913
998
(224)
(323)
(409)
489 to 2,212
626 to 2,833
(140,269) to
(634,508)
(202,421) to
(915,655)
(256,052) to
(1,158,253)
PM
86
119
134
146
(33)
(48)
(60)
10,823
13,860
(453,927)
(658,885)
(831,151)
S02
75
104
117
127
(29)
(41)
(52)
3,516 to
4,194
4,503 to
5,371
(128,265) to
(152,999)
(186,271) to
(222,190)
(234,472) to
(279,686)
Via land disposal or on-site offshore injection
Conversion factors from Environmental Assessment of the Final Effluent Limitations Guidelines and
Standards for the Pharmaceutical Manufacturing Industry (EPA-821-B-98-008)
Scaled from 1990$ using the Engineering News Record Construction Cost Index
7. REFERENCES
1. Van Slyke, Don, Unocal. Unocal Comments; Effluent Limitations Guidelines for the Oil and Gas
Extraction Point Source Category; Proposed Ruling (40 CFR 435). 6/9/00. (Record No. IV.A.a.3)
2. Mason, T., Avanti Corporation, Memorandum regarding "Conversion Factor to BOB (Barrels of
Oil Equivalents) for Natural Gas and Diesel Fuel." 7/12/96. (Record No. I.C.d.44)
3. AP-42: Compilation of Air Pollutant Emissions Factors, Volume II: Mobile Sources (AP-42),
pending 5th edition. Last updated: 06 April 1998
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4. 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.
5. 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.
6. Daly, J., U.S. EPA, Memorandum regarding "Market Share of Respondents to Technical
Questions, August 17, 1998.
7. 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.
8. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume I, April 1976.
9. Mclntyre, J., Avanti Corporation, Memorandum to J. Daly, U.S. EPA, regarding "Summary of
December 2 Meeting with David Wood of Mud Recovery Systems," December 18, 1997.
10. Johnston, C.A., EPA. Memorandum to File, On-shore Formation Injection Disposal Non-Water
Quality Environmental Impact Input Parameters. 6/20/00. (Record No. D.2)
11. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with J.
Belsome, Seabulk Offshore Ltd., regarding "Offshore supply boat costs and specifications," 6/3/98.
12. U.S. EPA, "Trip Report to Campbell Wells Landfarms and Transfer Stations in Louisiana,"
6/30/92. (Record No. C.d.60)
13. 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. (Record I.C.d.46)
14. Sunda, J., SAIC, Memorandum to A. Wiedeman, U.S. EPA, regarding "The assumptions used in
the development of the cost of commercial disposal of produced water using barge transportation,"
3/10/94. (Record I.C.d.47)
15. Montgomery, R, The Pechan-Avanti Group, Telecommunication Report on conversation with S.
Morgan, Ecology Control Inc., regarding "costs associated with land and water transport of drill
cuttings and drilling fluids for offshore oil platforms operating off the California coast," 5/9/98.
(Record No. I.C.d.25)
16. Mclntyre, J., The Pechan-Avanti Group, Telecommunications Report on conversation with D.
Stankey, McKittrick Solid Waste Disposal Facility, regarding "California Prices for Land Disposal
of Drilling Wastes," 10/16/98. (Record No. I.C.d.23)
17. Kennedy, K., The Pechan-Avanti Group, Telecommunications Report on conversation with
personnel at Apollo Services regarding "Detailed Information Regarding Apollo's Cuttings Injection
System," 7/9/98. (Record No. I.C.d.48)
18. Johnston memo to file: "Update on Several Model Input Parameters for Offshore Injection and
Land Disposal (Injection and Landfarming) Operations for Zero Discharged SBF Wastes. 8/14/00.
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19. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume II, September 1985.
(Record No. I.C.d.49)
20. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume I, Supplement F, July
1993. (Record No. I.C.d.50)
21. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume I, January 1975.
(Record No. I.C.d.51)
22. Candler, J., M. Churan and L. Conn. 1995. Laboratory and Field Measurements of Vapors
Generated by Organic Materials in Drilling Fluids. SPE 35866. (Record No. III.D. 12)
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CHAPTER X
OPTIONS SELECTION RATIONALE
1. INTRODUCTION
This chapter presents the options EPA has selected for control of the SBF and SBF-cuttings waste
streams. A discussion of the rationale for selection of these options also is included.
2. REGULATORY OPTIONS CONSIDERED FOR SBFs NOT ASSOCIATED WITH DRILL
CUTTINGS
EPA is promulgating, under BPT, BCT, BAT, and NSPS, zero discharge for SBFs not associated
with drill cuttings. This option is technically available and economically achievable. In the February 1999
proposal, EPA proposed BPT, BCT, BAT, and NSPS as zero discharge for SBFs not associated with drill
cuttings. In the April 2000 NODA, EPA published two options for the final rule for the BAT limitation and
NSPS for controlling SBFs not associated with SBF drill cuttings: (1) zero discharge; or (2) allowing
operators to choose either zero discharge or an alternative set of BMPs with an accompanying compliance
method. Industry supported the second option stating that the first option (zero discharge) would result in
the costly and potentially dangerous collection, shipping, and disposal of large quantities of rig site wash
water containing only a small quantity of SBF.1 Industry also stated that BMPs would be extremely
effective at reducing the quantity of non-cuttings related SBF and would focus operators' attention on
reducing these discharges.
EPA is promulgating BPT, BCT, BAT, and NSPS of zero discharge for SBFs not associated with
drill cuttings. This waste stream consists of neat SBFs that are intended for use in the downhole drilling
operations (e.g., drill bit lubrication and cooling, hole stability). Drilling fluids are transferred from supply
boats to the drilling rig and can be released during these transfer operations. This waste stream is often
spilled on the drill deck but contained through grated troughs, vacuums, or squeegee systems. This waste
stream is also held in numerous tanks during all phases of the drilling operation (e.g., trip tanks, storage
tanks). EPA received information that rare occurrences of improper SBF transfer procedures (e.g., no
bunkering procedures in place for rig loading manifolds) and improper operation of active mud system
equipment (e.g., no lock-out, tag-out procedures in place for mud pit dump valves) has the potential for the
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discharge of tens to hundreds of barrels of neat SBF, or SBF not associated with cuttings, if containment is
not practiced.2
Current practice for control of SBF not associated with drill cuttings is zero discharge (e.g., drill
deck containment, bunkering procedures), primarily due to the value of SBFs recovered and reused.
Therefore, zero discharge for SBF not associated with drill cuttings is technologically available and
economically achievable. Moreover, these controls generally allow the re-use of SBF in the drilling
operation and have no unacceptable NWQIs.
EPA has also decided that solids accumulated at the end of the well ("accumulated solids") and
wash water used to clean out accumulated solids or used on the drill floor are associated with drill cuttings
and are therefore not controlled by the zero discharge requirement for SBFs not associated with drill
cuttings.
3. REGULATORY OPTIONS CONSIDERED FOR SBFs ASSOCIATED WITH DRILL
CUTTINGS
3.1 BPT Technology Options Considered and Selected
EPA is promulgating BPT effluent limitations for the cuttings contaminated with SBFs ("SBF-
cuttings"). The BPT effluent limitations promulgated for SBF-cuttings would control free oil as a
conventional pollutant. The BPT limitation is no free oil as measured by the static sheen test, performed on
SBF separated from the cuttings in offshore waters and coastal Cook Inlet, Alaska.
In setting the no free oil limitation in offshore waters and coastal Cook Inlet, Alaska, EPA
considered the sheen characteristics of currently available SBFs. Because 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. Therefore, EPA believes that this limitation represents the appropriate BPT level of control for
SBFs associated with drill cuttings. At the time of the Offshore rulemaking when this was an issue, industry
re-formulated SBFs to comply with this limitation and thus EPA is retaining this limitation to ensure that
SBF-cuttings discharges do not create sheens.
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3.2 BCT Technology Options Considered and Selected
In July 1986, EPA promulgated a methodology for establishing BCT effluent limitations. EPA
evaluates the reasonableness of BCT candidate technologies - those that are technologically feasible - by
applying a two-part cost test: (1) a POTW test; and (2) an industry cost-effectiveness test.
EPA first calculates the cost per pound of conventional pollutant removed by industrial dischargers
in upgrading from BPT to a BCT candidate technology and then compares this cost to the cost per pound of
conventional pollutants removed in upgrading POTWs from secondary treatment. The upgrade cost to
industry must be less than the POTW benchmark of $0.25 per pound (in 1976 dollars). In the industry
cost-effectiveness test, the ratio of the incremental BPT to BCT cost divided by the BPT cost for the
industry must be less than 1.29 (i.e., the cost increase must be less than 29%).
The BCT effluent limitations will control free oil as a conventional pollutant. EPA is promulgating a
BCT effluent limitation for SBF-cuttings of no free oil equivalent to the BPT limitation for SBF-cuttings of
no free oil as determined by the static sheen test in offshore waters and coastal Cook Inlet, Alaska. Because
the BCT limitation is equivalent to the BPT limitations it has no incremental cost and thus passes the BCT
cost tests.
In developing BCT limits for the offshore waters and coastal Cook Inlet, Alaska, EPA considered
whether there are technologies (including drilling fluid formulations) that achieve greater removals of
conventional pollutants than promulgated for BPT, and whether those technologies are cost-reasonable
according to the BCT cost test. EPA identified no technologies that can achieve greater removals of
conventional pollutants as compared with the offshore waters and coastal Cook Inlet BPT requirements that
are also cost-reasonable under the BCT cost test. Accordingly EPA is promulgating BCT effluent
limitations for SBF-cuttings equal to the promulgated BPT effluent limitations for SBF-cuttings in offshore
waters and coastal Cook Inlet, Alaska.
3.3 BAT Technology Options Considered And Selected
3.3.1 Overview
EPA is promulgating stock limitations and discharge limitations in a two-part approach to control
SBF-cuttings discharges under BAT. The first part is based on product substitution through use of stock
limitations (e.g., sediment toxicity, biodegradation, PAH content, metals content) and discharge limitations
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(e.g., diesel oil prohibition, formation oil prohibition, sediment toxicity, aqueous toxicity). The second part
is the control of the quantity of SBF discharged with SBF-cuttings. As previously stated in the April 2000
NODA, EPA finds that the second part is particularly important because limiting the amount of SBF content
in discharged cuttings controls: (1) the amount of SBF discharged to the ocean; (2) the biodegradation rate
of discharged SBF; and (3) the potential for SBF-cuttings to develop cuttings piles and mats that are
detrimental to the benthic environment. While the primary technology basis for the limitations and standards
is product substitution and enhanced solids control technology, EPA also believes that in the rare instances
where a discharger could not comply with the limitations or standards, the discharger could meet zero
discharge by re-injection or land disposal. [Note: In the Offshore Guidelines, 58 FR 12454 (March 4, 1993),
EPA determined that zero discharge was technically available and economically achievable for the industry
as a whole. See Offshore preamble, Offshore Development Document, and Offshore Economic Analysis.]
EPA is also retaining the existing BAT limitations on: (1) the stock barite of 1 mg/kg mercury and 3
mg/kg cadmium; (2) the maximum aqueous toxicity of discharged SBF-cuttings as the minimum 96-hour
LC50 of the suspended particulate phase (SPP) toxicity test shall be 3% by volume; and (3) the discharge of
drilling wastes containing diesel oil in any amount is prohibited. These limitations control the levels of toxic
metal and aromatic pollutants, respectively. EPA believes all of these components are essential for
appropriate control of SBF-cuttings discharges.
The BAT effluent limitations promulgated for SBF-cuttings control a variety of toxic and
nonconventional pollutants in the stock base fluids by controlling their PAH content, sediment toxicity, and
biodegradation. The BAT effluent limitations promulgated for SBF-cuttings also control a variety of toxic
and nonconventional pollutants at the point of discharge by controlling formation oil contamination,
sediment toxicity, and the quantity of SBF discharged. The BAT stock and discharge limitations are
described below.
The BAT level of control in offshore waters has been developed taking into consideration among
other things: (1) the availability, cost, and environmental performance of SBF base fluids in terms of PAH
content, sediment toxicity, and biodegradation rate; (2) the availability, cost, and environmental performance
of SBFs retained on the cuttings discharge in terms of sediment toxicity; (3) the frequency of formation oil
contamination at the various control levels for the discharges; (4) the availability, cost, and environmental
performance of equipment and methods to recover SBF from the drill cuttings being discharged; and (5) the
NWQIs of each option. By environmental performance, EPA means both a reduction in the quantity of
pollutants discharged to the ocean and a reduction in their environmental effects in terms of sediment
toxicity, aquatic toxicity, and biodegradation rate. Issues related to the technical availability and economic
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achievability of promulgated BAT limitations are discussed below by regulated parameter. The NWQIs of
each selected option also are discussed below. EPA also considered NWQIs in selecting the controlled
discharge option for SBF-cuttings (i.e., BAT/NSPS Option 2).
EPA and industry sediment toxicity and biodegradation laboratory studies show that both vegetable
esters and low viscosity esters have better environmental performance than all other SBF base fluids. EPA,
however, rejected the option of basing BAT sediment toxicity and biodegradation stock limitations and
standards solely on vegetable esters and low viscosity esters because the record does not indicate that these
fluids can be used in drilling situations throughout the offshore subcategory nor could EPA predict the
conditions and circumstances where these fluids could be used. Specifically, EPA considered the large
number of factors related to whether esters could be used (e.g., formation characteristics, water depth,
temperature requirements, solids contamination, reactivity with alkaline materials) and determined that EPA
did not have sufficient information to specify when esters could be used. EPA is sufficiently satisfied,
however, that both esters provide better environmental performance (e.g., sediment toxicity,
biodegradation). Consequently, EPA is promulgating a higher retention on cuttings (ROC) BAT discharge
limitation to encourage the use of esters. The higher ROC discharge limitation for SBFs complying with the
stock limitations based on esters is derived from data representing four cuttings dryer technologies (e.g.,
vertical centrifuge, horizontal centrifuge, squeeze press mud recovery unit, and High-G linear shaker). The
lower ROC BAT discharge limitation for the SBFs complying with the C16-C18 internal olefm stock
limitations is based on data from the two top performing cuttings dryer technologies (e.g., vertical centrifuge
and horizontal centrifuge). EPA data demonstrate that operators properly using these cuttings dryer
technologies (e.g., vertical centrifuge, horizontal centrifuge, squeeze press, High-G linear shaker) are able to
comply with these final ROC numerical limitations. EPA believes that this balancing of the importance of
retention values with environmental performance as reflected by sediment toxicity and biodegradation rates
is justified because of the greater ability of esters to biodegrade and of their lower sediment toxicity.
EPA determined that zero discharge for BAT was technically feasible and economically achievable
because prior to the use of SBFs, the industry was able to operate using only the traditional OBFs (based on
diesel oil and mineral oil), which are prohibited from discharge. EPA concluded that a zero discharge BAT
limitation for SBF-cuttings would decrease the use of SBFs in favor of OBFs and WBFs. This is because a
zero discharge BAT limitation for SBF-cuttings would create an incentive for operators to use the least
expensive drilling fluids (i.e., OBFs, WBFs) in order to minimize overall compliance costs.
However, EPA rejected the BAT zero discharge option for SBF-cuttings wastes because it would
result in unacceptable increases in NWQIs. Therefore, EPA rejected the zero discharge option for SBF-
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cuttings wastes in the offshore subcategory of 40 CFR 435. Use of OBFs in place of SBFs would lead to
an increase in NWQIs including the toxicity of the drilling waste. Use of WBFs in place of SBFs would
generally lead to a per well increase in pollutants discharged, an increase in NWQIs, and an increase in
aquatic toxicity. WBF drilling operations lead to per well increases in pollutants discharged because WBFs
generate six times more washout (e.g., sloughing) of the well wall than SBFs. Also, WBF drilling operations
lead to increases in NWQIs because WBF drilling operations generally take longer than SBF drilling
operations which lead to more air emissions and fuel usage from drilling rigs and equipment. Aquatic
toxicity generally increases when drilling fluid manufacturers add supplements (e.g., glycols, shale inhibitors)
to WBFs for the purpose of making WBFs have technical capabilities (e.g., lubricity, shale suppression)
similar to SBFs. EPA estimates that, under the zero discharge option, some operators would switch to
WBF compositions with more non aqueous drilling fluid properties (e.g., lubricity, shale suppression), and
that these WBFs would exhibit greater aquatic toxicity.
EPA's analyses show that under the SBF-cuttings zero discharge option as compared to current
practice, for offshore existing sources there would be an increase of 35 million pounds of cuttings shipped
annually to shore for disposal in non-hazardous oilfield waste (NOW) sites and an increase of 166 million
pounds of cuttings injected. In addition, under the SBF-cuttings zero discharge option, operators would use
the more toxic OBFs. The zero discharge option for SBF-cuttings would lead to an increase in annual fuel
usage of 358,664 BOE and an increase in annual air emissions of 5,602 tons. Finally, the SBF-cuttings zero
discharge option in offshore waters would lead to an increase of 51 million pounds of WBF cuttings being
discharged to offshore waters. This pollutant loading increase is a result of Gulf of Mexico operators
switching from more efficient SBF drilling to less efficient WBF drilling.
EPA's analyses show that impacts of adequately controlled SBF discharges to the water column
and benthic environment are of limited scope and duration. By contrast, the landfilling of OBF-cuttings is of
a longer term duration and associated pollutants may affect ambient air, soil, and groundwater quality. EPA
and DOE documented at least five CERCLA ("Superfund") sites in Louisiana and California contaminated
with oilfield wastes and more than a dozen sites subject to Federal or state cleanup actions.
Nonetheless, while SBF-cuttings discharge with adequate controls is preferred over zero discharge
to offshore waters, SBF-cuttings discharge with inadequate controls is not preferred over zero discharge.
EPA believes that to allow discharge of SBF-cuttings to offshore waters, there must be appropriate controls
to ensure EPA's discharge limitations reflect the "best available technology" or other appropriate level of
technology. EPA has worked with industry to address the appropriate determination of PAH content,
sediment toxicity, biodegradation, quantity of SBF discharged, and formation oil contamination that are
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technically available, economically achievable, and have acceptable NWQIs. The final BAT limitations are
a result of this effort and are discussed below.
EPA, however, did not base the higher ROC BAT discharge limitation on current or existing shale
shaker technology as EPA finds that shale shakers are less effective at reducing base fluid retained on
cuttings than the selected BAT solids control technology, cuttings dryers. As previously stated in the April
2000 NODA, field results show that: (1) cuttings are dispersed during transit to the seabed and no cuttings
piles are formed when SBF concentrations on cuttings are held below 5%; and (2) cuttings discharged from
cuttings dryers (with SBF retention values under 5%) in combination with a sea water flush, hydrate very
quickly and disperse like water-based cuttings. The LTA based on data from all four cuttings dryers is
4.8% while the LTA for baseline solids control technology (e.g., shale shakers, fines removal units) is
10.2%. Therefore, the selected BAT solids control technology, in combination with BAT stock and
discharge limitations, is superior to existing solids control technology (shale shakers) in controlling
environmental impacts.
EPA is promulgating BAT of zero discharge for SBF-cuttings for coastal Cook Inlet, Alaska except
when operators are unable to dispose of their SBF-cuttings using any of the following disposal options: (1)
onsite injection (annular disposal or Class II UIC); (2) injection using a nearby coastal or offshore Class II
UIC disposal well; or (3) onshore disposal using a nearby Class II UIC disposal well or land application.
Coastal Cook Inlet operators are required to demonstrate to the NPDES permit authority that none of the
above three disposal options are technically feasible in order to qualify for the alternate BAT limitation.
Operators that qualify for the alternate BAT limitation are allowed to discharge SBF-cuttings at the same
level of BAT control as operators in offshore waters. The NPDES permit authority will use the procedure
given in Appendix 1 to Subpart D of 40 CFR Part 435 to establish whether or not an operator qualifies for
the SBF-cuttings zero discharge exemption. As stated in Appendix 1 to Subpart D of 40 CFR Part 435, the
following factors are considered in the determination of whether or not Cook Inlet operators qualify for the
SBF-cuttings zero discharge exemption: (1) inability to establish formation injection in wells that were
initially considered for annular or dedicated disposal; (2) inability to prove to UIC controlling authority that
the waste will be confined to the formation disposal interval; (3) inability to transport drilling waste to an
offshore Class II UIC disposal well or an onshore disposal site; and (4) whether or not there are no available
land disposal facilities (e.g., onshore re-injection, land disposal).
EPA finds that this option is technically available and economically achievable. Operators are
currently barred from discharging OBFs, SBFs, and enhanced mineral oil based drilling fluids under the
Cook Inlet NPDES general permit (64 FR 11889). Many Cook Inlet operators in coastal waters are
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currently using cuttings injection to comply with zero discharge disposal requirements for OBFs and OBF-
cuttings. EPA contacted Cook Inlet operators (e.g., Phillips, Unocal, Marathon Oil) and the state regulatory
agency, AOGCC, for more information on the most recent injection practices of coastal and offshore Cook
Inlet operators. AOGCC stated that there should be enough formation injection disposal capacity for the
small number of non-aqueous drilling fluid wells (< 5-10 wells per year) being drilled in Cook Inlet coastal
waters. Therefore, because coastal Cook Inlet operators are already complying with zero discharge of
OBF- and SBF-cuttings, this option is economically achievable as there are no incremental compliance
costs.
AOGCC stated, however, that case-specific limitations should be considered when evaluating
disposal options. Cook Inlet operators may experience the following difficulties in attempting to comply
with a zero discharge requirement for SBFs: (1) inability to establish formation injection in wells that were
initially considered for annular or dedicated Class II UIC disposal; (2) inability to prove to AOGCC's
satisfaction that the waste will be confined to the formation disposal interval; and (3) inability to transport
drilling waste to an offshore Class II UIC disposal well or an onshore disposal site. EPA believes that while
these problems are currently not presented by drilling in Cook Inlet, they could be a problem in the future.
Further, EPA believes this to be a greater problem in Cook Inlet where climate, tides, and distance from
commercial disposal sites make transportation to shore less feasible than in other offshore waters. If EPA
did not provide for some exceptions within the guideline itself and these problems were encountered beyond
the time frame for requesting a Fundamentally Different Factors variance (under section 301(n)(2) of the
CWA, 180 days) this would render zero discharge not achievable. Therefore, EPA believes it reasonable to
provide some flexibility to the current practice of zero discharge in Cook Inlet.
EPA further finds the NWQIs of this option for Cook Inlet to be acceptable. As previously stated,
few non-aqueous drilling fluid wells are drilled in coastal Cook Inlet, Alaska (< 5-10 wells per year). EPA
finds that the small number of wells drilled per year (even if all of them are drilled using SBF) leads to very
small increases in NWQIs. In particular, a zero discharge requirement for SBFs and SBF-cuttings in Cook
Inlet would lead to 400 tons of air emissions and 25,667 BOB fuel used. Consequently, EPA finds that the
overall small increases in NWQIs from the zero discharge option, as compared to either of the two SBF-
cuttings discharge options, in coastal Cook Inlet, Alaska, are acceptable.
EPA therefore finds the NWQIs in coastal Cook Inlet, Alaska, to be far different from other
offshore areas. In the GOM, the NWQIs are in total approximately 58 times greater than Cook Inlet. This
is due to the vast difference in the number of wells drilled and in the method of disposal. In the GOM 80%
of the wells use land disposal and 20% of the wells use re-injection. Land disposal, creates energy use, air
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emissions, and land application of waste. Moreover, EPA believes that operators in the GOM would simply
switch their fluids to WBFs and OBFs if EPA selected zero discharge, with the corresponding NWQIs and
water impacts associated with WBFs and OBF use. By contrast, in coastal Cook Inlet, Alaska, because
zero discharge is current practice, EPA projects operators will not switch from SBFs to OBFs and WBFs
due to this rule. Further, the total quantity of NWQIs from injection in coastal Cook Inlet, Alaska, is not
significant.
EPA also finds the NWQIs of zero discharge of coastal Cook Inlet, Alaska, to be distinguishable
from the NWQIs of zero discharge in offshore California. In offshore California, if EPA selected zero
discharge, EPA projects that operators would be far more likely to transport their waste to shore than re-
inject offshore. This transportation to shore generates land waste, energy requirements, and additional air
emissions in areas that have known air quality problems. For these reasons, EPA believes it is reasonable to
make a different choice regarding zero discharge in coastal Cook Inlet, Alaska, than in other waters covered
by this rule.
3.3.2 Stock Base Fluid Technical Availability and Economic Achievability
As SBFs have developed over the past few years, industry has come to use mainly a limited
number of primary base fluids. These include the internal olefins, linear alpha olefins, poly alpha olefins,
paraffinic oils, C12-C14 vegetable esters of 2-hexanol and palm kernel oil, and "low viscosity" C8 esters.
These fluids represent virtually all the SBFs currently used in oil and gas extraction industry. EPA collected
data on performance, environmental impacts, and costs for these SBFs to develop the effluent limitations
for final rule. The following definitions describe various SBFs.
Internal olefin (IO) refers to a series of isomeric forms of C16 and C18 alkenes.
Linear alpha olefin (LAO) refers to a series of isomeric forms of C14 and C16 monoenes.
โข Poly alpha olefin (PAO) refers to a mix mainly comprised of a hydrogenated decene dimer C20H62
(95%), with lesser amounts of Qo^ (4.8%) and C10H22 (0.2%).
โข Vegetable ester refers to a monoester of 2-ethylhexanol and saturated fatty acids with chain lengths
in the range C8 - C16.
"Low viscosity" ester refers to an ester of natural or synthetic C8 fatty acids and alcohols.
EPA also has data on other SBF base fluids, such as enhanced mineral oil, paraffinic oils (i.e., saturated
hydrocarbons or "alkanes"), and the traditional OBF base fluids: mineral oil and diesel oil.
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The stock base fluid limitations are based on the technology of product substitution. The
promulgated limitations are technically available because they are based on currently available base fluids
that can be used in the wide variety of drilling situations in offshore waters. EPA anticipates that the base
fluids meeting all requirements include vegetable esters, low viscosity esters, and lOs. In addition, based on
current information, EPA believes that the stock base fluid controls on PAH content, sediment toxicity, and
biodegradation rate being promulgated are sufficient to only allow the discharge of only those base fluids
(e.g., esters, lOs) with lower bioaccumulation potentials (i.e., log Kow < 3 to 3.5 and log Kow > 6.5 to 7).
Therefore, EPA found it was unnecessary to promulgate a separate limitation for bioaccumulation.
In the NODA, EPA considered basing the sediment toxicity and biodegradation stock limitations and
standards solely on vegetable esters (i.e., original esters) instead of the proposed C16-C18IO. EPA also
considered subcategorizing the final rule to determine when vegetable esters are not practical and when C16-
C18 lOs could be used instead. EPA considered these options due to the potential for better environmental
performance of vegetable ester-based drilling fluids. EPA and industry analytical testing show that esters
have better sediment toxicity and biodegradation performance.
EPA rejected the option of basing sediment toxicity and biodegradation stock limitations and
standards on vegetable esters due to several technical limitations. These technical limitations of vegetable
esters preclude their use in all areas of the Gulf of Mexico, offshore California, and Cook Inlet, Alaska.
Vegetable ester technical limitations include: (1) high viscosity compared with other IO SBFs at all
temperatures, with an increasing difference as temperature decreases, leading to lower rates of penetration in
wells and greater probability of losses due to higher equivalent circulating densities; (2) high gel strength in
risers that develops when a vegetable ester-SBF is not circulated; (3) a high temperature stability limit
ranging from about 225 ยฐF to perhaps 320 ยฐF - the exact value depends on the detailed chemistry of the
vegetable ester (i.e., the acid, the alcohol) and the drilling fluid chemistry; (4) reduction of the thermal
stability limit through hydrolysis when vegetable esters are in contact with highly basic materials (e.g., lime,
green cement) at elevated temperatures; and (5) less tolerance of the muds to contamination by seawater,
cement, and drill solids than is observed for IO-SBFs.3'4-5-6-7-8-9
EPA also rejected the option of subcategorizing the use of esters to define drilling conditions when
only esters could be allowed for a controlled discharge. EPA could not establish a "bright line" rationale to
define the situation where only esters should be the benchmark fluid (i.e., only esters would be allowed for a
controlled discharge). EPA considered many of the engineering factors used for selection of a drilling fluid
(e.g., rig size and equipment; formation characteristics; water depth and environment; lubricity, rheological,
and thixotropic requirements) and determined that this type of sub-categorization was not possible. Because
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of the large number of factors affecting whether esters could be used and the complexity of how the factors
relate to each other, EPA did not have enough information to develop a set of conditions under which esters
could be used. EPA, however, is encouraging the use of esters by promulgating a higher ROC limitation
and standard when esters are used.
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EPA also considered basing sediment toxicity and biodegradation stock limitations and standards on
low viscosity esters. Comments to the April 2000 NODA state that laboratory analyses, which were
designed to simulate Gulf of Mexico conditions to which a fluid may be exposed, indicate that low viscosity
esters have the following technical properties and uses.
โข Similar or better viscosity than C16-C18 lOs
Used to formulate stable low viscosity ester-SBFs up to 300ยฐF
Used to formulate low viscosity ester-SBFs to 16.0+ Ibs/gal mud weight
Reduce oil/water ratios to 70/30, thus reducing volumes of base fluid discharged
High tolerance to drilled solids
โข Flat gels make it easier to break circulation, minimizing initial circulation pressures and subsequent
risk of fracture
โข High tolerance to seawater contamination
โข Rheological properties can be adjusted by use of additives to suit specific conditions.9
EPA also received information on one well section drilled with low viscosity esters. Some of the results
from this low viscosity ester well section were compared to the results from another well section in the same
location where C16-C18 lOs were used. These results show that the low viscosity ester had: (1) comparable
or better equivalent circulating densities (i.e., acceptable fluid properties); and (2) faster ROP through better
hole cleaning and higher lubricity (i.e., fewer days required to drill to total depth which lead to less NWQI
and overall drilling costs). The low viscosity esters are relatively new base fluids and have only recently
been available to the market. Despite the results from the laboratory analyses and one well section, EPA
does not believe that this is enough information to make the determination that low viscosity esters can be
used in all or nearly all drilling conditions in the offshore waters (e.g., differing formations, water depths,
and temperatures). Therefore, EPA rejected the option of basing sediment toxicity and biodegradation stock
limitations and standards on low viscosity esters. EPA is sufficiently satisfied, however, that low viscosity
esters and vegetable esters provide better environmental performance (e.g., sediment toxicity,
biodegradation). Consequently, EPA is promulgating higher retention on cuttings discharge limitations
where esters are used to encourage operators to use esters when possible.
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3.3.2.1 PAH Content Technical Availability
The promulgated limitation of PAH content for offshore waters is a weight ratio defined as the
weight of PAH (as phenanthrene) per weight of the stock base fluid sample. The PAH weight ratio is
0.001%, or 10 parts per million (ppm). This limitation is based on the availability of base fluids that are free
of PAHs as detected by EPA Method 1654A, "PAH Content of Oil by High Performance Liquid
Chromatography with a UV Detector." Method 1654A is published in Methods for the Determination of
Diesel, Mineral and Crude Oils in Offshore Oil and Gas Industry Discharges (EPA-821-R-92-008).
EPA's promulgated PAH content limitation is technically available. Producers of several SBF base
fluids have reported to EPA that their base fluids are free of PAHs, including lOs, LAOs, vegetable esters,
low viscosity esters, certain enhanced mineral oils, synthetic paraffins, certain non-synthetic paraffins, and
others. The use of these fluids can accommodate the broad variety of drilling situations faced by industry in
offshore waters. Compliance with the stock BAT limitation and NSPS on PAH content can be achieved by
product substitution.
3.3.2.2 Sediment Toxicity Technical Availability
EPA has promulgated a sediment toxicity stock base fluid limitation that only allows the discharge
of SBF-cuttings using SBF base fluids as toxic or less toxic, but not more toxic, than C16-C18 lOs.
Alternatively, this limitation could be expressed in terms of a "sediment toxicity ratio" which is defined as
10-day LC50 of C16-C18 lOs divided by the 10-day LC50 of stock base fluid being tested. EPA is
promulgating a sediment toxicity ratio of less than 1.0. Compliance with this limitation is determined by the
10-day Leptocheirus plumulosus sediment toxicity test (ASTM E1367-92: "Standard Guide for Conducting
10-day Static Sediment Toxicity Tests With Marine and Estuarine Amphipods," supplemented with the
preparation procedure specified in Appendix 3 of Subpart A of 40 CFR 435).
To support the final rule, EPA and other researchers conducted numerous 10-day L. plumulosus
sediment toxicity tests on various SBF base fluids with natural and formulated sediments. Nearly all SBF
base fluids have lower sediment toxicity than diesel and mineral oil. Some SBF base fluids, however, show
greater sediment toxicity than other SBF base fluids.: The base fluids meeting this limitation include
vegetable esters, low viscosity esters, lOs, and some PAOs.:
EPA finds this limit to be technically available through product substitution because information in
the rulemaking record supports the findings that vegetable esters, low viscosity esters, and lOs have
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performance characteristics enabling them to be used in the wide variety of drilling situations in offshore
waters and to meet the promulgated limit.
EPA selected the C16-C18IO, which is the most popular drilling fluid in the Gulf of Mexico, as the
basis for the sediment toxicity rate ratio limitation instead of the vegetable ester or low viscosity ester for
several reasons: (1) EPA does not believe that vegetable esters can be used in all drilling situations; and (2)
EPA does not have sufficient field testing information supporting the use of low viscosity esters in all drilling
situations. Operators may not be encouraged to switch from OBFs or WBFs to SBF if only vegetable ester-
or low viscosity ester-SBFs could be discharged. As previously stated, EPA is promoting the appropriate
conversion from OBF- and WBF-drilling to SBF-drilling in order to reduce pollutant loadings and NWQI.
Due to demonstrated or potential technical limitations of vegetable esters or low viscosity esters, EPA
estimates that the pollutant loadings and NWQIs associated with establishing vegetable esters or low
viscosity esters as the basis for stock limitations are similar to the pollutant loadings and NWQIs associated
with the zero discharge option for all SBF-cuttings. EPA finds these increases in pollutant loadings and
NWQIs as unacceptable.
The SBF rulemaking record indicates that drilling fluids that meet the stock base fluid sediment
toxicity limitation and standard (e.g., internal olefins) will meet all drilling requirements in the OCS. EPA
did not base the stock base fluid sediment toxicity limitation and standard on vegetable esters or low
viscosity esters for two reasons. First, EPA documented technical limitations of vegetable esters in the deep
water environment; second, EPA did not have enough information to make the determination that low
viscosity esters can be used in all or nearly all drilling operations in the OCS. However, EPA did provide an
incentive in the way of a higher ROC limitation for the use of esters or their equivalent with respect to
sediment toxicity.
3.3.2.3 Biodegradation Rate Technical Availability
EPA is promulgating a biodegradation stock base fluid limitation that would only allow the discharge
of SBF-cuttings using SBF base fluids that degrade as fast or greater than C16-C18 lOs. Alternatively, this
limitation could be expressed in terms of a "biodegradation rate ratio" which is defined as the percent
degradation of C16-C18 lOs divided by the percent degradation of stock base fluid being tested, both at 275
days. EPA is promulgating a biodegradation rate ratio of less than 1.0. As stated in the April 2000 NODA,
EPA is promulgating the use of the marine anaerobic closed bottle biodegradation test (i.e., ISO
11734:1995) with modifications for compliance with this biodegradation BAT limitation. The technology
basis for this limitation is product substitution. Industry and EPA research efforts conducted in support of
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the SBF final rule indicate the order of degradation, from fastest to slowest, is: vegetable and low viscosity
esters > LAO > IO > linear paraffin > mineral oil > PAO. To meet this limitation through product
substitution, the base fluids currently available for use include vegetable esters, low viscosity esters, LAO,
and lOs.
EPA finds this limit to be technically available through product substitution because information in
the rulemaking record supports the findings that vegetable esters, low viscosity esters, and lOs have
performance characteristics enabling them to be used in the wide variety of drilling situations in offshore
waters and to meet the promulgated limit. Marketing data given to EPA shows that IO SBFs are the most
popular SBFs used in the Gulf of Mexico.
The marine anaerobic closed bottle biodegradation test (i.e., ISO 11734:1995) is modified to make
the test more applicable to a marine environment. These modifications are listed in Appendix 4 of Subpart
A of 40 CFR 435 and include: (1) the laboratory shall use seawater in place of freshwater; (2) the laboratory
shall use marine sediment in place of digested sludge as an inoculum; and (3) the laboratory shall run the test
for 275 days.
EPA selected the closed bottle test because it models the ability of a drilling fluid to degrade
anaerobically. Industry comments to the April 2000 NODA report the results of seabed surveys.5 These
seabed surveys and the scientific literature indicate that the environments under cuttings piles are anaerobic
and that the recovery of seabeds did not occur in acceptable periods of time when drilling fluids cannot
anaerobically degrade (e.g., diesel oils, mineral oils). The scientific literature also indicates that there is no
known mechanism for initiation of anaerobic alkane biodegradation.10 The general anaerobic microbiology
literature indicates that metabolic pathways are just beginning to be determined for anaerobic biodegradation
of linear alkanes. The anaerobic biodegradability of the SBF base fluid represents an essential prerequisite
for the prevention of long-term persistence of SBFs and deleterious impacts on marine sediments.11
Therefore, EPA considers the control of anaerobic degradation as the most environmentally relevant way to
ensure the biodegradation of SBF under cuttings piles and other anaerobic environments for the recovery of
benthic organisms and environments in an acceptable period.
EPA has selected the C16-C18 IO as the basis for the biodegradation rate ratio limitation instead of
the vegetable ester or low viscosity ester for two reasons: (1) EPA does not believe that vegetable esters can
be used in all drilling situations; and (2) EPA does not have sufficient field testing information that low
viscosity esters can be used in all drilling situations. Operators may not be encouraged to switch from OBFs
or WBFs to SBF if only vegetable ester- or low viscosity ester-SBFs could be discharged. As previously
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stated, EPA is promoting the appropriate conversion from OBF- and WBF-drilling to SBF-drilling in order
to reduce pollutant loadings and NWQI. Due to demonstrated or potential technical limitations of vegetable
esters or low viscosity esters, EPA estimates that the pollutant loadings and NWQIs associated with
establishing vegetable esters or low viscosity esters as the basis for stock limitation are similar to the
pollutant loadings and NWQIs associated with the zero discharge option for all SBF-cuttings. EPA finds
these increases in pollutant loadings and NWQIs as unacceptable. Nevertheless, due to EPA's information
(primarily laboratory data) that indicates that esters provide better environmental performance in terms of
sediment toxicity and biodegradation, EPA is promulgating a higher ROC limitation and standard where
esters are used to encourage operators to use esters when possible.
The SBF rulemaking record indicates that drilling fluids meeting the stock base fluid biodegradation
limitation and standard (i.e., internal olefms) will meet all drilling requirements in the OCS. EPA did not
base the stock base fluid biodegradation limitation and standard on vegetable esters or low viscosity esters
for two reasons: (1) the documented technical limitations of vegetable esters in the deep water environment;
and (2) insufficient information to make the determination that low viscosity esters can be used in all or
nearly all drilling operations in the OCS. However, EPA did provide incentives in the way of a higher ROC
limitations for the use of esters or their equivalent with respect to biodegradation.
3.3.2.4 Economic Achievability of Stock Base Fluid Controls
EPA finds that the promulgated stock base fluid controls are economically achievable. Industry
representatives have told EPA that while the synthetic base fluids are more expensive than diesel and
mineral oil base fluids, the savings in discharging the SBF-cuttings versus land disposal or injection of OBF-
cuttings (as required under current regulations) more than offsets the increased cost of SBFs. Moreover,
the reduced time to complete a well with SBF as compared with OBF- and WBF-drilling can be significant
(i.e., days to weeks). This reduction in time translates into lower rig rental costs for operators. Thus,
operator costs are lower even with the more expensive SBF provided the drill cuttings with adhering SBF
can be discharged. The stock base fluid limitations outlined above and promulgated by EPA are technically
achievable through product substitution with the use of the currently widely used SBFs based on lOs
($160/bbl), vegetable esters ($250/bbl), and low viscosity esters ($300/bbl).12 For comparison, diesel oil-
based drilling fluid costs about $70/bbl, and mineral oil-based drilling fluid costs about $90/bbl. According
to industry sources, currently in the Gulf of Mexico the most widely used and discharged SBFs are, in order
of use, based on lOs, LAOs, and vegetable esters. Because the stock limitations allow the continued use of
the IO- and ester-SBFs, EPA attributes no additional cost due to the stock base fluid requirements other
than monitoring (testing and certification) costs. EPA also examined costs to the few operators that have
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been using less costly SBFs that don't meet these requirements (particularly anaerobic degradation) and
have found these costs to be economically achievable (see SBF Economic Analysis). EPA estimates that
dischargers will satisfy: (1) the base fluid stock sediment toxicity and biodegradation limitations by having
suppliers monitor once annually; and (2) the PAH and formation oil limitations by having suppliers monitor
each batch of stock SBF.
EPA also considered NWQIs in selecting the controlled discharge option for SBF-cuttings (i.e.,
BAT/NSPS Option 2).
3.3.3 Discharge Limitations Technical Availability and Economic Achievability
3.3.3.1 Formation Oil Contamination of SBF-Cuttings
EPA has promulgated a BAT limitation of zero discharge to control formation oil contamination on
SBF-cuttings. EPA is also promulgating a screening method (Reverse Phase Extraction [RPE] method
presented in Appendix 6 to Subpart A of Part 435) and a compliance assurance method (Gas
Chromatograph/Mass Spectrometer [GC/MS] method presented in Appendix 5 to Subpart A of Part 435) to
demonstrate compliance with this zero discharge requirement.
Formation oil is an "indicator" pollutant for the many toxic and priority pollutant pollutants present
in formation (crude) oil (e.g., aromatic and polynuclear aromatic hydrocarbons). The RPE method is a
fluorescence test and is appropriately "weighted" to better detect crude oils. These crude oils contain more
toxic aromatic and PAH pollutants and show brighter fluorescence (i.e., noncompliance) in the RPE method
at lower levels of crude oil contamination. Under the final rule, approximately 5% of all (all meaning a large
representative sampling) formation oils would fail (not comply) at 0.1% contamination of SBFs and 95% of
all formation oils will fail at 1.0% contamination of SBFs. The majority of formation oils will fail at 0.5%
contamination of SBFs. Because the RPE method is a relative brightness test, GC/MS is promulgated as a
confirmatory compliance assurance method when the results from the RPE compliance method are in doubt
by either the operator or the enforcement authority. Results from the GC/MS method will supersede those
of the RPE method. EPA is also requiring that dischargers verify and document that a SBF is free of
formation oil contamination before initial use of the SBF. The GC/MS method will be used to verify and
document the absence of formation oil contamination in SBFs.
EPA intends that the BAT limitation promulgated on formation (crude) oil contamination in SBF is
no less stringent that the existing BAT limitation on WBF through the static sheen test (Appendix 1 of
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Subpart A of 40 CFR 435). In most cases, the static sheen test detects formation oil contamination in WBF
down to 1% and in some cases down to 0.5%. 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 be
disposed of 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 current rules that industry can economically afford.
EPA has determined that essentially no costs are associated with this requirement other than monitoring and
reporting costs, which are minimal costs for this industry, but are incorporated into the cost and economic
analyses.
3.3.3.2 Retention of SBF on SBF-Cuttings
EPA has promulgated BAT limitations controlling the amount of SBF discharged with SBF-cuttings
for the offshore subcategory where SBF-cuttings may be discharged. As previously stated, limiting the
amount of SBF content in discharged cuttings controls: (1) the amount of toxic and non-conventional
pollutants in SBF that are discharged to the ocean; (2) the biodegradation rate of discharged SBF; and (3)
the potential for SBF-cuttings to develop cuttings piles and mats that are deleterious to the benthic
environment. The BAT limitations promulgated for controlling the amount of SBF discharged with SBF-
cuttings are averaged by hole volume over the well sections drilled with SBF. Those portions of the SBF-
cuttings waste stream that are retained for zero discharge (e.g., fines) are factored into the weighted well
average with a retention value of zero.
EPA evaluated the costs, cost savings, and technical performance of several technologies to recover
SBF from the SBF-cuttings discharge. EPA also investigated the use of Best Management Practices
(BMPs) to reduce the amount of SBF discharge on SBF-cuttings. Typical BMPs for SBF-cuttings include
regulating the flow and dispersion across solid control equipment screens and properly maintaining these
screens. EPA also considered NWQIs (e.g., land disposal requirements, fuel use, air emissions, safety, and
other considerations) in setting the SBF retention on SBF-cuttings BAT limitation.
The drilling fluid and drill cuttings undergo an extensive separation process by the solids control
system to remove drilling fluid from the drill cuttings. The solids control system is necessary to maintain
constant drilling fluid properties and/or change them as required by the drilling conditions. Drilling fluid
recovered from the solids control equipment is recycled into the active mud system (e.g., mud pits, mud
pumps) and back downhole. Drill cuttings discarded from the solids control equipment are a waste product.
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Drill cuttings are also cleaned out of the mud pits and from the solid separation equipment during
displacement of the drilling fluid system (i.e., accumulated solids).
Most drilling operators use, at a minimum, a solids control system typically consisting of primary
and secondary shale shakers in series with a "fines removal unit" (e.g., mud cleaner, decanting centrifuge).
The primary and secondary shale shakers remove the larger and smaller cuttings, respectively. The fines
removal unit removes the "fines" (i.e., low gravity solids) down to approximately 5 microns (10~6 meters).
Solids less than 5 microns are labeled as "entrained" and are unable to be removed by solids control
equipment. Because of their small size and large surface area per unit volume, the fines retain more drilling
fluid than an equal amount of larger cuttings coming off the shale shakers. This solid control equipment
configuration was labeled as "baseline" (i.e., representative of current industry practice) in the NODA. EPA
continues to use this solid control equipment configuration as baseline in the analyses supporting the final
rule.
EPA assessed the baseline performance using industry submitted ROC data received before and in
response to the NODA. EPA received sufficient additional cuttings retention data from Gulf of Mexico
sources to re-evaluate the discharges of the baseline solids control equipment (e.g., primary shale shaker,
secondary shale shaker, fines removal unit) to calculate a revised baseline long-term average retention value
of 10.2% by weight of SBF on cuttings. Despite the revision of the retention data, the revised long-term
average retention value is only slightly different than the 11% originally calculated for the February 1999
proposal and the 11.4% calculated for the NODA. This relative convergence of the various calculated
baseline performance averages provides further confidence in the accuracy of the baseline model and
associated data.
Operators also recover additional drilling fluid from drill cuttings discarded from the shale shakers
through the use of cuttings dryers (e.g., vertical or horizontal centrifuges, squeeze press mud recovery units,
High-G linear shakers). Since the February 1999 proposal and the NODA, the Gulf of Mexico offshore
drilling industry has increased its use of "add-on" cuttings drying equipment (i.e., "cuttings dryers") to
reduce the amount of SBF adhering to the SBF-cuttings prior to discharge. Specifically, in response to the
NODA, EPA received ROC data from approximately 45 Gulf of Mexico SBF well projects that used
cuttings dryers (e.g., vertical or horizontal centrifuges, squeeze press mud recovery units, High-G linear
shakers) to reduce the amount of SBF discharged. These 45 Gulf of Mexico SBF well projects represent a
broad representation of typical factors affecting solids control equipment performance which include: (1)
Gulf of Mexico formation types (e.g., shale, sand, salt); (2) rig types (e.g., drill tension leg platform, semi-
submersible); (3) drilling operation types (i.e., exploratory or development); and (4) water depth (i.e.,
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shallow or deep). Current data available to EPA indicate that these cuttings dryers can operate consistently
and efficiently when properly installed and maintained. Specifically, vendor-supplied data associated with
these cuttings dryer deployments suggest that the overall cuttings dryer downtime (i.e., time when cuttings
dryer equipment is not operable) is approximately 1 to 2%. EPA finds this small downtime percentage as
acceptable.
EPA discussed how it revised the BAT/NSPS-level solids control equipment configuration used in
its analyses in the NODA. EPA also discussed a range of management options regarding the BAT limitation
for SBF retention on SBF-cuttings: (1) two discharges from the BAT/NSPS-level solids control equipment
configuration (i.e., one discharge from the cuttings dryer and another discharge from the fines removal unit);
(2) one discharge from the BAT/NSPS-level solids control equipment configuration (i.e., one discharge from
the cuttings dryer with the fines from the fines removal unit captured for zero discharge); and (3) zero
discharge of SBF-cuttings. These three options are labeled as BAT/NSPS Option 1, BAT/NSPS Option 2,
and BAT/NSPS Option 3, respectively. EPA estimates that 97% and 3% of the total cuttings are generated
by the cuttings dryer and fines removal unit, respectively.
EPA developed two numerical well averaged ROC limitations (i.e., one for SBFs with the stock
base fluid performance similar to esters and another for SBFs with the stock base fluid performance similar
to C16-C18 lOs) and based both of these ROC limitations on the technology of only one discharge from the
cuttings dryer with the fines from the fines removal unit captured for zero discharge (i.e., BAT/NSPS
Option 2). The numerical well averaged ROC maximum limitation for SBFs (i.e., 9.4%) with the
environmental characteristics of esters is based on a combination of data from horizontal centrifuge, vertical
centrifuge, squeeze press, and High-G linear shaker cuttings dryer technologies. The numerical well
averaged ROC maximum limitation for SBFs (i.e., 6.9%) with the environmental characteristics of C16-C18
internal olefins is based on a combination of data from horizontal and vertical centrifuge cuttings dryer
technologies. EPA estimates that operators, generally installing new equipment where none has been used
in the past, will be able to choose from among the better technologies, designs, operating procedures, and
maintenance procedures that EPA has considered to be among the best available technologies. EPA data
demonstrate that operators properly using these cuttings dryer technologies (e.g., vertical centrifuge,
horizontal centrifuge, squeeze press, High-G linear shaker) will be able to comply with these final ROC
numerical limitations. Data submitted to EPA show that operators using the vertical centrifuge and
horizontal centrifuge are capable of achieving the lower ROC limitation (i.e., 6.9%). Data submitted to EPA
also show that operators using the vertical centrifuge, horizontal centrifuge, squeeze press, and High-G
linear shaker are capable of achieving the higher ROC limitation (i.e., 9.4%).
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EPA developed the two ROC limitations because EPA used a two part approach to control SBF-
cuttings discharges. The first part is the control of which SBFs are allowed for discharge through use of
stock limitations (e.g., sediment toxicity, biodegradation, PAH content, metals content) and discharge
limitations (e.g., diesel oil prohibition, formation oil prohibition, sediment toxicity, aqueous toxicity). The
second part is the control of the quantity of SBF discharged with SBF-cuttings. As previously stated, EPA
and industry sediment toxicity and biodegradation laboratory studies show that both vegetable esters and low
viscosity esters have better environmental performance than all other SBF base fluids. However, because
the technical availability of product substitution with esters was not demonstrated across the offshore
subcategory, EPA rejected the option of basing sediment toxicity and biodegradation stock limitations and
standards on vegetable esters and low viscosity esters. EPA is sufficiently satisfied, however, that both
esters provide better environmental performance (e.g., sediment toxicity, biodegradation). Consequently,
EPA is promulgating a higher retention on cuttings discharge limitation to encourage operators to use esters
when possible. EPA estimates that a higher retention on cuttings discharge limitation for esters is equivalent
to the same level of control as a lower retention on cuttings discharge limitation for all other SBFs that have
poorer sediment toxicity and biodegradation performances.
In response to the NODA, EPA received comments from an ester-SBF manufacturer that EPA
should create an incentive for operators to use ester-SBFs by basing the ROC limitation for ester-SBFs on
baseline solids control equipment (e.g., primary and secondary shale shakers, fines removal unit).9'13 They
argued that the superior laboratory performance of these fluids in terms of sediment toxicity and
biodegradation justifies allowing them to be discharged with a ROC limitation based on baseline solids
control equipment. EPA estimates that a ROC BAT limitation based on the baseline solids control
equipment is 15.3%.
While EPA is willing to expand the technology basis to allow the use of less effective cuttings dryers
for ester-SBFs (e.g., squeeze press, High-G linear shakes), EPA is unwilling to entirely abandon the use of
cuttings dryers for ester-SBF drilling operations. EPA is not setting a higher ROC limitation for SBFs with
the environmental performance of ester-SBFs based on baseline solids control technology because the
environmental improvement resulting from the use of improved solids control technology (i.e., cuttings
dryers) outweighs the incremental ester laboratory sediment toxicity and biodegradation performance over
lOs. Cuttings dryers promote pollution prevention through increased re-use of drilling fluids and prevent
significant amounts of pollutants from being discharged to the ocean.
EPA provides for variability from the long term average (LTA) of performance data from the
candidate treatment technology or technologies. The LTA performance of the baseline solids control
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technology is 10.2%, as compared to the LTA of 4.8% based on data from all four cutting dryer
technologies. This translates into a difference of 118 million pounds per well of pollutant discharges to the
ocean between current practice (i.e., 10.2%) and the improved solids control technologies (i.e., 4.8%). In
balancing the environmental effects of these additional ester-SBFs discharges controlled with the use of
baseline solids control technology against the environmental effects of lower lO-SBFs discharges controlled
with the use of cuttings dryers, EPA has concluded that the improvement in solids control technology
leading to lower values of ROC is a more significant factor than laboratory data for ester base fluids showing
lower sediment toxicity and higher biodegradation.
EPA also is not convinced that the difference in ROC limitations provides no incentive to use
esters-SBFs, as the ester-SBF manufacturer argues. EPA believes that the difference between 6.9% and
9.4% could provide an incentive for operators to use esters-SBFs. Operators may find that it is worthwhile
to purchase ester-SBFs in order to be able to operate with even a greater margin of flexibility under a limit
of 9.4% as compared to 6.9%.
As the rule is performance based, EPA is not prohibiting the discharge of SBF-cuttings from the
fines removal unit in order to comply with the base fluid retained on cuttings discharge BAT limitation.
Operators are only required to show that the volume-weighted average of all their SBF-cuttings discharges is
below the discharge BAT limitation. EPA expects that most operators will be able to discharge cuttings
from the cuttings dryer and fines removal unit and comply with this discharge BAT limitation. If, for
example, the average retention of SBF on SBF-cuttings from a cuttings dryer is 6.00%, the average
retention of SBF on SBF-cuttings from a fines removal unit is 12.00%, and the fines are observed to
comprise 3% of the total cuttings discharged, then the well average is 6.18% [i.e., (0.97)(6.00%) +
(0.03)(12.00%) = 6.18%]. If the well average for SBF retention from the cuttings dryer exceeds the
discharge limit, then in order to comply with this discharge BAT limitation all cuttings must be injected
onsite or hauled to shore for land disposal. EPA finds that if this is the case, the limit is technologically
available because operators have transported OBFs to shore since 1986 and have transported WBFs that do
not meet the existing effluent limitations and standards since 1993.
EPA finds that both ROC limitations (i.e., 6.9%, 9.4%) are technically available to the industry
because it is based on product substitution and a statistical analysis of ROC performance from drilling
conditions throughout offshore waters. The BAT limitations for controlling the amount of SBF discharged
with SBF-cuttings are calculated such that nearly all well averages for retention are expected to meet these
values using the selected technologies without any additional attention to design, operation, or maintenance.
EPA data demonstrate that operators properly using these cuttings dryer technologies (e.g., vertical
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centrifuge, horizontal centrifuge, squeeze press, High-G linear shaker) will be able to comply with these final
ROC numerical limitations because: (1) these limits allow for variation in formation characteristics that may
not exist in the United States; (2) operators, generally installing new equipment where none has been used in
the past are able to choose from among the better technologies, designs, operating procedures, and
maintenance procedures that EPA considers to be among the best available technologies; and (3) operators
may elect to use SBFs with the stock base fluid performance of esters and horizontal or vertical centrifuge
cuttings dryers to achieve a ROC well average well below the 9.4% ROC limitation.
Data used in the calculation of the numerical limits exclude retention results submitted without
backup calculations (i.e., without raw retort data) and include data from drilling operations in foreign waters
(e.g., Canada). EPA excluded ROC data without raw retort data (e.g., masses and volumes of cuttings
samples and recovered liquids taken during the retort method by the field technician) due to concerns over
data quality (e.g., no independent method to check data quality). EPA included ROC data from Canadian
drilling operations to incorporate the variability of cuttings dryer performance in harder and less permeable
formations that generally lead to higher ROC values. EPA estimates that the major factors leading to higher
ROC values for all solids control equipment include: (1) slower rates of penetration; (2) formations that are
harder and less permeable; and (3) selection of certain drill bits. The Canadian ROC data come from
formations that are generally much harder and less permeable than what is observed in the Gulf of Mexico.
These harder formations generally lead to slower rates of penetration. The less permeable Canadian
formations lead to fewer downhole losses of SBF. Downhole losses require the addition of fresh SBF to
maintain volume requirements for the active mud system. These additions of fresh SBF to the active mud
system help control the potential of build-up of fines. In addition, operators often use PDC drill bits in order
to grind through the hard Canadian formations. This grinding action leads to smaller cuttings than is what is
observed in the Gulf of Mexico. The smaller cuttings have more surface area for SBF than larger cuttings
and generally have higher ROC values. Consequently, EPA's use of Canadian data in its analyses
incorporate sufficient variability to model the formations in Gulf of Mexico, offshore California, Cook Inlet,
Alaska, and other offshore U.S. waters where EPA does not have ROC data.
EPA finds that both well-average discharge BAT ROC limitations (e.g., 6.9%, 9.4%) for base fluid
on wet cuttings are economically achievable. According to EPA's analysis, in addition to reducing the
discharge of SBFs associated with the cuttings, EPA estimates that this control will result in a net savings of
$48.9 million ($1999) dollars per year. This savings results, in part, because the value of SBFs recovered is
greater than the cost of installation of the improved solids control technology. EPA also examined costs to
the few operators that have been using less costly SBFs that don't meet these requirements (particularly
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anaerobic degradation) and have found these costs to be economically achievable (see SBF Economic
Analysis).
EPA concluded that a zero discharge requirement for SBF-cuttings from existing sources and the
subsequent increase use of OBFs and WBFs would result in: (1) unacceptable NWQIs; and (2) more
pollutant loadings to the ocean due to operators switching from SBFs to less efficient WBFs. For these
reasons, EPA rejected the BAT zero discharge option for SBF-cuttings from existing sources.
In the NODA, EPA requested comments on the issue of rig compatibility with the installation of
cuttings dryers (e.g., vertical or horizontal centrifuges, squeeze press mud recovery units, High-G linear
shakers). EPA received general information on the problems and issues related to cuttings dryer installations
from API/NOIA. API/NOIA stated that not all rigs are capable of installing cuttings dryers.: In late
comments, some industry commentors submitted initial data indicating that 48 of the 223 Gulf of Mexico
drilling rigs are not capable of having a cuttings dryer system installed due to either rig space and/or rig
design without prohibitive costs or rig modifications.14 Upon a further, more extensive review of Gulf of
Mexico rigs, these same commentors concluded that 30 of 234 Gulf of Mexico drilling rigs are not capable
of having a cuttings dryer system installed due to either rig space and/or rig design without prohibitive costs
or rig modifications.15 EPA also received late comments from one operator, Unocal, stating that 36 of 122
Unocal wells drilled between late 1997 and mid-2000 were drilled with rigs that do not have 40 foot x 40
foot space available for a cuttings dryer installation.16 The API/NOIA rig survey and the Unocal rig survey
identified most of the same rigs as unable to install cuttings dryers. However, two rigs (i.e., Parker 22,
Nabors 802) identified in the Unocal rig survey as having no space for a cuttings dryer installation were
identified in the API/NOIA rig survey as each having a previous cuttings dryer installation. Finally, EPA
received information from a drilling fluid manufacturer and cuttings dryer equipment vendor, M-I Drilling
Fluids, stating that they are not aware of any Gulf of Mexico rig not capable of installing a cuttings dryer.17
EPA finds that current space limitations for cuttings dryers do not require a 40 foot x 40 foot space.
Specifically, EPA has in the record information gathered during EPA's October 1999 site visit and
information supplied by API/NOIA, MMS, and equipment vendors. EPA received information from a
drilling fluid manufacturer and cuttings dryer equipment vendor, M-I Drilling Fluids, stating that they are not
aware of any GOM rig not capable of installing a cuttings dryer.17 Another cuttings dryer equipment
vendor, JB Equipment, asserted that there are at most only a few rigs that pose questionable installation
problems and that they have yet to survey a rig that they could not install a cuttings dryer.22 JB Equipment
also stated that inexperience with cuttings dryer installations may inhibit the ability of operators or rig owners
to properly judge whether a cuttings dryer can be installed. JB Equipment cited an example where the
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operator concluded that a cuttings dryer could not be installed on a rig (Nabors 803) while JB Equipment
surveying efforts identified the cuttings dryer installation for the same rig as one of the simplest installations
JB Equipment performs. MMS also concluded that rigs do not need a 40 foot x 40 foot space to install a
cuttings dryer and that, with the exception of a few jackup and platform rigs, there should not be any
significant issues related to installing cuttings dryers on OCS drilling rigs.21 API/NOIA estimated that 150
square feet are required for a cuttings dryer installation in order to meet the ROC BAT limitation and
NSPS.: EPA also estimates that the minimum height clearance for a typical cuttings dryer installation is 6
feet. The API/NOIA estimate is based on the installation of a horizontal centrifuge cuttings dryer (i.e.,
MUD-6). The Unocal estimate is based on the vertical centrifuge cuttings dryer and is also characterized by
other industry representatives and MMS as too high.15'21 EPA's estimate of a typical vertical centrifuge
installation is 15 feet x 15 feet (i.e., 225 square feet) with a minimum height clearance of 11 feet. EPA
based the ROC BAT limitation and NSPS (e.g., 6.9%) on the use of both these cuttings dryers for SBFs
with the stock limitations of C16-C18 lOs. Based on comments from operators, equipment vendors, and
MMS, EPA believes that most of these shallow water rigs have the requisite 150-225 square feet available
to install a cuttings dryer. Therefore, EPA finds that operators are not required to have a 1,600 square foot
space for a cuttings dryer installation in order to meet the ROC BAT limitation and NSPS. Proper spacing
and placement of cuttings dryers in the solids control equipment system should prevent installation
problems.
Moreover, current usage shows that SBFs are used in only 14% of the total number of wells drilled
in shallow water. The majority of SBF usage is in deep water where nearly all rigs are capable of installing
cuttings dryers.15 Therefore, EPA estimates that only a very small percentage of rigs will not be able to do
one of the following in order to drill: (1) install cuttings dryers; (2) use WBFs; and (3) perform zero
discharge operations (e.g., injection or onshore disposal). Operators that cannot install cuttings dryers,
cannot use WBFs, and cannot perform zero discharge operations should apply for a Fundamental Different
Factors (PDF) waiver in order for EPA to consider the case-specific conditions (e.g., perform a variable
load and center of gravity analysis). Finally, EPA finds that only a small percentage of operators will be
forced to use OBFs and zero discharge operations due to their inability to use WBFs or install cuttings
dryers and EPA finds the NWQIs associated with these zero discharge operations as acceptable.
EPA has also decided that solids accumulated at the end of the well ("accumulated solids") and
wash water are associated with drill cuttings and are therefore, not controlled by the zero discharge
requirement for SBFs not associated with drill cuttings. EPA has decided to control accumulated solids and
wash water under the discharge requirements for cuttings associated with SBFs. The amount of SBF base
fluid discharged with discharged accumulated solids will be estimated using procedures in Appendix 7 to
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Subpart A of 40 CFR 435 and incorporated into the base fluid retained on cuttings numeric limitation or
standard. The source of the pollutants in the accumulated solids and associated wash water are drill cuttings
and drilling fluid solids (e.g., barite). The drill cuttings and drilling fluid solids can be prevented from
discharge with SBF-cuttings due to equipment design (e.g., sand traps, sumps) or improper maintenance of
the equipment (e.g., failing to ensure the proper agitation of mud pits). EPA agrees with commentors that
the discharge of SBF associated with accumulated solids in the SBF active mud system and the associated
wash water is normally a one-time operation performed at the completion of the SBF well (e.g., cleaning out
mud pits and solids control equipment).
The quantity of SBF typically discharged with accumulated solids and wash water is relatively
small. The SBF fraction in the 75 barrels of accumulated solids is approximately 25% and generally only
very small quantities of SBF are contained in the 200 to 400 barrels of associated equipment wash water.
Current practice is to retain accumulated solids for zero discharge or recover free oil from accumulated
solids prior to discharge. Since current practice is to recover free oil and discharge accumulated solids, the
controlled discharge option for SBF-cuttings represents current practice and is economically achievable.
Moreover, recovering free oil from accumulated solids prior to discharge has no unacceptable NWQIs.
EPA defines accumulated solids and wash water as associated with drill cuttings. Therefore, operators will
control these SBF-cuttings wastes using the SBF stock limitations and cuttings discharge limitations. As
compliance with EPA's SBF stock limitations and cuttings discharge limitations does not require the
processing of all SBF-cuttings wastes through the solids control technologies (e.g., shale shakers, cuttings
dryers, fines removal units), operators may or may not elect to process accumulated solids or wash water
through the solids control technologies.
EPA has also promulgated a set of BMPs for operators to use in order to demonstrate compliance
with the numeric ROC limitation. By using this option, operators may reduce the retort monitoring
otherwise required to determine compliance with the numeric ROC limitation. This option combines the set
of BMPs that represent current practice with BMPs that are associated with the use of improved solids
control technology. This option is technologically available and economically achievable for the same
reasons that apply to compliance with the ROC numerical limitations. Examples of BMPs that represent
current practices are, for example, use of mud guns, proper mixing procedure, and elimination of settling
places for accumulated solids. Examples of BMPs associated with the use of the new solids control
technology are, for example, operating cuttings dryers in accordance with the manufacturer's specifications
and maintaining a certain mass flux. If operators elect to use this BMP option, they are required to
demonstrate compliance through limited retort monitoring of cuttings and additional BMP paperwork.
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3.3.2.3 Sediment Toxicity of SBF Discharged with Cuttings
As originally proposed in February 1999 and re-stated in April 2000, EPA is promulgating a BAT
limitation to control the maximum sediment toxicity of the SBF discharged with cuttings. This BAT
limitation controls the sediment toxicity of the SBF discharged with cuttings as a nonconventional pollutant
parameter and as an indicator for other pollutants in the SBF discharged with cuttings. Some of the toxic,
priority, and nonconventional pollutants in the SBF discharged with cuttings may include: (1) the base fluids
such as enhanced mineral oils, lOs, LAOs, PAOs, paraffinic oils, C12-C14 vegetable esters of 2-hexanol and
palm kernel oil, "low viscosity" C8 esters, and other oleaginous materials; (2) barite which is known to
generally have trace contaminants of several toxic heavy metals such as mercury, cadmium, arsenic,
chromium, copper, lead, nickel, and zinc; (3) formation oil which contains toxic and priority pollutants such
as benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and phenol; and (4) additives such as
emulsifiers, oil wetting agents, filtration control agents, and viscosifiers.
The sediment toxicity of the SBF discharged with cuttings is measured by the modified sediment
toxicity test (ASTM E1367-92: "Standard Guide for Conducting 10-day Static Sediment Toxicity Tests
With Marine and Estuarine Amphipods," supplemented with the preparation procedure specified in
Appendix 3 of Subpart A of 40 CFR 435) using a natural sediment or formulated sediment, 96-hour testing
period, and Leptocheirus plumulosus as the test organism. EPA is promulgating a sediment toxicity
limitation for the SBF discharged with cuttings at the point of discharge that would only allow the discharge
of SBF-cuttings using SBFs as toxic or less toxic, but not more toxic, than C16-C18 lOs SBFs. Alternatively,
this limitation is expressed in terms of a "SBF sediment toxicity ratio" which is defined as 96-hour LC50 of
C16-C18 lOs SBF divided by the 96-hour LC50 of the SBF being discharged with cuttings at the point of
discharge. EPA is promulgating a SBF sediment toxicity ratio of less than 1.0.
As previously stated, establishing discharge limits on toxicity encourages the use of less toxic drilling
fluids and additives. The modifications to the sediment toxicity test include shortening the test to 96-hours.
Shortening the test will allow operators to continue drilling operations while the sediment toxicity test is
being conducted on the discharged drilling fluid. Moreover, discriminatory power is substantially reduced
for the 10-day test on drilling fluid as compared to the 96-hour test (i.e., the 10-day test is of lower practical
use in determining whether a SBF is substantially different from OBFs). Finally, operators discharging
WBFs are already complying with a biological test at the point of discharge, the 96-hour SPP toxicity test,
which tests WBF aquatic toxicity using the test organism Mysidopsis bahia.
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The promulgated sediment toxicity limitation would be achievable through product substitution.
EPA anticipates that the base fluids meeting the sediment toxicity limitation would include vegetable esters,
low viscosity esters, and lOs. The reference C16-C18 lOs SBF is formulated to meet the specifications in
Table X-l and also is contained in Appendix 8 of Subpart A of 40 CFR 435. The sediment toxicity
discharge limitation is technically and economically achievable because it is based on currently available base
fluids that can be used and are used across the wide variety of drilling situations found in offshore waters.
EPA estimates minimal monitoring costs associated with this limitation. Additionally, the sediment toxicity
discharge limitation will not lead to an increase of NWQIs.
TABLE X-l
Properties for Reference Ci6-Ci8 lOs SBF Used in Discharge Sediment Toxicity Testing
Mud Weight of SBF Discharged
with Cuttings (pounds per gallon)
8.5- 11
11 -14
> 14
Reference C16-C18 lOs SBF
(pounds per gallon)
9.0
11.5
14.5
Plastic Viscosity (PV), centipoise (cP)
Yield Point (YP), pounds/ 100 sq. ft.
10-second gel, pounds/100 sq. ft.
10-minute gel, pounds/100 sq. ft.
Electrical stability, V
Reference C16-C18 lOs SBF
Synthetic to Water Ratio (%)
75/25
80/20
85/15
12-30
10-20
8- 15
12-30
>300
3.4 NSPS Technology Options Considered and Selected for Drilling Fluid Associated with Drill
Cuttings
The general approach followed by EPA for developing NSPS options was to evaluate the best
demonstrated SBFs and processes for control of priority toxic, 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 that it considered to
represent NSPS level of control applicable to the SBF-cuttings waste stream. Further, EPA has made a
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finding of no barrier to entry based upon the establishment of this level of control for new sources.
Therefore, EPA is promulgating that NSPS be established equivalent to BPT and BAT for conventional,
priority, and nonconventional pollutants. EPA concluded that NSPS are technologically and economically
achievable for the same reasons that BAT is available and BPT is practical. EPA also concluded that
NWQIs are reduced under the selected NSPS for new wells due to the increased efficiency of SBF drilling.
EPA concluded that a zero discharge requirement for SBF-cuttings from new sources and the
subsequent increase use of OBFs and WBFs would result in: (1) unacceptable NWQIs; and (2) more
pollutant loadings to the ocean due to operators switching from SBFs to less efficient WBFs.
For the same reasons that the BAT limitations promulgated in the final rule are technologically and
economically achievable, the promulgated NSPS are also technologically and economically achievable.
EPA's analyses show that under the SBF zero discharge option for all areas as compared to current practice
as a basis for new source standards there would be an increase of 3.4 million pounds of cuttings annually
shipped to shore for disposal in NOW sites and an increase of 10.2 million pounds of cuttings annually
injected. This zero discharge option would lead to an increase in annual fuel use of 18,067 BOE and an
increase in annual air emissions of 528 tons. Finally, the SBF zero discharge option for the Gulf of Mexico
would lead to an increase of 7.5 million pounds of WBF-cuttings being discharged to offshore waters. This
pollutant loading increase is a result of operators in offshore waters (in the Gulf of Mexico) switching from
efficient SBF drilling to less efficient WBF drilling. EPA found these levels of NWQIs unacceptable and
rejected the NSPS zero discharge option for SBF-cuttings from new sources, except in coastal Cook Inlet,
Alaska.
3.5 PSES and PSNS Technology Options Considered and Selected
Based on comments to the Coastal rule, the 1993 Coastal Oil and Gas Questionnaire, and other
information reviewed as part of this rule, EPA has not identified any existing offshore or coastal oil and gas
extraction facilities which discharge SBF and SBF-cuttings to publicly owned treatment works (POTWs),
nor are any new facilities projected to direct these wastes in such manner. EPA retains the zero discharge
requirement that exists in the current pretreatment standards for existing and new sources for all coastal
subcategory facilities because these wastes are incompatible and would interfere with POTW operations
(see Coastal Development Document [EPA-821-R-96-023], Chapter XIV, Section 3.1.3). As current
industry practice is zero discharge of SBFs and SBF-cuttings into POTWs, the zero discharge PSES and
PSNS requirements represent current practice and is technologically and economically achievable with no
additional NWQIs.
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3.6 Best Management Practices (BMPs) to Demonstrate Compliance with Numeric BAT
Limitations and NSPS for Drilling Fluid Associated with Drill Cuttings
Sections 304(e), 308(a), 402(a), and 501(a) of the CWA authorize the Administrator to prescribe
BMPs as part of effluent limitations guidelines and standards or as part of a permit. The BMP alternatives
to numeric limitations and standards in this final rule are directed, among other things, at preventing or
otherwise controlling leaks, spills, and discharges of toxic and hazardous pollutants in SBF cuttings wastes.
As discussed in the NODA, EPA considered three options for the final rule for the BAT limitation
and NSPS controlling SBF retained on discharged cuttings: (1) a single numeric discharge limitation with an
accompanying compliance test method; (2) allowing operators to choose either a single numeric discharge
limitation with an accompanying compliance test method, or as an alternative, a set of BMPs that employs
limited cuttings monitoring; or (3) allowing operators to choose either a single numeric discharge limitation
with an accompanying compliance test method or an alternative set of BMPs that employ no cuttings
monitoring. Under the third BMP option for SBF-cuttings (i.e., cuttings discharged and not monitored),
EPA also considered whether to require as part of the BMP option, the use of a cuttings dryer as
representative of BAT/NSPS or to make the use of a cuttings dryer optional.
EPA selected the second BMP option (i.e., allowing operators to choose either a single numeric
discharge limitation with an accompanying compliance test method, or as an alternative, a set of BMPs that
employs limited cuttings monitoring). EPA selected this option as it provides for a reasonable level of
flexibility and is based on quantifiable objective performance measures. EPA analyses show that cuttings
monitoring for the first third of the SBF footage drilled for a SBF well interval is a reliable indicator of the
remaining two-thirds of the SBF-interval.18> 19'20 Procedures for demonstrating compliance with the selected
BMP option are given in Appendix 7 to Subpart A of Part 435.
For the final rule, EPA did not have enough data from across a wide variety of drilling conditions
(e.g., formation, water depth, rig size) to demonstrate that BMPs without cuttings monitoring are equivalent
to a numeric ROC limitation or standard. Further, under a BMP option with no numeric limit there is no
objective performance measure. This presents a particular problem offshore, where real-time inspections are
not as practical as they are for land-based discharges. Therefore, EPA rejected the third BMP option and
cuttings dryer sub-option for SBF-cuttings (i.e., allowing operators to choose either a single numeric
discharge limitation with an accompanying compliance test method or an alternative set of BMPs that
employ no cuttings monitoring). EPA concluded that BMP option one and BMP option two demonstrate
the same level of compliance with the well averaged ROC limitation and standard.18 Therefore, EPA
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selected BMP option two over BMP option one to provide operators with greater flexibility to demonstrate
compliance with the well averaged ROC limitation and standard.
The BMP option promulgated in the final rule includes information collection requirements that are
intended to control the discharges of SBF in place of numeric effluent limitations and standards. These
information collection requirements include, for example: (1) training personnel; (2) analyzing spills that
occur; (3) identifying equipment items that might need to be maintained, upgraded, or repaired; (4)
identifying procedures for waste minimization; (4) performing monitoring (including the operation of
monitoring systems) to establish equivalence with a numeric cuttings retention limitation and to detect leaks,
spills, and intentional diversion; and (5) generally to periodically evaluate the effectiveness of the BMP
alternatives.
BMP option two also requires operators to develop and, when appropriate, amend plans specifying
how operators will implement BMP option two, and to certify to the permitting authority that they have
done so in accordance with good engineering practices and the requirements of the final regulation. The
purpose of those provisions is, respectively, to facilitate the implementation of BMP option two on a site-
specific basis and to help the regulating authorities to ensure compliance without requiring the submission of
actual BMP Plans. Finally, the recordkeeping provisions are intended to facilitate training, to signal the need
for different or more vigorously implemented BMP alternatives, and to facilitate compliance assessment.
4. REFERENCES
1. Moran, Robert, National Ocean Industries Association, Re: National Ocean Industries Association,
American Petroleum Institute, Offshore Operators Committee, and Petroleum Equipment Suppliers
Association Comments on "Effluent Limitations Guidelines for Oil and Gas Extraction Point Source
Category," Proposed Rule 65 FR 21548 (April 21, 2000). 6/20/00. (Record No. IV.A.a.13)
2. Farmer, Janis M., BP Amoco, Letter to C. Johnston, EPA, in response to SBF NODA. 6/29/00.
Attachment 4: QTEC "BMP" Reports, QTECH LTD Reports Ocean America and Discoverer 534.
(Record No. IV.A.a.26)
3. Van Slyke, Don, Unocal. Unocal Comments; Effluent Limitations Guidelines for the Oil and Gas
Extraction Point Source Category; Proposed Ruling (40 CFR 435). 6/9/00. (Record No. IV.A.a.3)
4. Xiao, L. and C. Piatti. 1995. Biodegradable Invert Oil Emulsion Drilling Fluids for Offshore
Operations: A Comprehensive Laboratory Evaluation and Comparison, SPE 29941. (Record No.
A.a.13)
5. Young, S, Anchor Drilling Fluids. 1994. Life After Oil Based Muds? - The Technical and
Environmental Benefits of "Pseudo-Oil Based Muds." (Record No. A.a. 13)
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6. Patel, A.D., J.M. Wilson, B.W. Loughridge. 1999. Impact of Synthetic-Based Drilling Fluids on
Oilwell Cementing Operations, SPE 50726. (Record No. A.a.13)
7. Friedheim, J.E. and R.M. Pantermuehl, M-I Drilling Fluids. 1993. Superior Performance with
Minimal Environmental Impact: A Novel Nonaqueous Drilling Fluid, SPE/IADC 25753. (Record
No. A.a.13)
8. Friedheim, J.E. and H.L. Conn, M-I Drilling Fluids. 1995. Second Generation Synthetic Fluids in
the North Sea: Are They Better? SPE 35061. (Record No. A.a.13)
9. Hall, John, Baroid Drilling Fluids, Re: Effluent Limitations Guidelines for the Oil and Gas Extraction
Point Source Category; Proposed Rule 40 CFR Part 435 April 21, 2000. 6/19/00. (Record No.
IV.A.a.7)
10. Candler, J.E., S.P. Rabke, A.J.J. Leuterman, Predicting the Potential Impact of Synthetic-Based
Muds with the Use of Biodegradation Studies, SPE 52742, 1999. (Record No. IV.A.a.13,
Attachment BIODEG-62)
11. Steber, J., C.-P. Ilerold and J.M. Limia. 1995. Comparative Evaluation of Anaerobic
Biodegradability of Hydrocarbons and Fatty Derivatives Currently Used as Drilling Fluids.
Chemoshpere, Vol. 31, No. 4, pp. 3105-3118. (Record No.I.D.b.26).
12. Candler, J., M-I Drilling Fluids. Email to C.A. Johnston RE: unit costs for various muds. 10/23/00.
(Record No. IV.B.a. 13)
13. Martin, D., Centrifugal Services, Inc., Letter to C. Johnston, EPA. 8/2/00. (Record No.
IV.A.a.33).
14. Angelle, R. and P. Scott. 2000. Rig Survey Related to Installation Cost and Operational Costs of
"Cuttings Dryers" to Reduce the Retention of Synthetic Based Mud on Cuttings Discharge.
(Record No. IV.B.b.33)
15. Angelle, R. and P. Scott. 2000. Rig Survey Update Focusing on the Number of Rigs/Platforms
Where Cuttings Dryers Could Not be Installed. Prepared by the Technology Assessment
Workgroup of Synthetic Based Mud Research Consortium (API and NOIA) in Conjunction with
Cuttings Dryer Equipment Vendor Representatives. 11/9/00. (Record No. IV.B.b.34)
16. O'Donnell, K., Unocal. 2000. Letter to M. Rubin, EPA transmitting additional information.
10/26/00. (Record IV.B.b.31)
17. Candler, J., M-I. Email to C. Johnston, EPA concerning ability of service companies to place
cuttings dryers on rigs. 11/10/00. (Record No. IV.B.b.32)
18. EPA. 2000. Statistical Analyses Supporting Final Effluent Limitations Guidelines and Standards
for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas
Extraction Point Source Category. EPA-821-B-00-015. (Record No. IV.C.a.3)
19. Hanni, G., J. Hartley, R. Monro, A. Skullerd. 1998. Evolutionary Environmental Management of
Drilling Discharges: Results without Cost Penalty, SPE 46617. (Record No. III.B.a.18)
20. Farmer, J.M. 2000. Email to C. Johnston, EPA, Data for the SBM Notice of Data Availability.
3/8/00. (Record No. III.B.b. 15)
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21. Danenberger, E., MMS. Email to C. Johnston, EPA, FW: rig installation issue... 12/15/00.
(Record No. IV.B.a.28)
22. Hurst, B. and J. Hurst, JB Equipment. Email to C. Johnston, EPA, RE: rig installation issues.
12/12/00. (Record No. IV.B.b.48)
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CHAPTER XI
BEST MANAGEMENT PRACTICES
Sections 304(e), 308(a), 402(a), and 501(a) of the CWA authorize the Administrator to prescribe
BMPs as part of effluent limitations guidelines and standards or as part of a permit. The use of BMPs,
either as an alternative to or to reduce the sampling and analysis to demonstrate compliance with numeric
limitations and standards of the final rule, are directed, among other things, at preventing or otherwise
controlling leaks, spills, and discharges of toxic and hazardous pollutants in SBF cuttings wastes (see
Chapter 7 for a list of the toxic and hazardous pollutants controlled by these BMPs). Typical BMPs for
SBF-cuttings include regulating the flow and dispersion across solid control equipment screens and properly
maintaining these screens.
As discussed in the April 2000 NODA (65 FR 21568), EPA considered three options for the final
rule for the BAT limitation and NSPS controlling SBF retained on discharged cuttings: (1) a single numeric
discharge limitation with an accompanying compliance test method; (2) allowing operators to choose either a
single numeric discharge limitation with an accompanying compliance test method, or as an alternative, a set
of BMPs that employs limited cuttings; or (3) allowing operators to choose either a single numeric discharge
limitation with an accompanying compliance test method or an alternative set of BMPs that employ no
cuttings monitoring. Under the third SBF-cuttings discharge BMP option (i.e., cuttings discharged and not
monitored), EPA also considered whether to require as part of the BMP option, the use of a cuttings dryer
as representative of BAT/NSPS or to make use of a cuttings dryer optional.
EPA has selected the second BMP option for the final rule (i.e., allowing operators to choose either
a single numeric discharge limitation with an accompanying compliance test method for the entire well
drilling, or as an alternative, a set of BMPs that employs limited cuttings monitoring to show compliance
with the ROC numerical discharge limitation). EPA selected this option as it provides for a reasonable level
of flexibility and is based on quantifiable performance measures. EPA analyses show that cuttings
monitoring for the first third of the SBF footage drilled for a SBF well interval is a reliable indicator of the
remaining two-thirds of the SBF-interval.l-2> 3 Procedures for demonstrating compliance with the selected
BMP option are given in Appendix 7 to Subpart A of Part 435.
XI-1
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For the final rule, EPA did not have sufficient data from across a wide variety of drilling conditions
(e.g., formation, water depth, rig size) to demonstrate that BMPs without cuttings monitoring are equivalent
to a numeric ROC limitation or standard. EPA is also concerned that a set of BMPs without cuttings
monitoring is not as objective to enforce. This is because with a numeric limitation or with the selected
BMP option with reduced cuttings monitoring, operators will need to keep records demonstrating
compliance with the numeric limitation. By contrast, under a BMP option with no numeric limit, there is no
objective performance measure. This presents a particular problem offshore, where real-time inspections
are not as practical as on land based industries.
Therefore, EPA rejected the third BMP option and cuttings dryer sub-option for SBF-cuttings (i.e.,
allowing operators to choose either a single numeric discharge limitation with an accompanying compliance
test method or an alternative set of BMPs that employ no cuttings monitoring). EPA concluded that BMP
option one and BMP option two demonstrate the same level of compliance with the well averaged ROC
limitation and standard. Therefore, EPA selected BMP option two over BMP option one to provide
operators with greater flexibility to demonstrate compliance with the well averaged ROC limitation and
standard.
EPA is also promulgating a set of BMPs for operators to use that demonstrates compliance with the
numeric ROC limitation and therefore reduces the retort monitoring otherwise required to determine
compliance with the numeric ROC limitation. This option combines the set of BMPs that represent current
practice with BMPs that are associated with the use of improved solids control technology. This option is
technologically available and economically achievable for the same reasons that apply to compliance with
the ROC numerical limitations. Examples of BMPs that represent current practices are, for example, use of
mud guns, ensuring proper mixing procedure, and elimination of settling places for accumulated solids.
Examples of BMPs associated with the use of the new solids control technology are, for example, operating
cuttings dryers in accordance with the manufacturer's specifications and maintaining a certain mass flux. If
operators elect to use this BMP option, they will be required to demonstrate compliance through limited
retort monitoring of cuttings and additional BMP paperwork. Paperwork requirements are detailed in
Appendix 7 of Subpart A of 40 CFR 435.
The BMP option promulgated in the final rule includes information collection requirements that are
intended to control the discharges of SBF in place of numeric effluent limitations and standards. These
information collection requirements include, for example: (1) training personnel; (2) analyzing spills that
occur; (3) identifying equipment items that might need to be maintained, upgraded, or repaired; (4)
XI-2
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identifying procedures for waste minimization; (5) performing monitoring (including the operation of
monitoring systems) to establish equivalence with a numeric cuttings retention limitation and to detect leaks,
spills, and intentional diversion; and (6) generally to periodically evaluate the effectiveness of the BMP
alternatives.
BMP option two also requires operators to develop and, when appropriate, amend plans specifying
how operators will implement BMP option two, and to certify to the permitting authority that they have
done so in accordance with good engineering practices and the requirements of the final regulation. The
purpose of these provisions is, respectively, to facilitate the implementation of BMP option two on a site-
specific basis and to help the regulating authorities ensure compliance without requiring the submission of
actual BMP Plans. Finally, the recordkeeping provisions are intended to facilitate training, to signal the need
for different or more vigorously implemented BMP alternatives, and to facilitate compliance assessment.
REFERENCES
1. EPA. 2000. Statistical Analyses Supporting Final Effluent Limitations Guidelines and Standards
for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas
Extraction Point Source Category. EPA-821-B-00-015. (Record No. IV.C.a.3)
2. Hanni, G., J. Hartley, R. Monro, A. Skullerd. 1998. Evolutionary Environmental Management of
Drilling Discharges: Results without Cost Penalty, SPE 46617. (Record No. III.B.a.18)
3. Farmer, J.M. 2000. Email to C. Johnston, EPA, Data for the SBM Notice of Data Availability.
3/8/00. (Record No. III.B.b. 15)
XI-3
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GLOSSARY AND ABBREVIATIONS
Act: The Clean Water Act.
ADEC: Alaska Department of Environmental Conservation.
Administrator: Administrator of the U.S. Environmental Protection Agency
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.
BOP: Blowout Preventer
bpd: Barrels per day.
BPJ: Best Professional Judgment.
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BPT: The best practicable control technology currently available, under section 304(b)(l) 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 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.
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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.
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 conventional
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 cut-
tings 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-Construction 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.
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Field: A geographical area in which a number of oil or gas wells produce hydrocarbons from an under-
ground 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.
Formation: Various subsurface geological strata.
Formation Damage: Damage to the productivity 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 lonization Detection.
GC/MS: Gas Chromatography with Mass Spectroscopy Detection.
gph: 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 (IO): 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.
[ig/1: Micrograms per liter.
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mg/1: Milligrams per liter.
MDL: Minimum detection limit
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.
NODA: Notice of Data Availability (65 FR 21559)
Non-Aqueous Drilling Fluid: A drilling fluid in which the continuous phase is a water-immiscible fluid
such as an oleaginous material (e.g., mineral oil, enhanced mineral oil, paraffmic 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 Defense 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.
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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
produced 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 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 commer-
cial disposal operation. The primary focus is on treatment 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.
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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.
ROC: Retention (of drilling fluids) on cuttings.
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.
SO2: 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.
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.
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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
r r
^s Me.
VOC: Volatile organic carbon
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 jobs are deepening, plugging back, pulling and
resetting liners, and squeeze cementing.
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APPENDIX VII-1
SBF/OBF Model Well Drilling Waste Volumes
A-l
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WORKSHEET No. 22:
Shallow Water Development Model Well Data: Discharged Cuttings Compostion Calculations
BPT 10.20% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestreams from Prim. & Sec. Shakers & FRU Ibs bbl
Total Cuttings Waste Discharged = 656,659 916.8
SBF Basefluid Discharged = 66,979 239.2
SBF Water Discharged = 28,502 81.3
SBF Barite Discharged = 47,028 31.2
Dry Drill Cuttings Discharged = 514,150 565.0
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 142,509 351.8
Formation Oil (discharged with cuttings) = 207 0.7
Whole SBF + Formation Oil = 142,716 352.5
SBF Basefluid Discharged + Formation Oil = 67,186 239.9
BAT/NSPS Option 1 4.03% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestreams From Cuttings Dryer and FRU Ibs bbl
Total Cuttings Waste Discharged = 562,370 684.0
SBF Basefluid Discharged = 22,664 80.9
SBF Water Discharged = 9,644 27.5
SBF Barite Discharged = 15,913 10.6
Dry Drill Cuttings Discharged = 514,150 565.0
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 48,220 119.0
Formation Oil (discharged with cuttings) = 70 0.2
Whole SBF + Formation Oil = 48,290 119.3
SBF Basefluid Discharged + Formation Oil = 22,734 81.2
BAT/NSPS Option 2 3.82% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestream from Cuttings Dryer (Discharged) Ibs bbl
Total Cuttings Waste Discharged = 545,499 660.2
SBF Basefluid Discharged = 20,838 74.4
SBF Water Discharged = 8,867 25.3
SBF Barite Discharged = 14,631 9.7
Dry Drill Cuttings Discharged = 501,163 550.7
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 44,336 109.4
Formation Oil (discharged with cuttings) = 64 0.2
Whole SBF + Formation Oil = 44,401 109.7
SBF Basefluid Discharged + Formation Oil = 20,902 74.6
Wastestream from FRU (Not Discharged) Ibs bbls
Total Cuttings Waste Not Discharged = 16,871 23.8
SBF Basefluid Not Discharged = 1,805 6.4
SBF Water Not Discharged = 768 2.2
SBF Barite Not Discharged = 1,267 0.8
Dry Drill Cuttings Not Discharged = 13,030 14.3
Adding formation oil to whole SBF (not discharged with cuttings):
Ibs bbls
Whole SBF (not discharged with cuttings) = 3,841 9.5
Formation Oil (not discharged with cuttings) = 6 0.02
Whole SBF + Formation Oil (not discharged) = 3,846 9.50
SBF Basefluid Discharged + Formation Oil (not discharged) = 1,811 6.5
A-2
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WORKSHEET No. 23:
Shallow Water Exploratory Model Well Data: Discharged Cuttings Compostion Calculations
BPT
10.20% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestreams from Prim. & Sec. Shakers & FRU Ibs bbl
Total Cuttings Waste Discharged = 1,376,078 1,921.1
SBF Basefluid Discharged = 140,360 501.3
SBF Water Discharged = 59,728 170.4
SBF Barite Discharged = 98,551 65.4
Dry Drill Cuttings Discharged = 1,077,440 1184.0
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 298,638 737.1
Formation Oil (discharged with cuttings) = 433 1.5
Whole SBF + Formation Oil = 299,072 738.6
SBF Basefluid Discharged + Formation Oil = 140,793 502.8
BAT/NSPS Option 1
4.03% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestreams From Cuttings Dryer and FRU Ibs bbl
Total Cuttings Waste Discharged = 1,178,489 1,433.4
SBF Basefluid Discharged = 47,493 169.6
SBF Water Discharged = 20,210 57.7
SBF Barite Discharged = 33,346 22.1
Dry Drill Cuttings Discharged = 1,077,440 1184.0
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 101,049 249.4
Formation Oil (discharged with cuttings) = 147 0.5
Whole SBF + Formation Oil = 101,196 249.9
SBF Basefluid Discharged + Formation Oil = 47,640 170.1
BAT/NSPS Option 2
3.82% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestream from Cuttings Dryer (Discharged) Ibs bbl
Total Cuttings Waste Discharged = 1,143,135 1,383.4
SBF Basefluid Discharged = 43,668 156.0
SBF Water Discharged = 18,582 53.0
SBF Barite Discharged = 30,660 20.4
Dry Drill Cuttings Discharged = 1,050,224 1154.1
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 92,910 229.3
Formation Oil (discharged with cuttings) = 135 0.5
Whole SBF + Formation Oil = 93,045 229.8
SBF Basefluid Discharged + Formation Oil = 43,803 156.4
Wastestream from FRU (Not Discharged) Ibs bbls
Total Cuttings Waste Not Discharged = 35,355 49.9
SBF Basefluid Not Discharged = 3,783 13.5
SBF Water Not Discharged = 1,610 4.6
SBF Barite Not Discharged = 2,656 1.8
Dry Drill Cuttings Not Discharged = 27,306 30.0
Adding formation oil to whole SBF (not discharged with cuttings):
Ibs bbls
Whole SBF (not discharged with cuttings) = 8,049 19.9
Formation Oil (not discharged with cuttings) = 12 0.04
Whole SBF + Formation Oil (not discharged) = 8,061 19.91
SBF Basefluid Discharged + Formation Oil (not discharged) = 3,795 13.6
A-3
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WORKSHEET No. 24:
Deep Water Development Model Well Data: Discharged Cuttings Compostion Calculations
BPT 10.20% Overall Cuttings Retention
Wastestreams from Prim. & Sec. Shakers & FRU
Total Cuttings Waste Discharged =
SBF Basefluid Discharged =
SBF Water Discharged =
SBF Barite Discharged =
Dry Drill Cuttings Discharged =
Adding formation oil to whole SBF (discharged with cuttings):
Whole SBF (discharged with cuttings) =
Formation Oil (discharged with cuttings) =
Whole SBF + Formation Oil =
SBF Basefluid Discharged + Formation Oil =
BAT/NSPS Option 1 4.03% Overall Cuttings Retention
Wastestreams From Cuttings Dryer and FRU
Total Cuttings Waste Discharged =
SBF Basefluid Discharged =
SBF Water Discharged =
SBF Barite Discharged =
Dry Drill Cuttings Discharged =
Adding formation oil to whole SBF (discharged with cuttings):
Whole SBF (discharged with cuttings) =
Formation Oil (discharged with cuttings) =
Whole SBF + Formation Oil =
SBF Basefluid Discharged + Formation Oil =
BAT/NSPS Option 2 3.82% Overall Cuttings Retention
Wastestream from Cuttings Dryer (Discharged)
Total Cuttings Waste Discharged =
SBF Basefluid Discharged =
SBF Water Discharged =
SBF Barite Discharged =
Dry Drill Cuttings Discharged =
Adding formation oil to whole SBF (discharged with cuttings):
Whole SBF (discharged with cuttings) =
Formation Oil (discharged with cuttings) =
Whole SBF + Formation Oil =
SBF Basefluid Discharged + Formation Oil =
Wastestream from FRU (Not Discharged)
Total Cuttings Waste Not Discharged =
SBF Basefluid Not Discharged =
SBF Water Not Discharged =
SBF Barite Not Discharged =
Dry Drill Cuttings Not Discharged =
Number of Discharged Cuttings Waste
Ibs bbl
993,705 1 ,387.3
101,358 362.0
43,131 123.1
71,166 47.3
778,050 855.0
Ibs bbls
215,655 532.3
313 1.1
215,968 533.4
101,671 363.1
Number of Discharged Cuttings Waste
Ibs bbl
851,020 1,035.1
34,296 122.5
14,594 41.6
24,080 16.0
778,050 855.0
Ibs bbls
72,970 180.1
106 0.4
73,076 180.5
34,402 122.8
Number of Discharged Cuttings Waste
Ibs bbl
825,490 999.0
31,534 112.6
13,419 38.3
22,141 14.7
758,397 833.4
Ibs bbls
67,093 165.6
97 0.3
67,190 165.9
31,631 113.0
Ibs bbls
25,531 36.0
2,732 9.8
1,162 3.3
1,918 1.3
19,718 21.7
Adding formation oil to whole SBF (not discharged with cuttings):
Whole SBF (not discharged with cuttings) =
Formation Oil (not discharged with cuttings) =
Whole SBF + Formation Oil (not discharged) =
SBF Basefluid Discharged + Formation Oil (not discharged) =
Ibs bbls
5,812 14.3
8 0.03
5,821 14.38
2,740 9.8
A-4
-------
WORKSHEET No. 25:
Deep Water Exploratory Model Well Data: Discharged Cuttings Compostion Calculations
BPT 10.20% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestreams from Prim. & Sec. Shakers & FRU Ibs bbl
Total Cuttings Waste Discharged = 2,209,396 3,084.5
SBF Basefluid Discharged = 225,358 804.9
SBF Water Discharged = 95,897 273.6
SBF Barite Discharged = 158,230 105.1
Dry Drill Cuttings Discharged = 1,729,910 1901.0
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 479,486 1183.5
Formation Oil (discharged with cuttings) = 696 2.4
Whole SBF + Formation Oil = 480,182 1185.9
SBF Basefluid Discharged + Formation Oil = 226,054 807.2
BAT/NSPS Option 1 4.03% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestreams From Cuttings Dryer and FRU Ibs bbl
Total Cuttings Waste Discharged = 1,892,152 2,301.5
SBF Basefluid Discharged = 76,254 272.3
SBF Water Discharged = 32,448 92.6
SBF Barite Discharged = 53,540 35.6
Dry Drill Cuttings Discharged = 1,729,910 1901.0
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 162,242 400.5
Formation Oil (discharged with cuttings) = 235 0.8
Whole SBF + Formation Oil = 162,477 401.3
SBF Basefluid Discharged + Formation Oil = 76,489 273.1
BAT/NSPS Option 2 3.82% Overall Cuttings Retention Number of Discharged Cuttings Waste
Wastestream from Cuttings Dryer (Discharged) Ibs bbl
Total Cuttings Waste Discharged = 1,835,387 2,221.2
SBF Basefluid Discharged = 70,112 250.4
SBF Water Discharged = 29,835 85.1
SBF Barite Discharged = 49,227 32.7
Dry Drill Cuttings Discharged = 1,686,213 1853.0
Adding formation oil to whole SBF (discharged with cuttings):
Ibs bbls
Whole SBF (discharged with cuttings) = 149,174 368.2
Formation Oil (discharged with cuttings) = 217 0.7
Whole SBF + Formation Oil = 149,391 368.9
SBF Basefluid Discharged + Formation Oil = 70,328 251.1
Wastestream from FRU (Not Discharged) Ibs bbls
Total Cuttings Waste Not Discharged = 56,765 80.1
SBF Basefluid Not Discharged = 6,074 21.7
SBF Water Not Discharged = 2,585 7.4
SBF Barite Not Discharged = 4,265 2.8
Dry Drill Cuttings Not Discharged = 43,842 48.2
Adding formation oil to whole SBF (not discharged with cuttings):
Ibs bbls
Whole SBF (not discharged with cuttings) = 12,923 31.9
Formation Oil (not discharged with cuttings) = 19 0.06
Whole SBF + Formation Oil (not discharged) = 12,942 31.96
SBF Basefluid Discharged + Formation Oil (not discharged) = 6,093 21.8
A-5
-------
WORKSHEET No. 26:
Summary Model Well Volume Data
Waste Component
BPT
(10.20% Cuttings Retention)
SBF Basefluld Discharged
SBF Water Discharged
SBF Barite Discharged
Dry Drill Cuttings Discharged
Dry Drill Cut + SBF Discharged
SBF Discharged
Formation Oil Discharged
Total Discharge - Water *
BAT/NSPS Option 1
(4.03% Cuttings Retention)
SBF Basefluid Discharged
SBF Water Discharged
SBF Barite Discharged
Dry Drill Cuttings Discharged
Dry Drill + SBF Discharged
SBF Discharged
Formation Oil Discharged
Total Discharge - Water *
Shallow Water (1, 000 ft)
Development
bbls
IDS
239.2
81.3
31.2
565.0
916.8
351.8
0.7
836
66,979
28,502
47,028
514, 150
656,659
142,509
207
628,364
80.9
27.5
10.6
565.0
684.0
119.0
0.2
657
22,664
9,644
15,913
514, 150
562,370
48,220
70
552, 796
Exploratory
bbls
IDS
501.3
170.4
65.4
1184.0
1921.1
737.1
1.5
1,752
140,360
59, 728
98,551
1,077,440
1,376,078
298,638
433
1,316,784
169.6
57.7
22.1
1184.0
1433.4
249.4
0.5
1,376
47,493
20,210
33,346
1,077,440
1,178,489
101,049
147
1,158,426
Deep Water (>1,000 ft)
Development
bbls
Ibs
362.0
123.1
47.3
855.0
1387.3
532.3
1.1
1265.3
101,358
43, 131
71,166
778,050
993, 705
215,655
313
950,887
122.5
41.6
16.0
855.0
1035. 1
180.1
0.4
993.8
34,296
14,594
24,080
778,050
851,020
72,970
106
836,532
Exploratory
bbls
Ibs
804.9
273.6
105.1
1901.0
3084.5
1183.5
2.4
2813.3
225,358
95,897
158,230
1,729,910
2,209,396
479,486
696
2,114,195
272.3
92.6
35.6
1901.0
2301.5
400.5
0.8
2209.7
76,254
32,448
53,540
1,729,910
1,892,152
162,242
235
1,859,939
* Used in "Regional Summary" and "NSPS Regional Summary" Worksheets
Waste Component
BAT/NSPS Option 2
(3.82% Cuttings Retention)
Discharge Wastes
SBF Basefluid Discharged
SBF Water Discharged
SBF Barite Discharged
Dry Drill Cuttings Discharged
Dry Drill + SBF Discharged
SBF Discharged
Formation Oil Discharged
Total Discharge - Water *
Zero Discharge Wastes
SBF Basefluid Not Discharged
SBF Water Not Discharged
SBF Barite Not Discharged
Dry Drill Cuttings Not Disch.
Dry Drill + SBF Not Discharged
SBF Not Discharged
Formation Oil Not Discharged
Shallow Water (1,000 ft)
Development
bbls
Ibs
74.4
25.3
9.7
550.7
660.2
109.4
0.2
635
20,838
8,867
14,631
501, 163
545,499
44,336
64
536,696
6.4
2.2
0.8
14.3
23.8
9.5
0.0
1,805
768
1,267
13,030
16,871
3,841
6
Exploratory
bbls
Ibs
156.0
53.0
20.4
1154.1
1383.4
229.3
0.5
1,331
43,668
18,582
30,660
1,050,224
1, 143, 135
92,910
135
1,124,687
13.5
4.6
1.8
30.0
49.9
19.9
0.0
3,783
1,610
2,656
27,306
35,355
8,049
12
Deep Water (>1,000 ft)
Development
bbls
Ibs
112.6
38.3
14.7
833.4
999.0
165.6
0.3
961.1
31,534
13,419
22, 141
758,397
825,490
67,093
97
812,169
9.8
3.3
1.3
21.7
36.0
14.3
0.0
2,732
1,162
1,918
19,718
25,531
5,812
8
Exploratory
bbls
Ibs
250.4
85.1
32.7
1853.0
2221.2
368.2
0.7
2136.8
70,112
29,835
49,227
1,686,213
1,835,387
149,174
217
1,805,769
21.7
7.4
2.8
48.2
80.1
31.9
0.1
6,074
2,585
4,265
43,842
56, 765
12,923
19
* Used in "Regional Summary" and "NSPS Regional Summary" Worksheets
Total Discharge - Water *
Baseline
BAT 1
BAT 2
BAT 3
SWD
628,364
552, 796
536,696
628,364
SWE
1,316,784
1,158,426
1,124,687
1,316,784
DWD
950,887
836,532
812, 169
950,887
OWE
2,114,195
1,859,939
1,805,769
2,114,195
Summary Model Well Pollutant Data
Priority metals (from barite)
Non-conventionals (from barite)
Priority organics (from SBF+oil)
Non-conventionals (from SBF+oil)
Priority metals
Priority organics
Total Priority Pollutants
Non-conventionals
Total
%
0.0856%
0.00347%
0.0890%
99.82%
Ibs
24.7
28,805
1.002
29.6
24.7
1.002
25.7
28,835
28,886
%
0.1793%
0.00000%
0.1793%
0.00%
Ibs
51.8
-
0.000
51.8
-
51.8
-
104
%
0.0000%
0.00000%
0.0000%
0.00%
Ibs
0.0
-
0.000
-
-
%
0.0000%
0.00000%
0.0000%
0.00%
Ibs
0.0
-
0.000
-
-
A-6
-------
APPENDIX VII-2
WBF Waste Volume and Characteristics
A-7
-------
WORKSHEET No. B:
ANALYSIS OF WBF PASS/FAIL PERMIT LIMITS (SHEEN; TOXICITY); FAILS HAULED TO ONSHORE DISPOSAL(a,b,c)
Gulf of Mexico
shallow
shallow, no lube
shallow, no lube, no spot
shallow, no lube, + spot
shallow, + lube
shallow, + lube, no spot
shallow, + lube, + spot
total % shallow wells
deep
deep, OBF (no discharge)
deep, WBF (discharge)
deep, no lube
deep, no lube, no spot
deep, no lube, + spot
deep, + lube
deep, + lube, no spot
deep, + lube, + spot
total % deep wells
California
shallow
shallow, no lube
shallow, no lube, no spot
shallow, no lube, + spot
shallow, + lube
shallow, + lube, no spot
shallow, + lube, + spot
total % shallow wells
deep
deep, OBF (no discharge)
deep, WBF (discharge)
Ideep, no lube
deep, no lube, no spot
deep, no lube, + spot
deep, + lube
deep, + lube, no spot
deep, + lube, + spot
total % deep wells
Alaska
shallow
shallow, no lube
shallow, no lube, no spot
shallow, no lube, + spot
shallow, + lube
shallow, + lube, no spot
shallow, + lube, + spot
total % shallow wells
deep
deep, OBF (no discharge)
deep, WBF (discharge)
deep, no lube
hdeep, no lube, no spot
deep, no lube, + spot
deep, + lube
deep, + lube, no spot
deep, + lube, + spot
total % deep wells
(44.88% * 78%
(44.88% *
(6. 12%* 78%
(6.12%*
(43. 12%* 78%
(43.12%*
(6. 12%* 78%
(6.12%*
(5 1.04%* 78%
(51.04%*
(6.96% * 78%
(6.96% *
(36.96% * 78%
(36.96% *
(3.93% * 78%
(3.93% *
(36.08% * 78%
(36.08% *
(4.92% * 78%
(4.92% *
(5 1.92%* 78%
(51.92%*
(7.08% * 78%
(7.08% *
0
(51% GOM wells) =
(51%* 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(51%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(49% GOM wells) =
(1 5% of deep wells) =
(85% of deep wells) =
(49% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(49%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(58% CA wells) =
(58% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(58%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(42% CA wells) =
(1 5% of deep wells) =
(85% of deep wells) =
(42% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(42%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(41 %AK wells) =
(41%* 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(41%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(59% AK wells) =
(1 5% of deep wells) =
(85% of deep wells) =
(59% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(59%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
'o Wells/region
Shallow/deep
% split
51.00%
49.00%
7.35%
41.65%
58.00%
42.00%
6.30%
35.70%
41.00%
59.00%
8.85%
50.15%
No lube
/lube
% split
44.88%
6.12%
36.65%
5.00%
41.65%
51.04%
6.96%
31.42%
4.28%
35.70%
36.08%
4.92%
44.13%
6.02%
50.15%
No spot
/spot
% split
35.01%
9.87%
4.77%
1.35%
28.59%
8.06%
3.90%
1.10%
41.65%
39.81%
11.23%
5.43%
1.53%
24.50%
6.91%
3.34%
0.94%
35.70%
28.14%
7.94%
3.84%
1.08%
34.42%
9.71%
4.69%
1.32%
50.15%
Proj'd Tox /
Sheen Limit
Failure Rate
1.0%
33.0%
33.0%
56.0%
100%
1.0%
33.0%
33.0%
56.0%
1.0%
33.0%
33.0%
56.0%
100%
1.0%
33.0%
33.0%
56.0%
1.0%
33.0%
33.0%
56.0%
100%
1.0%
33.0%
33.0%
56.0%
Proj'd %
Wells Fail
Permit Lim
0.350%
3.258%
1.575%
0.754%
5.940%
7.35%
0.286%
2.661%
1.286%
0.616%
12.20%
0.398%
3.706%
1.792%
0.857%
6.753%
6.30%
0.245%
2.281%
1.103%
0.528%
10.46%
0.281%
2.619%
1.266%
0.606%
4.773%
8.85%
0.344%
3.204%
1.549%
0.741%
14.69%
Proj'd %
Wells Pass
Permit Lim
34.66%
6.62%
3.20%
0.59%
45.06%
0.00%
28.30%
5.40%
2.61%
0.48%
36.80%
39.41%
7.52%
3.64%
0.67%
51.25%
0.00%
24.26%
4.63%
2.24%
0.41%
31.54%
27.86%
5.32%
2.57%
0.48%
36.23%
0.00%
34.08%
6.51%
3.15%
0.58%
44.31%
Sum lubes(l)
spot(s), or l+s
that Pass
10.41%
8.50%
11.83%
7.28%
8.37%
10.23%
(a) Percentage Distribution of Water-based Drilling Fluid Types, (no oil, +MO lube, +MO spot, or+MO lube & spot)
(b) Cells shaded in blue are data input from ODD: Table XI-10, p XI-17; other percentages shown are derived from these input values)
(c) The terms "shallow" and "deep" as used in the offshore effluent limitaiton guideline do NOT have the same meaning as the same terms as used in the synthetics effluent guideline;
these terms in the offshore rule refers to the relative target depth of the well, whereas in the synthetics rule they refer to the water depth in which operations occur.
A-8
-------
WORKSHEET No. C:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: WELL DEPTHS AND VOLUMES OF DISCHARGED CUTTINGS AND DRILLING FLUIDS
(from ODD: Table XI-2, p XI-4)
(from ODD: Table XI-2, p XI-4)
well depth, TD
cuttings discharged , bbl per well
drilling fluids (bbl) per well
COM |
10,559
1,475
6,938
CA |
Shallow Well
7,607
1,242
5,939
AK
10,633
1,480
6,963
COM
13,037
2,458
9,752
CA
Deep Well
10,082
1,437
6,777
AK
12,354
2,413
9,458
Current Well Counts, SBF Effluent Limitations Guideline (see "Well Count Input Sheet," this file)
Est'd % WBF > SBF
Baseline 0%
BAT 1 6%
BAT 2 6%
EXISTING SOURCES, WBF Wells
COM CA AK Subtotal
857.0
803.0
803.0
5
5
5
4
4
4
866
812
812
NEW SOURCES, WBF Wells
COM CA AK Subtotal
38
35
35
0
0
0
0
0
0
38
35
35
Total
904
847
847
WBF/Water Phase Composition/Contribution to Toxic/Non-conventional Pollutant Loadings, Offshore Record
(from ODD: Table XI-3, p XI-5 and Table XI-6, p XI-9)
1 Drilling
| Fuids
barite
1 kg/bbl tox+non-Conv
I Ib/bbl tox+non-Conv
[mineral oil
ITSS
Composition,
Ibs/bbl
98
9
153
Total nonC+toxics+Ba
384,792 mg/kg dry
17.1 kg/bbl
37.7 Ib/bbl
2.9 Ib/bbl
153.0 Ib/bbl
Cuttings
Density
Adherent mud
Mud TSS
Ad'nt mud TSS
(fromODD, p XI-6)
543 Ibs/bbl
Ib/bbl
7.7 Ib/bbl
Total TSS per bbl cuttings
551 Ib/bbl
WBF/ Mineral Oil Phase Contribution to Toxic/Non-conventional Pollutant Loadings
(from ODD: Table XI-5, p XI-7)
MO (9 Ib/bbl)
30.51 mg nonconventionals/ml MO:
0.05 mg toxics/ml MO,
kg toxic+Non-conventional Pollutants per bbl MO
Ibs toxic + Non-conventional Pollutants per bbl MO
0.14700 kg/bbl
0.00024 kg/bbl
0.147 kg/bbl
0.324 Ib/bbl
>n-conventional = 99.8%
toxics = 0.2%
461
11.0
2.1
23.1
543
566
b/bbl mud
Ib/gal mud
gal of 5% mud
wt of 5% mud
Ib/bbl cuttings
Ib/bbl wet cuttings
A-9
-------
APPENDIX VIII-1
Derivation of Supply Boat Transport Days
A-10
-------
SUPPLY BOAT FREQUENCY WORKSHEET
(Zero discharge)
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
(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
(Total roundtrip - regular port to rig roundtrip = 277 - 200 = 77 mi.)
9. Supply boat maneuvering time at rig = 1 hr 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
Deep Water Development Model Wells
Waste volume generated = 1,387.3 bbl
Number of boxes of waste generated = 1387/25 = 56 boxes
Number of days to drill model well = 7.9 days
Number of supply boat trips = 1 dedicated trip
Number of days for supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (186.9 hrs loading) + (24 hr
demurrage) = 237.59 hrs = 9.90 days
Number of truck roundtrips = 1387/119 =12 trips
Total truck miles = 12 * 20 = 240 mi.
Deep Water Exploratory Model Wells
Waste volume generated = 3,084.5 bbl
Number of boxes of waste generated = 3085/25 = 124 boxes
Number of days to drill model well = 17.5 days
Number of supply boat trips = 2 dedicated 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) + (209.1 hrs loading) + (24 hr
demurrage) = 259.79 hrs = 10.82 days
Number of days for regularly scheduled supply boat:
A-ll
-------
(77 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (4 hrs loading) + (24 hr
demurrage) = 37.30 hrs = 1.55 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) + (199.39 hrs loading) + (24 hr
demurrage) = 250.08 hrs = 10.42 days
Supply boat days = 21.24 days for dedicated + 1.55 days for regularly scheduled = 22.79 days
Number of truck roundtrips = 3084.5/119 = 26 trips
Total truck miles = 26 * 20 = 520 mi.
Shallow Water Development Model Wells
Waste volume generated = 916.8 bbl
Number of boxes of waste generated = 917/25 = 37 boxes
Number of days to drill model well = 5.2 days
Number of supply boat trips = 1 dedicated trip
Number of days for supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (124.8 hrs loading) + (24 hr
demurrage) = 175.49 hrs = 7.31 days
Number of truck roundtrips = 917/119 = 8 trips
Total truck miles = 8 * 20 = 160 mi.
Shallow Water Exploratory Model Wells
Waste volume generated = 1,921.1 bbl
Number of boxes of waste generated = 1921/25 = 77 boxes
Number of days to drill model well = 10.9 days
Number of supply boat trips = 1 dedicated trip; 1 regularly scheduled trip
Number of days for supply boat:
(277 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (252.43 hrs loading) + (24 hr
demurrage) = 303.12 hrs = 12.63 days
Number of days for regularly scheduled supply boat:
(77 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (4hr loading) + (24 hr demurrage)
= 37.30 hrs = 1.55 days
Supply boat days = 12.63 days for dedicated + 1.55 days for regularly scheduled = 14.18 days
Number of truck roundtrips = 1921/119= 17 trips
Total truck miles = 17 * 20 = 340 mi.
OFFSHORE CALIFORNIA
Assumptions:
1. Cuttings box capacity = 25 bbl
A-12
-------
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 = 1 hr 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
Deep Water Development Model Wells
Waste volume generated = 1,387.3 bbl
Number of boxes of waste generated = 1387.3/25 = 56 boxes
Number of days to drill model well = 7.9 days
Number of supply boat trips = 1 dedicated trip
Number of days for supply boat:
(200 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (186.9hrs loading) + (24 hr
demurrage) = 230.9 hrs = 9.62 days
Number of truck roundtrips = 1387.3/50 = 28 trips
Total truck miles = 28 * 300 = 8400 mi.
Shallow Water Development Model Wells
Waste volume generated = 916.8 bbl
Number of boxes of waste generated = 917/25 = 37 boxes
Number of days to drill model well = 5.2 days
Number of supply boat trips = 1 dedicated trip
Number of days for supply boat:
(200 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (122hrs loading) + (24 hr
demurrage) = 166.1 hrs = 6.92 days
Number of truck roundtrips = 917/50 = 19 trips
Total truck miles = 19 * 300 = 5700 mi.
A-13
-------
SUPPLY BOAT FREQUENCY WORKSHEET
(Discharge cuttings with 3.82% SBF retention; zero discharge of fines)
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. Incremental mileage for regularly scheduled supply boat = 77 miles
(Total roundtrip - regular port to rig roundtrip = 277 - 200 = 77 mi.)
8. Supply boat maneuvering time at rig = 1 hr per trip
9. Additional boat idling at rig due to potential delays = 1.6 hrs per trip
10. Supply boat in-port unloading time and demurrage = 24 hrs per trip
11. Truck capacity =119 bbls
12. Roundtrip trucking distance from port to disposal facility = 50 miles
Deep Water Development Model Wells
Waste volume generated = 23.8 bbl
Number of boxes of waste generated = 23.8/25 = 1 box
Number of days to drill model well = 7.9 days
Number of supply boat trips = 1 regularly scheduled trip
Number of days for supply boat:
(77 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (0.1 hrs loading) + (24 hr
demurrage) = 33.30 hrs = 1.40 days
Number of truck roundtrips = 23.8/119 = 1 trip
Total truck miles = 1 * 50 = 50 mi.
Deep Water Exploratory Model Wells
Waste volume generated = 49.9 bbl
Number of boxes of waste generated = 49.9/25 = 2 boxes
Number of days to drill model well = 17.5 days
Number of supply boat trips = 1 regularly scheduled trip
Number of days for regularly scheduled supply boat:
(77 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (0.2hr loading) + (24 hr
demurrage) = 33.50 hrs = 1.40 days
Number of truck roundtrips = 49.9/119 = 1 trip
Total truck miles = 1 * 50 = 50 mi.
A-14
-------
Shallow Water Development Model Wells
Waste volume generated = 36 bbl
Number of boxes of waste generated = 36/25 = 2 boxes
Number of days to drill model well = 5.2 days
Number of supply boat trips = 1 regularly scheduled trip
Number of days for supply boat:
(77 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (0.2hr loading) + (24 hr
demurrage) = 33.50 hrs = 1.40 days
Number of truck roundtrips = 36/119 = 1 trip
Total truck miles = 1 * 50 = 50 mi.
Shallow Water Exploratory Model Wells
Waste volume generated = 80.1 bbl
Number of boxes of waste generated = 80.1/25 = 4 boxes
Number of days to drill model well = 10.9 days
Number of supply boat trips = 1 regularly scheduled trip
Number of days for regularly scheduled supply boat:
(77 mi/11.5 mi per hr) + (1 hr maneuvering) + (1.6 hrs add. idling at rig) + (0.4hr loading) + (24 hr
demurrage) = 33.70 hrs = 1.40 days
Number of truck roundtrips = 80.1/119 = 1 trip
Total truck miles = 1 * 50 = 50 mi.
A-15
-------
APPENDIX VIII-2a
Cost (Savings) Analysis Worksheets
Chapter VIII states:
โข Worksheets 20 through 22 are WBF Zero Discharge baseline costs for the Gulf of Mexico, offshore California, and
Cook Inlet, Alaska, respectively, including costs for transport and land disposal and for onsite injection.
Worksheets 20A and 22A are WBF Zero Discharge BAT/NSPS Option 1 and BAT/NSPS Option 2 costs for the
Gulf of Mexico (costs for transport and land disposal and for onsite injection) and for Cook Inlet, Alaska (onsite
injection), respectively.
In this Appendix, the contents of these worksheets are as follows:
โข Worksheets 20 and 21 are WBF Zero Discharge baseline costs for the Gulf of Mexico and offshore California,
respectively, including costs for transport and land disposal; Worksheet 22 has been deleted because land disposal is
not current waste management practice in Cook Inlet, Alaska.
Worksheets 20A through 22A are WBF Zero Discharge BAT/NSPS Option 1 and BAT/NSPS Option 2 costs for
the Gulf of Mexico, offshore California, and Cook Inlet, Alaska for onsite injection, respectively.
A-16
-------
WORKSHEET A: SBF Cost Model Input Data
MODEL WELL WASTE DATA
Waste
DWD
OWE
SWD
SWE
BPT (Retention = 9.42%; Volumes (bbl); Worksheets 1-3
Wet cuttings
DF Lost w/ Cuttings
1,387
532
3,085
1,184
917
352
1,921
737
BAT 1 (Retention =3.68%; Volumes (bbl); Worksheets 7-9
Wet cuttings
DF Lost w/ Cuttings
1,035
180
2,301
400
684
119
1,433
249
BAT 2 (Retention =3.48%; Volumes (bbl); Worksheets 7-9
Part A: 97% (vol) of Waste is Discharged Cuttings from Cuttings Dryer
Wet cuttings
DF Lost w/ Cuttings
Part B: 3% (vol) of Waste is Fines Retained for Zero Discharge
Wet cuttings
DF Lost w/ Fines
999
166
36
14
2,221
368
80
32
660
109
24
9
1,383
229
50
20
BAT-3 (Zero Discharge) Volumes (bbl): Worksheets 10-12 I
Wet cuttings
DF Lost w/ Cuttings
1,387
532
3,085
1,184
917
352
1,921
737
Length of SBF Drilling Program , in Days
All wastes
8
18 | 5
SBF Retention on Cuttings, % Wet Weight Cuttings
BPT (Baseline)
BAT/NSPS Option 1 (Two Discharges):
BAT/NSPS Option 2 (One Discharge):
10.20%
4.03%
3.82%
10.20%
4.03%
3.82%
10.20%
4.03%
3.82%
11
10.20%
4.03%
3.82%
MISCELLANEOUS COST DATA
Geographic multiplier, CA::GOM = 1.6
Geographic multiplier, AK::GOM = 2.0
ENRCCI 1999S/1 995$ Ratio = 1.108
SUMMARY OF SUPPLY BOAT INFORMATION
GULF OF MEXICO OPERATIONS
No. Supply Boat Trips
Dedicated trips
Regularly-scheduled trip[s]
Total Trips
No. days, supply boats hauling waste ashore
CALIFORNIA OPERATIONS
No. Supply Boat Trips
Dedicated trips
Regularly-scheduled trip[s]
Total Trips
No. days, supply boats hauling waste ashore
(N. Orentas Memo, 2/23/00)
BPT (CA & AK) and Zero Discharge (GOM)
DWD
1
0
1
9.90
1
0
1
9.62
LASKA (COOK INLET) OPERATIONS (No longer applicable)
No. Supply Boat Trips
Dedicated trips
Regularly-scheduled trip[s]
Total Trips
No. days, supply boats hauling waste ashore
NA
NA
NA
NA
OWE
2
1
3
22.79
NA
NA
NA
NA
NA
NA
NA
NA
SWD
1
0
1
7.31
1
0
1
6.92
NA
NA
NA
NA
SWE
1
1
2
14.18
NA
NA
NA
NA
NA
NA
NA
NA
BAT Option 2B (ZD Fines)
DWD
0
1
1
9.90
0
1
1
9.62
NA
NA
NA
NA
OWE SWD SWE
000
1 1 1
1 1 1
22.79 7.31 14.18
000
NA 1 NA
0 1 0
NA 6.92 NA
NA NA NA
NA NA NA
NA NA NA
NA NA NA
A-17
-------
BASELINE GULF OF MEXICO OPERATIONS
UNIT COSTS
Cost per bbl SBF $221.00
Cost per bbl OBF $79.00
Cost per SBF Toxicity Test $575
Cost per day, supply boat $8,500
Cost per day, onsite injection system $4,280
Container Rental
Boxes per well
(Days to fill & haul
Zero Discharge GOM Disposal Inputs
DWD
$25
59
9.90
23.508
OWE SWD SW
$25 $25
131 39
22.79 7.31 1
E
$25
82
4.18
23.550 23.513 23.427
POLLUTION CONTROL SELECTION RATIOS
Wells currently using OBF: haul vs inject
Wells currently using OBF: convert to SBF vs remain OBF ยป>
NA
NA
NA
NA
NA NA
NA NA
BASELINE CALIFORNIA OPERATIONS
UNIT COSTS
Disposal Cost $12.53
Handling Cost $5.89
Container Rental $40.00
Supply Boat Cost
Days to fill and haul
$8,500
9.62
Trucking Cost $355
OBF Lost Drilling Fluid (w/ Cuttings) Costs $126
per bbl
per bbl
per box per day
per day
per DWD
per 2- box truck
per bbl
Vendor guote
$35.00 per ton and 91 7 Ibs waste cuttings per bbl
Basis: apply F125GOM handling costs = 47% of total GOM disposal costs
GOM vendor guote ($25 per day) times geographic area multiplier (CA:GOM = 1.6)
58
131
per DWD 39 per SV
per OWE 82 per SV
6.92 days per SWD
VD |
VE|
Truck rate ($65/hr x 300 mi r.t. @55mph) per 2-box truck load
$79 per bbl; industry guote
BASELINE ALASKA (COOK INLET) OPERATIONS
UNIT COSTS (No longer applicable)
Cuttings Box Purchase Cost
Capacity of Disposal Boxes
Cost of Disposal Boxes
Supply Boat Cost
Days rental
Trucking Cost
No. boxes per 22-ton truckload
Drilling Fluid Cost (lost with cuttings)
SWD
$135
8
540
$8,500
NA
$1,994
8
$158
Operator guotes of $125/box in 1995; ENR CCI ratio of 1 998$/1 995$ 1.108
bbl per box
Vendor guote of $500/box in 1995; ENR CCI rat o of 1 998$/1 995$ = 1.108
per day, vendors
Vendor guote, $1,800 per 22-ton (8-box) truckload in 1995* ENR CCI 1.108
( ~8 boxes * 8 bbls/box * 704 Ibs / bbl = 45,056 Ibs)
per bbl; from GOM vendor; Geographic Multiplier from Ofshore DD = 2.0
A-18
-------
BAT{NSPS} OPTION 1, GULF OF MEXICO OPERATIONS
UNIT COSTS
DWD
OWE
SWD
BAT Solids Control Equipment $2,400 per day, including all equipment, abor, and materials;
Drilling days (DWD; OWE; SWD; SWE) 0.4|
7.9| 17.5| 5.2
SWE
10.9
Cuttinqs dryer+FRU that reduces base fluid retention from 10.2% to 4.03% proportion drillinq t me to total operational time (I.e., SCE rental tin
Installation and Downtime Costs: Installation $32,500 Installation is avg. of range;
: Downtime $24,000 downtime = $6,000/hour (avq.) x
Drillinq Fluid Costs (lost with cuttinqs) $221 per bbl SBF; cost from vendor
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test $50 Cost from vendor
Retention of Base Fluids by Retort @ $50/test $50 Retort measured o
Footage Drilled with SBF (DWD; OWE; SWD; SWE)
ice per discha
6,500
โข hrs; cost
ge per 50
8,500
3 from Par
3 ft drilled;
7,500
-------
BAT{NSPS} OPTION 2, GULF OF MEXICO OPERATIONS
UNIT COSTS
BAT Solids Control Equipment
Drilling days (DWD; SWD;)
Cuttings dryer + FRU that reduces base fluid retention from 0.00% to 10.20%
$2,400 per day, including all equipment, labor, and materials;
| 7.9| 17.5| 5.2
0.4 proportion drilling time to total operational time (I.e., SCE rental time )
10.9| data from industry
Installation and Downtime Costs: Installation
: Downtime
$32,500
$24,000
Installation is avg. of range;
downtime = $6,OOP/hour (avq.) x 4 hrs; costs from Parker 1999
Zero Discharge of Fines via Hauling:
Disposal Costs @ $10.13/bbl
Handling Cost @ $4.75/bbl
Container Rental @ $25/box/day
Number boxes
Number days to fil and haul
10.13
4.75
$25
See Worksheet 10
See Worksheet 10
Orentas 2000
2 4
9.90 22.79
2 3
7.31 14.18
Drilling Fluid Costs (lost with cuttings)
$221 perbblSBF; cost from vendor
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
Footage Drilled with SBF (DWD; OWE; SWD; SWE)
$50 Cost from vendor
$50 Retort measured once per discharge per 500 ft drilled; costs from vendor
| 6,500 | 8,500 | 7,500 I 10,000 I
BAT{NSPS} OPTION 2, CALIFORNIA OPERATIONS
BAT Solids Control Equipment
Drilling days (DWD; SWD)
Cuttings dryer + FRU that reduces base fluid retention from 0.00% to 10.20%
DWD
$3,840 Includes equipment, labor, & materials; apply GOM costs *CA multiplier (1.6, from offshore DD)
7.9J | 5.2J data from industry
0.4 proportion drilling time to total operational time (I.e., SCE rental time )
Installation and Downtime Costs: Installation
: Downtime
$52,000
$38,400
Installation is avg. of GOM cost range; plus geographic multiplier
downtime = $6,OOP/hour (avg. GOM cost: Parker, 1999 x 4 hrs; plus geographic multiplier
Zero Discharge of Fines via Hauling:
Disposal Cost @ $16.05/bbl 12.41
Handling Cost @ $7.54/bbl 5.83
Container Rental @ $40/box/day $40
I Trucking Cost @ $354/50-bbl truckload $354
seew/s10 Vendor quote: $35.00 per ton and 704 Ibs waste cuttings per bbl
see w/s 10
Orentas 2000 GOM vendor quote ($25 per day) times geographic area multiplier (CA:GOM = 1.(
per 50-bbl truck load Truck rate ($65/hr x 300 mi r.t. @55mph) per 2-box truck load
Number boxes (DWD; SWD)
Number days to fil and haul
Drilling Fluid Costs (lost with cuttinqs)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
Footage Drilled with SBF (DWD; SWD)
$354
$50
$50
3
9.62
2
6.92
perbblSBF; GOM cost plus qeoqraphic multiplier; cost from vendor
Cost from vendor
Retort measured o
ice per discha
6,500
ge per 50
3 ft drilled;
7,500
costs from vendor
BAT{NSPS} OPTION 2, ALASKA (COOK INLET) OPERATIONS
UNIT COSTS (No longer applicable)
BAT Solids Control Equipment
Drilling days ( SWD)
Cuttinqs dryer + FRU that reduces base fluid retention from 0.00% to 10.20%
Installation and Downtime Costs: Installation
: Downtime
$4,800
0.4
$65,000
$48,000
| SWD
Includes equipment, labor, & materials; app
proportion drillinq t me to total operational ti
y GOM costs *AK multiplier (2.0
5.2|
ne (I.e., SCE rental time )
from offshore DD)
Installation is avg. of GOM cost range; plus geographic multiplier
downtime = $6,000/hour (avg. GOM cost: Parker, 1999 x 4 hrs; plus geographic multiplier
Zero Discharge of Fines via Hauling:
Disposal Cost $540
8-bbl Cuttings Box Purchase Cost @ $135/box $135
Trucking Cost @ $1,944 per 8-box truckload $1,994
Number boxes 39
Number days NA
Drilling Fluid Costs (lost with cuttings)
$442 perbblSBF; GOM cost plus geographic multiplier; cost from vendor
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
Footage Drilled with SBF (SWD)
$50 Cost from vendor
$50 Retort measured once per discharge per 500 ft drilled; costs from vendor
I 7,500 |
A-20
-------
WORKSHEET B: Cost Analysis for OBF and SBF
X
1/x
Diesal
Oil
a
$70.00
0.0143
Mineral
Oil
b
$90.00
0.0111
c = a+b
0.0254
d = 1/c n
39.3701
2
n*D
$78.74
X
1/x
IO
a
$160.00
0.0063
VEstr
b
$250.00
0.0040
LowVisc
VEstr
c
$300.00
0.0033
d = a+b+c
0.0136
e = 1/d n
73.6196
3
n*D
$220.86
Cost of WB-drilling fluid:
$45.00 /bbl
A-21
-------
WORKS
857
201
67
5
0
2
4
0
2
38
20
2
0
0
0
0
0
0
803
264
40
5
0
2
4
1
1
35
24
1
0
0
0
0
0
0
MEET C: Well Count Projections, Baseline and all Options
BASELINE
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
12
16
0
0
0
0
0
0
0
OWE
36
48
0
0
0
0
0
0
0
SWD
511
86
42
3
0
1
3
0
1
SWE
298
51
25
2
0
1
1
0
1
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
11
15
0
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
SWD
27
5
2
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
Note: By definition "exploratory" wells are excluded from the "new sources" category
BAT OPT 1
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
11
17
0
0
0
0
0
0
0
OWE
34
49
0
0
0
0
0
0
0
SWD
479
124
25
3
0
1
3
1
0
SWE
279
74
15
2
0
1
1
0
1
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
10
16
0
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
SWD
25
8
1
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
1,125
7
6
1,138
60
0
0
60
1,107
7
6
1,120
60
0
0
Note: By definition "exploratory" wells are excluded from the "new sources" category 60
803
264
40
5
0
2
4
1
1
35
24
1
0
0
0
0
0
0
877
11
237
5
0
2
4
0
2
42
3
15
0
0
0
0
0
0
BAT OPT 2
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
11
17
0
0
0
0
0
0
0
OWE
34
49
0
0
0
0
0
0
0
SWD
479
124
25
3
0
1
3
1
0
SWE
279
74
15
2
0
1
1
0
1
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
10
16
0
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
SWD
25
8
1
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
Note: By definition "exploratory" wells are excluded from the "new sources" category
BAT OPT 3
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
17
3
8
0
0
0
0
0
0
OWE
51
8
25
0
0
0
0
0
0
SWD
511
0
128
3
0
1
3
0
1
SWE
298
0
76
2
0
1
1
0
1
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
DWD
15
3
8
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
SWD
27
0
7
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
1,107
7
6
1,120
60
0
0
60
877
1,125
7
6
1,138
60
0
0
Note: By definition "exploratory" wells are excluded from the "new sources" category 60
A-22
-------
Worksheet No. 1
Compliance Cost Estimates ($1999): Baseline Current Practice (BPT)
Existing Sources; Gulf of Mexico
Technologies: Discharge SBF cuttings via primary, secondary shakers & FRU; fractional SBF retention (wt:wt) determined as 10.2%
Zero discharge of OBF cuttings via haul & land-disposal or on-site grinding and injection
Model Well Types: Four types: Deep- and Shallow-water, Development and Exploratory
Per-Well Waste Volumes:
Deep-water Development:
Deep-water Exploratory:
Shallow-water Development:
Shallow-water Exploratory:
Cost Item
SBF & OBF Discharge Costs
Drilling Fluid Costs,
Wells Currently Using SBF
SBF: (SBF@$221/bbl)
OBF Cost/Well : Haul and Dispose
OBF: Well: Grind and Inject
Baseline Cost ($/well)
Unit Cost ($/bbl)
No. wells
No. Wells Discharge (OBF: haul)
No. wells (OBF: inject)
TOTAL ANNUAL ($)
BASELINE COM COST ($)
1 ,387 bbls waste SBF/OBF-cuttings ( 0.2% crude contamination)
532 bbls SBF/OBF lost with cuttings
3,085 bbls waste SBF/OBF-cuttings ( 0.2% crude contamination)
1 ,184 bbls SBF/OBF lost with cuttings
91 7 bbls waste SBF/OBF-cuttings ( 0.2% crude contamination)
352 bbls SBF/OBF lost with cuttings
1 ,921 bbls waste SBF/OBF-cuttings ( 0.2% crude contamination)
737 bbls SBF/OBF lost with cuttings
DWD
$117,572
$117,572
$85
16
16
$1,881,152
OWE
$261 ,664
$261 ,664
$85
48
48
SWD
$77,792
$77,792
$85
86
86
$6,690,112
SWE
$162,877
$162,877
$85
51
51
$8,306,727
Subtotal for SBF Wells: $29,437,863
SWD
$110,715
$83,448
$105,262
$115
42
34
8
$4,431,901
SWE
$236,406
$174,853
$224,096
$117
25
20
5
$5,602,395
Subtotal for OBF Wells: $10,034,296
TOTAL
$39,472,159
UNIT COSTS
SBF @ $221 $/bbl lost w/ cuttings
SedTox Monitoring Test $575 $/test, once per well
WBF Upper Bound (10.73%) Anal
WBF haul, $/well
WBF inject, $/well
No. WBF wells
% WBF fail sheen /tox (a)
No wells fail sheen/tox
No. haul
No. inject
No. discharge
$ haul
$ inject
Total $
ysis for Zero Discharge Wells (fail tox/sheen)
Deep-Water Using WBF
Development
$906,022
$543,102
12
10.73%
1
1
11
$906,022
$906,022
Exploratory
$2,724,495
$1,235,566
36
10.73%
4
4
32
$10,897,980
$10,897,980
Shallow-Water Using WBF
Development
$627,810
$387,454
511
10.73%
55
44
11
456
27,623,640
$4,261 ,994
$31 ,885,634
Exploratory
$1,429,659
$768,992
298
10.73%
32
26
6
266
37,171,134
$4,613,951
$41 ,785,085
$76,598,776
$8,875,945
$85,474,721
(a) Per ODD
A-23
-------
Worksheet No. 2
Compliance Cost Estimates (1999$): Baseline Current Practice (BPT)
Existing Sources; California (NOTE: Costs no longer applicable to SBF
reg analysis since no conversions to SBF are projected)
Technology: Zero-Discharge via Haul and Land-Dispose
Model Well Types: Deep- and Shallow-water Development Wells
Per-Well Waste Volumes:
Deep-water Devel:
Deep-water Explor:
Shallow-water Devel:
Shallow-water Explor.:
Cost Item
Disposal Cost ($12.53/bbl)
Handling Cost ($5.89/bbl)
Container Rental
($40/box/day * "x" boxes* 'V" days to fill & haul)
Supply Boat Cost ($8,500/day)
Trucking Cost ($354/truck load)
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl)
TOTAL OBF Cost / Model Well, Haul/Land Dispose
Unit Cost ($/bbl)
No. Wells
TOTAL CA OBF HAUL/LAND DISPOSAL COST ($)
UN IT COSTS
Disposal Cost
Handling Cost
Container Rental
Boxes per well
Days to fill & haul
Trucking Cost
Supply Boat Cost
Days to fill & haul
OBF Lost Drilling Fluid (w/ Cuttings) Costs
OBF Grind & Inject Disposal:
Onsite Injection System @ $4280/day
x rental days x CA geographic multiplier
Drilling Fluid Costs
TOTAL CA OBF Cost per Model Well, Grind & Inject ($)
Unit Cost ($/bbl)
No. Wells
TOTAL CA OBF & GRIND & INJECT COST ($)
Unit Costs
Drilling days
Drilling days Operating Days
Rental Days
Geographic multiplier
OBF Drilling Fluid
1 ,387 bbls waste OBF-cuttings ( 0.2% crude contamination)
532 bbls OBF lost with cuttings
3,085 bbls waste OBF-cuttings ( 0.2% crude contamination)
1,184 bbls OBF lost with cuttings
91 7 bbls waste OBF-cuttings ( 0.2% crude contamination)
352 bbls OBF lost with cuttings
1 ,921 bbls waste OBF-cuttings ( 0.2% crude contamination)
737 bbls OBF lost with cuttings
SWD
$1 1 ,490
$5,401
$15,007
$81,770
$7,091
$44,352
$165,111
$180
0
$0
$12.53
$5.89
$40
39
9.62
$355
$8,500
9.62
$126
$89,024
$44,493
$133,517
$146
1
$133,517
5.2
0.4
13.0
1.6
$79.00
SWE
$24,070
$11,315
$22,698
$58,820
$14,536
$92,862
$224,301
$117
0
$0
per bbl
per bbl
per box per day
82
6.92
- box truck load
per day
6.92
per bbl
$186,608
$93,157
$279,765
$146
1
$279,765
10.9
0.4
27.3
1.6
$79.00
TOTAL
$0
$413,282
A-24
-------
Worksheet No. 3
Compliance Cost Estimates (1999$): Baseline Current Practice (BPT)
Existing Sources; Cook Inlet, Alaska
Technology: Zero-Discharge via Haul and Land-Dispose
Model Well Types: Shallow-Water Development Wells
Per-Well Waste Volumes:
Cost Item
OBF Onsite Injection Costs
Onsite Injection System @ $8560/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Cost
(OBF lost with cuttings @ $158/bbl)
Total Cost per Model Well ($)
Unit Cost ($/bbl)
No. Wells
Total OBF Costs per Well Type, Cook Inlet ($)
SWD
917
352
SWD
$111,280
$55,616
$166,896
$182
1
$166,896
SWE
1,921
737
SWE
$233,260
$116,446
$349,706
$381
1
$349,706
bbls waste OBF-cuttings ( 0.2% crude contamination)
bbls OBF lost with cuttings
Drilling days, SWD: SWE:
5.2 10.9
Drilling days: Days-to-Drill Fraction: 0.4
Days-to-Drill:
13.0 27.3
Injection unit cost from GOM vendor $4,280
Geographic Multiplier, Offshore DD 2
AK injection unit cost, $/day) $8,560
Cost OBF ($/bbl), GOM ; $79.00
Geographic Multiplier, Offshore DD 2
AK OBF cost, $/bbl) $1 58.00
Per-well costs x 1 shallow-water development wells
Total Annual Baseline OBF Cook Inlet COST ($) $516,602
SBF Onsite Injection Costs
Onsite Injection System @ $8560/day
Drilling Fluid Cost
(SBF lost with cuttings @ $442/bbl)
Total Cost per Well
$111,280
$155,584
$266,864
$233,260
$325,754
$559,014
Cost from GOM vendor; Geographic 221
Multiplier from Offshore DD 2
442
A-25
-------
Worksheet No. 4
Compliance Cost Estimates (1999$): Cuttings Dryer & FRU Discharge (BAT/NSPS Option 1)
Existing Sources; Gulf of Mexico
Technology: Discharge via both an add-on drill cuttings "dryer" and a fines removal unit with an average fractional
retention value for base fluid on cuttings (wtwt) = 4.03%
Model Well Types: Four types: Deep- and Shallow-water, Development and Exploratory
Per-Well Waste Volumes:
Deep-water Development: 1 ,035 bbls waste cuttings (0.2% crude contamination)
180 bbls SBF/OBF lost with cuttings
Deep-water Exploratory: 2,301 bbls waste cuttings (0.2% crude contamination)
400 bbls SBF/OBF lost with cuttings
Shallow-water Development: 684 bbls waste cuttings (0.2% crude contamination)
119 bbls SBF/OBF lost with cuttings
Shallow-water Exploratory: 1 ,433 bbls waste cuttings (0.2% crude contamination)
249 bbls SBF/OBF lost with cuttings
Cost Item
GOM Wells Projected to Use SBF (Current SBF plus 6%
BAT Solids Control Equipment @ $2400/day x rental days
Cuttings dryer + fines removal unit
Installation and Downtime Costs
($32,500 inst + $24,000 dt)
Drilling Fluid Costs
(SBF lost with cuttings @ $180/bbl)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
SedTox Monitoring Test
Unadjusted Cost Per Well ($)
Unit Cost ($/bbl)
No. SBF wells + WBF>SBF wells + OBF > SBF wells
Total Annual GOM Cost for SBF Wells ($)
Installation/Downtime Well / Structure Adj't Factor
Installation/Downtime Well per Structure
Total Cost Adjustment
Total Adj'd Annual GOM Cost, SBF Wells
Avg Adjusted Total Cost per well type
DWD
OWE
SWD
SWE
TOTAL
WBF &40% OBF Wells Convert) and Discharging All Cuttings
$47,400
$56,500
$39,780
$50
$1,300
$575
$145,605
$141
17
$2,475,285
2.2
($523,909)
$1,951,376
$114,787
$105,000
$56,500
$88,400
$50
$1,700
$575
$252,225
$110
49
$12,359,025
1.6
($1,038,188)
$11,320,838
$231,038
$31,200
$56,500
$26,299
$50
$1,500
$575
$116,124
$170
124
$14,399,376
2.2
($3,821,455)
$10,577,921
$85,306
$65,400
$56,500
$55,029
$50
$2,000
$575
$179,554
$125
74
$13,286,996
1.6
($1,567,875)
$11,719,121
$158,367
$249,000
$226,000
$209,508
$200
$6,500
264
$42,520,682
($6,951,426)
$35,569,256
GOM Wells Retaining Use of OBF ( 0% Conversion)
Cost/Well : Haul and Dispose
Cost/Well: Grind and Inject
Weighted (80:20, haul:inject)Average Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells
No. Wells haul
No. Wells inject
TOT ANNUAL GOM COST (OBF Wells; $)
$110,715
$83,448
$105,262
$115
25
20
5
2,631,544
$236,406
$174,853
$224,096
$117
15
12
3
3,361,437
$329,358
5,992,981
TOT Annual GOM Cost for SBF Improved Solids Control ($) 35,569,256
TOT Annual GOM Cost , SBF+OBF Wells 41,562,237
Includes all equipment, labor, and materials;
days of rental from industry
Installation costs ($32,500) plus
$6,000/hour(avg; Parker, 1999)x4hrs
Cost from vendor
Cost from vendor
Retort run once/discharge/500 ft drilled;
one commingled discharqe; cost from vendor
UNIT COSTS
Drilling days (DWD; OWE; SWD; SWE)| 7.90
Proportion drilling time to operational (rental) time 0.40
BAT Solids Control Equipment (cuttings dryer+FRU ) $2,400
Installation and Downtime Costs: Installation $32,500
: Downtime $24,000
17.50
per day, including ec
nstallation is avg. ol
downtime = $6,000/r
5.20
uipment, labor, and m
range;
our (avq.)x4 hrs; co
10.90
aterials;
sts from Parker 1 999
Drilling Fluid Costs (lost with cuttings) $221 perbblSBF; cost from vendor
Monitoring Analyses
Footage Drilled with SBF (DWD; OWE; SWD; SWE)
Retention of Base Fluids by Retort @ $50/test
Crude Contamination of Drilling Fluid @ $50/test
SedTox Monitoring Test
* FRU: fines removal unit (i.e., decanting centrifuge or mud
6,500
50
50
575
cleaner)
8,500
Retort measured on
Cost from vendor
7,500 1 10,000
:e per discharge per 500 ft drilled; costs fro
n vendor
-------
Worksheet No. 4-A
WBF Upper Bound (10.73%) Analysis for Zero Discharge Wells
Existing Sources; Gulf of Mexico
(Costs incurred only if WBF wells are projected to fail their toxicity or sheen limits)
BAT 1 & 2
WBF ANALYSIS:
(WBF >SBF Wells Only,
projected WBF Costs)
hau
inject
Total No. WBF>SBF Wells
% Fail sheen/tox
No. Wells Fail sheen/tox
No. haul
No. inject
Cost to haul
Cost to inject
Total WBF> SBF Haul+lnject Costs
BAT 1 & 2
WBF ANALYSIS:
(Remaining WBF Wells)
WBF haul, Si/well
WBF inject, $/well
No. WBF wells
% WBF fail sheen /tox (a)
No wells fail sheen/tox
No. haul
No. inject
$ haul
$ inject
Total $
(a) Per ODD
DWD
$906,022
$543,102
1
10.73%
0
0
$0
$0
$0
OWE
$2,724,495
$1,235,566
2
10.73%
0
0
$0
$0
$0
SWD
$627,810
$387,454
32
10.73%
3
2
1
$1,255,620
$387,454
$1,643,074
SWE
$1,429,659
$768,992
19
10.73%
2
2
0
$2,859,318
$0
$2,859,318
(see worksheet 20 for per well cost detail)
(see worksheet 20A for per well cost detail)
$4,114,938
$387,454
$4,502,392!
DWD
$906,022
$543,102
11
10.73%
1
1
$906,022
$906,022
OWE
$2,724,495
$1,235,566
34
10.73%
4
4
$10,897,980
$10,897,980
SWD
$627,810
$387,454
479
10.73%
51
41
10
25,740,210
$3,874,540
$29,614,750
SWE
$1,429,659
$768,992
279
10.73%
30
24
6
34,311,816
$4,613,951
$38,925,767
Installation/Downtime Adjusted BAT 1 SBF Well Costs
Total Annnual GOM Disposal Cost for SBF Wells ($)
No. Wells
Average Cost per well type
Installation/Downtime Well/Structure Adjustment
TOTAL ADJ 'D ANNUAL GOM Cost, SBF Wells ($)
Average Adjusted Total Cost per well type
GOM-widewtd avg per well
DWD
$2,475,285
17
$145,605
($523,909)
$1,951,376
114,787
OWE
$12,359,025
49
$252,225
($1,038,188)
$11,320,838
231,038
SWD
$14,399,376
124
$116,124
($3,821,455)
$10,577,921
85,306
$71,856,028
$8,488,491
$80,344,519
$84,846,911
SWE Totals
$13,286,996 $42,520,682
74 264
$179,554 $161,063
($1,567,875) ($6,951,426)
$11,719,121 $35,569,256
158,367
$134,732
-------
Worksheet NO. 5 (see Baseline CA sheet (W/Ss 2 & 2-A) for SBF/OBF cost projections, all options)
Compliance Cost Estimates (1999$): Discharge from Cuttings Dryer/FRUs (BAT/NSPS Option 1)
Existing Sources, California (Costs no longer applicable; 0% conversion to SBF projected)
Technology: Discharge via both an add-on drill cuttings "dryer" and a fines removal unit with an average fractional
retention of base fluid on cuttings (weight:weight) = 4.03%
Model Well Types: Deep- and Shallow-Water Development Wells
Per-Well Waste Volumes:
Shallow-water Explor.: 1 ,433 bbls waste SBF-cuttings (0.2% crude contamination)
249 bbls SBF lost with cuttings
Shallow-water Development: 684 bbls waste SBF-cuttings (0.2% crude contamination)
119 bbls SBF lost with cuttings
Cost Item
SBF Discharge
SBF Cost Estimate
BAT Solids Control Equipment @ $3840/day x rental days
Cuttings dryer + fines removal unit
Installation and Downtime Costs
($52,000 inst + $38,400 dt)
Drilling Fluid Costs
(SBF lost with cuttings @ $354/bbl)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
SedTox Monitoring Test
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL CA Cost ($)
SWD
$75,840
$90,400
$88,146
$50
$1,300
$575
$256,311
$179
0
$0
SWE
$48,960
$90,400
$42,126
$50
$1,500
$575
$183,611
$268
0
$0
TOTAL
$0
Includes all equipment, labor, and materials; Geographic Area
Cost Multiplier (1 .6) from Offshore DD; rental days from industry data
Installation is avg. of range; downtime is $6,000/hour (avg) x
1 .6 (area multiplier) x 4 hours; costs from Parker 1999
Cost from vendor; Geographic Multiplier from Offshore DD
Cost from vendor
Retort measured once per discharge per 500 ft drilled;
two discharge points; cost from vendor
Per-well costs x no. of wells
UNIT COSTS
Drilling days (DWD; SWD)| 7.9| 5.1 1 from industry
Proportion of drilling time to total operational time (I.e., SCE rental time) 0.4
BAT Solids Control Equipment (cuttings dryer + fines removal unit) $3,840 Includes all equipment, labor, and materials; geographic multiplier (1 .6) from offshore DD
Installation and Downtime Costs: Installation $52,000 Installation is avg. of GOM cost range; plus geographic multiplier
: Downtime $38,400 downtime = $6,000/hour (avg. GOM cost; Parker, 1999) x 4 hrs; plus geographic multiplier
Drilling Fluid Costs (lost with cuttings) $354 perbblSBF; GOM cost plus geographic multiplier; cost from vendor
Monitoring Analyses
Footage Drilled with SBF (DWD; SWD)
Retention of Base Fluids by Retort @ $50/test
Crude Contamination of Drilling Fluid @ $50/test
SedTox Monitoring Test
CA Wells Currently Using OBF ( 0% Conversion Scenario)
TOTAL Cost per Model Well ($)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL BASELINE CA COST ($)
6,500
50
$50
$575
$133,517
$180
1
$133,517
7,500
$279,765
$117
1
$279,765
Retort once/discharge/500 ft drilled; 2 discharge points (cuttings dryer; FRU); vendor costs
Cost from vendor
2
$413,282
A-28
-------
Worksheet No. 6
Compliance Cost Estimates (1999$): Cuttings Dryer/FRU Discharge (BAT/NSPS Option 1)
Existing Sources; Cook Inlet, Alaska (NOTE: SBF disposal projected via onsite injection)
Technology: Discharge via both an add-on drill cuttings "dryer" and fines removal unit;
average fractional retention of basefluid on cuttings (wt:wt) = 4.03%
Vlodel Well Types: Shallow-Water Development Wells
Per-Well Waste Volumes:
Shallow-water Development: 917 bbls waste SBF-cuttings (0.2% crude contamination)
352 bbls SBF lost with cuttings [NOTE: volumes not the same
Shallow-water Exploration: 1,921 as other BAT1 volumes โ current practice is to inject OBF;
737 will not upgrade ttmt system to reduce retention on cuttings. ]
Cost Item
AK WBF Wells: Grind & Onsite Injection (if applicable)
Onsite Injection System @ $8560/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Cost
(WBF lost with cuttings @ $90/bbl)
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells Fail Limts
Total Annual Cook Inlet Cost per Well Type ($)
SWD
$222,560
$27,302
$249,862
$178
0
$0
SWE
$466,520
$52,961
$519,481
$191
0
$0
Cost from GOM vendor; Geographic $180
Multiplier from Offshore DD 2
TOTAL ANNUAL Cook Inlet Cost ($) $0
UNIT COSTS
BAT Solids Control Eqpt (cuttings dryer+fines removal unit)
Drilling days (SWD)
Proportion drilling time to oper'l time (SCE rental time)
Installation and Downtime Costs: Installation
: Downtime
SBF Drilling Fluid Costs (lost with cuttinqs)
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
Footage Drilled with SBF (SWD)
AK Well (n=1 ) Projected to Convert from OBF to SBF; Onsite
Cost Item
Onsite Injection System @ $8560/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Cost
(SBF lost with cuttings @ $442/bbl)
Total Cost per Model Well ($)
Unit Cost ($/bbl)
No. Wells
Total OBF Costs per Well Type, Cook Inlet ($)
Total Annual Baseline OBF Cook Inlet COST ($)
AK OBF Wells (n=2) Projected to Remain OBF; Onsite Inject!
Onsite Injection System @ $8560/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Cost
(OBF lost with cuttings @ $158/bbl)
Total Cost per Model Well ($)
Unit Cost ($/bbl)
No. Wells
Total OBF Costs per Well Type, Cook Inlet ($)
Total Annual Baseline OBF Cook Inlet COST ($)
$4,800
5.2
$0
$65,000
$48,000
$442
$50
$50
$7,500
Injection
SWD
$111,280
$155,584
$266,864
$291
1
$266,864
10.9
SWE
$233,260
$325,754
$559,014
$291
0
$0
$266,864 I
on
$111,280
$55,616
$166,896
$182
0
$0
$233,260
$116,446
$349,706
$182
1
$349,706
$349,706
Includes eqpt/labor/mat'l; geogr multiplier (1 .6) from ODD
from industry
Install1!! is avg. of GOM cost range; + geogr multiplier dwntime
=$6K/h (avg. GOM cost; Parker, 1999x4 h; + geogr multiplier
per bbl SBF; GOM cost + geogr multiplier; cost from vendor
Cost from vendor
Retort once/discharge/500 ft; 2 discharges
(cuttings dryer and FRU); costs from vendor
see Baseline worksheet for details
Cost from GOM vendor; Geographic $221
Multiplier from Offshore DD 2
Cost from GOM vendor; Geographic $79
Multiplier from Offshore DD 2
A-29
-------
Worksheet No. 6-A BAT/NSPS Option 1, Alaska
WBF Upper Bound (10.73%) Analysis for Zero Discharge Wells
(Costs incurred only if WBF wells are projected to fail their
toxicity or sheen limits)
SWD 1,404 bbls waste cuttings
SWD 6,067 bbls WBF discharged
SWE 2,723 bbls waste cuttings
SWE 11,769 bbls WBF discharged
WBF Disposal
Onsite Injection System
Drilling Fluid Cost
Total Cost / Model Well ($)
Unit Cost ($/bbl)
No Wells
No. Wells Fail Limits
Total Costs per Well Type,
DWD
NA
OWE
NA
SWD
$222,560
$27,302
$249,862
$178
3
0
$0
SWE
$466,520
$52,961
$519,481
$191
1
0
$0
5.00% adherent fluid
$90 per bbl, WBF
Total Annual Baseline $0
Cook Inlet Costs ($)
% WBF wells projected to fail toxicity and/or /sheen limitations 10.73%
A-30
-------
Worksheet No. 7
Compliance Cost Estimates (1999$): Cuttings Dryer Discharge; Zero Discharge FRUs (BAT/NSPS Option 2)
Existing Sources; Gulf of Mexico
Technology: Discharge via both an add-on drill cuttings "dryer" and a fines removal unit with an
average fractonal retention of base fluid on cuttings (weightweight) = 3.82%
Model Well Types: Four types: Deep- and Shallow-water, Development and Exploratory
Per-Well Waste Volumes (bbls):
Waste Cuttings @ 3.82% Retention, bbl
SBF Lost with Cuttings, bbl
Waste Fines @ 10.2% Retention, bbl
SBF Lost with Fines, bbl
Cost Item
DWD
999
166
36
14
OWE
2,221
368
80
32
SWD
660
109
24
9
SWE
1,383
229
50
21
DWD
OWE
SWD
SWE
TOTAL
GOM Wells Currently Using SBF and Discharging Cuttings
DISCHARGED PORTION, SBF FLUIDS AND CUTTINGS DRYER WASTE STREAM
BAT Solids Control Equipment @$2400/day x rental days
(Cuttings dryer + fines removal unit costs)
Installation and Downtime Costs
($32,500 inst + $24,000 dt)
Adjustment to Installation/Dopwntime Costs - Multiple Well Structures:
Projected No. Wells per Structure
Adjusted Cost per well for Installation and Downtime
Drilling Fluid Costs @ $221/bbl: SBF lost with cuttings
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
SedTox Monitoring Test
Costs per Well, Discharged Waste/Cuttings Dryer Portion
Unit Cost ($/bbl)
No. SBF wells + WBF>SBF wells + DBF > SBF wells
Annual GOM Cost for Cuttings Dryer Units/SBF Wells
$47,400
$56,500
2.2
($30,818)
$36,686
$50
$650
$575
$111,043
$111
17
$1,887,728
$105,000
$56,500
1.6
($21,188)
$81,328
$50
$850
$575
$223,116
$100
49
$10,932,660
$31,200
$56,500
2.2
($30,818)
$24,089
$50
$750
$575
$82,346
$125
124
$10,210,881
$65,400
$56,500
1.6
($21,188)
$50,609
$50
$1,000
$575
$152,947
$111
74
$11,318,041
$34,349,310
Includes all equipment, labor, and materials;
days of rental from industry
Installation is avg. of range; downtime is
$6,000/hour (avg.) x 4 hrs; costs from Parker 1999
Cost from vendor
Cost from vendor
Retort measured once per discharge per 500 ft drilled;
cost from vendor
DISCHARGED PORTION, ZERO DISCHARGE FINES REMOVAL WASTE STREAM
Zero Discharge of Fines via Hauling
Disposal Costs @ $10.13/bbl
Handling Cost @ $4.75/bbl
Container Rental @ $25/box/day x no. bxx x days to fill and haul
Drilling Fluid Costs @$221/bbl : SBF Lost with Fines
Costs per Well, Zero Discharge FRU Portion
Unit Cost ($/bbl)
No. SBF wells + WBF>SBF wells + DBF > SBF wells
Annual GOM Cost for Fines Removal Units/SBF Wells
$365
$171
$495
$3,094
$4,125
$115
$810
$380
$2,279
$7,072
$10,541
$132
$243
$114
$366
$1,989
$2,712
$113
$507
$238
$1,064
$4,641
$6,449
$129
17 49 124 74
$70,119.56 $516,528.60 $336,240.88 $477,189.00
$1,400,078.04
TOTAL GOM SBF BAT 3 COSTS PER WELL $115,167.50 $233,656.90 $85,057.44 $159,395.00
TOTAL GOM SBF BAT 3 COSTS $1,957,847.56 $11,449,188.60 $10,547,121.88 $11,795,230.00 $35,749,388.04
A-31
-------
GOM Wells Currently Using OBF ( 0% Conversion)
Cost/Well : Haul and Dispose
Cost/Well: Grind and Inject
Weighted (80:20, haul:inject)Average Cost Per Well ($)
Unit Weighted Average Cost ($/bbl)
No. Wells
TOTAL ANNUAL GOM Cost for OBF Wells ($)
$110,715
$83,448
$105,262
$115
25
$2,631,544
$236,406
$174,853
$224,096
$117
15
$3,361,437
40
$5,992,981
TOTAL ANNUAL GOM Cost for SBF Improved Solids Control ($)
TOTAL ANNUAL GOM Cost, SBF+OBF Wells
$35,749,388
$41,742,369
UNIT COSTS
BAT Solids Control Equipment (cuttings dryer + fines removal unit) $2,400
Drilling days (DWD; OWE; SWD; SWE) 7.90
Proportion of drilling time to total operational time (I.e., SCE rental time) 0.4
per day, including all equipment, labor, and materials;
17.50 5.20 10.90 data from industry
Installation and Downtime Costs: Installation
: Downtime
$32,500
$24,000
Installation is avg. of range;
downtime = $6,OOP/hour (avg.) x 4 hrs; costs from Parker 1999
Zero Discharge of Fines via Hauling:
Disposal Costs @ $10.13/bbl
Handling Cost @ $4.75/bbl
Container Rental @ $25/box/day
Number boxes
Number days to fill and haul
$10.13
$4.75
$25
2
9.90
See Worksheet 10
See Worksheet 10
Orentas 2000
4
22.79
2 3
7.31 14.18
Drilling Fluid Costs (lost with cuttings)
$221 per bbl SBF; cost from vendor
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
Footage Drilled with SBF (DWD; OWE; SWD; SWE)
SedTox Monitoring Test|
$50
$50
6500
$575
Cost from vendor
Retort measured once per discharge per 500 ft drilled; one disharge point (cuttings dryer) costs from vendor
8500 7500 10000
Haul/Inject Disposal Costs for SBF Fines Only
Disposal Costs @ $10.13/bbl
Handling Cost @> $4.75/bbl
Container Rental @> $25/bx/d
SBF lost with fines
Total Cost Per Well ($)
No. Wells
TOTAL GOM DISPOSAL COSTS
Deep Water
Devel. Well
$365
$171
$495
$3,094
$4,125
17
$70,120
Deep Water Shallow Water
Explor. Well Devel. Well
$810
$380
$2,279
$7,072
$10,541
49
$516,529
$243
$114
$366
$1,989
$2,712
124
$336,241
Shallow Water
Explor. Well
$507
$238
$1,064
$4,641
$6,449
74
$477,189
$1,400,078]
A-32
-------
Worksheet NO. 8 (see Baseline CA sheet (W/Ss 2 & 2-A) for SBF/OBF cost projections, all options)
Compliance Cost Estimates (1999$): Cuttings Dryer Discharge;
Zero Discharge FRUs (BAT/NSPS Option 2)
Existing Sources, California (Costs no longer applicable; 0% conversion to SBF projected)
Technology: Discharge via both an add-on drill cuttings "df
retention of base fluid on cuttings (wtwt) = 3.82%
Model Well Types: Deep- and Shallow-Water Development Wells
Per-Well Waste Volumes:
Waste Cuttings @ 3.48% Retention
SBF Lost with Cuttings
Waste Fines @ 9.42% Retention
SBF Lost with Fines
SWE
1,383
229
50
20
SWD
660
109
24
9
Cost Item
SWE
SWD
TOTAL
SBF Discharge/Disposal
BAT Solids Control Equipment @ $3840/day x rental days
Cuttings dryer + fines removal unit
Installation and Downtime Costs
($52,000 inst + $38,400 dt)
Zero Discharge of Fines via Hauling
Disposal Co st@ $12. 41/bbl
Handling Cost @ $5.83/bbl
Container Rental @ $40/box/day
Trucking Cost @ $354/50-bbl truckload
Drilling Fluid Costs @ $354/bbl
SBF lost with cuttings
SBF lost with fines
Monitoring Analyses
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
SedTox Monitoring Test
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL CA Cost ($)
$75,840
$90,400
$0
$0
$1,154
$354
$81,066
$7,080
$50
$650
$575
$256,815
$179
0
$0
$49,920
$90,400
$0
$0
$554
$354
$38,586
$3,186
$50
$750
$0
$183,446
$268
0
$0
$0
Includes all equipment, labor, and materials; Geographic Area
Cost Multiplier (1.6) from Offshore DD; rental days from industry
Installation is avg. of range; downtime is $6,000/hour (avg) x
1.6 (area multiplier) x 4 hours; costs from Parker 1999
Cost from vendor; Geographic Multiplier from Offshore DD
Cost from vendor
Retort measured once per discharge per 500 ft drilled;
cost from vendor
Per-well costs x no. of wells
UNIT COSTS
Drilling days (DWD; SWD)
raction of drilling time to total operational (I.e., rental) time
BAT Solids Control Equipment (cuttings dryer + FRU
Installation and Downtime Costs: Installation
: Downtime
Zero Discharge of Fines via Hauling:
Disposal Cost @ $12.32/bbl
Handling Cost @ $5.79/bbl
Container Rental @ $40/box/day
Trucking Cost @ $354/50-bbl truckload
Number boxes
Number days to fill and haul
Drilling Fluid Costs (lost with cuttings)
Monitoring Analyses
Footage Drilled with SBF (DWD; SWD)
Retention of Base Fluids by Retort @ $50/test
Crude Contamination of Drilling Fluid @ $50/test
SedTox Monitoring Test
7.9
0.4
$3,840
$52,000
$38,400
$0
$0
$40
$354
3
9.62
354
6,500
$50
$50
$575
5.2
2
6.92
7,500
data from industry
Includes all equipment, labor, and materials; geographic multiplier (1.6) from offshore D
Installation is avg. of GOM cost range; plus geographic multiplier
downtime = $6,000/hour (avg. GOM cost; Parker, 1999) x 4 hrs; plus geographic multip
per bbl SBF; GOM cost plus geographic multiplier; cost from vendor
per 50-bbl truck load
Retort once/discharge/500 ft drilled; 1 disharge point (cuttings dryer) costs from vendc
Cost from vendor
A-33
-------
Worksheet No. 9
Compliance Cost Estimates (1999$): Discharge from Cuttings Dryer; Zero Discharge of Fines
(BAT 2)Existing Sources; Cook Inlet, Alaska (NOTE: projected SBF disposal - onsite injection)
Technology: Discharge via add-on drill cuttings "dryer" and fines removal unit; average fractional retention of base fluid
on cuttings (wt:wt) = 3.82%
Model Well Types: Shallow-Water Development Wells
Per-Well Waste Volumes:
Waste Cuttings @ 3.48% Retention
SBF Lost with Cuttings
Waste Fines @ 9.42% Retention
SBF Lost with Fines
Cost Item
SWD
917
352
NA
NA
SWE
1,921
737
NA
NA
SWD
SWE
AK WBF Wells: Grind and Onsite Injection Costs (if applicable)
Onsite Injection System
@$8560/day
Drilling Fluid Cost, WBF
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells Fail Limits
TOTAL ANNUAL Cook Inlet Cost ($)
NA
NA
$0
$0
0
$0
NA
NA
$0
$0
0
$0
bbls SBF lost with cuttings [NOTE: the volumes are not the same
as other BAT1 volumes because current practice is to inject OBF;
will not upgrade ttmt system to reduce retention on cuttings. ]
0
UNIT COSTS
Drilling days
Proportion of drilling time to total operational (I.e., rental) time
SBF Drilling Fluid Cost/bbl (lost with cuttings)
5.2
0.4
$442
AK Well (n=1 ) Projected to Convert from OBF to SBF; Onsite Injection
Cost Item
Onsite Injection System @ $8560/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Cost
(SBF lost with cuttings @ $442/bbl)
Total Cost per Model Well ($)
Unit Cost ($/bbl)
No. Wells
TotalAnnual Baseline OBF Cook Inlet COST ($)
SWD
$111,280
$155,584
$266,864
$291
1
266,864.00
10.9
$442
SWE
$233,260
$325,754
$559,014
$291
0
AK OBF Well Projected to Remain OBF; Onsite Injection
Total Cost per Model Well ($)
Unit Cost ($/bbl)
No. Wells
Total Annual Baseline OBF Cook Inlet COST ($)
$166,896
$182
0
$349,706
$182
1
$349,706
see Baseline worksheet for details
A-34
-------
Worksheet No. 9-A BAT/NSPS Option 2, Alaska
WBF Upper Bound (10.73% Analysis for Zero Discharge Wells
(Costs incurred only if WBF wells are projected to fail their
toxicity or sheen limits)
WBF Disposal Analysis
WBF Waste Volumes (per ODD Data)
SWD 1,404 bbls waste cuttings
SWD 6,067 bbls WBF discharged
SWE 2,723 bbls waste cuttings
SWE 11,769 bbls WBF discharged
Onsite Injection System
@$8560/day
Drilling Fluid Cost
Total Cost / Model Well ($)
Unit Cost ($/bbl)
No. Wells
No. Wells Fail Limts
Total Costs / Well Type
Total Annual Cost
DWD
NA
OWE
NA
SWD
$222,560
$27,302
$249,862
$178
3
0
$0
SWE
$466,520
$52,961
$519,481
$191
1
0
$0
$0
xicity and/or /sheen limitations 10.73%
5.00% adherent fluid
$90 per bbl, WBF
A-35
-------
Worksheet No. 10
Per Well Compliance Cost Estimates (1999$): Zero Discharge (BAT 3)
Existing Sources; Gulf of Mexico
Technology: Zero-Discharge via Haul and Land-Dispose
Model Well Types: Four types: Deep- and Shallow-water, Development and Exploratory
Per-Well Waste Volumes:
Deep-water Development:
Deep-water Exploratory:
Shallow-water Development:
Shallow-water Exploratory:
Cost Item
1 ,387 bbls waste cuttings (0.2% crude contamination)
532 bbls SBF lost with cuttings
3,085 bbls waste cuttings (0.2% crude contamination)
1 ,184 bbls SBF lost with cuttings
91 7 bbls waste cuttings (0.2% crude contamination)
352 bbls OBF lost with cuttings
1 ,921 bbls waste cuttings (0.2% crude contamination)
737 bbls OBF lost with cuttings
DWD
OWE
SWD
SWE
GOM OBF Wells Projected to Convert from SBF to OBF Under Zero Discharge
Disposal Cost ($10.13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8,500/day) x days to fill and haul
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Haul and Dispose ($/bbl)
$14,050
$6,588
$14,603
$84,150
$42,028
$161,419
$116
$31 ,251
$14,654
$74,637
$193,715
$93,536
$407,793
$132
$9,289
$4,356
$7,127
$62,135
$27,808
$110,715
$121
$19,460
$9,125
$29,069
$120,530
$58,223
$236,406
$123
GOM SBF Wells Projected to Remain as SBF Wells Under Zero Discharge
Disposal Cost ($10.13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8,500/day) x days to fill and haul
Drilling Fluid Costs
(SBF lost with cuttings @ $221 /bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Haul and Dispose ($/bbl)
For SBF > OBF Wells Under Zero Discharge
$14,050
$6,588
$14,603
$84,150
$117,572
$236,963
$171
$31 ,251
$14,654
$74,637
$193,715
$261 ,664
$575,921
$187
$9,289
$4,356
$7,127
$62,135
$77,792
$160,699
$175
$19,460
$9,125
$29,069
$120,530
$162,877
$341,060
$178
Average of $9.50 and $10.75, quoted
from vendors
Vendor quote, includes
crains, labor, trucks to landfill, etc.
Vendor
Vendors
Vendor quote
Average of $9.50 and $10.75, quoted
from vendors
Vendor quote, includes
crains, labor, trucks to landfill, etc.
Vendor
Vendors
Vendor and operator quotes
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl) $42,028 $93,536
Other Unchanged Costs $1 1 9,391 $31 4,257
TOTAL Cost per Model Well ($) $161,419 $407,793
Unit Cost to Haul and Dispose ($/bbl) $116 $132
A-36
-------
Worksheet No. 11
Per Well Compliance Cost Estimates (1999$): Zero Discharge (BAT 3)
Existing Sources; Gulf of Mexico
Technology:
Zero-Discharge via On-site Grinding and Injection
Model Well Types:
Four types: Deep- and Shallow-water, Development and Exploratory
Per-Well Waste Volumes:
Deep-water Development:
Deep-water Exploratory:
Shallow-water Development:
Shallow-water Exploratory:
1,387 bbls waste SBF-cuttings (0.2% crude contamination)
532 bbls SBF lost with cuttings
3,085 bbls waste SBF-cuttings (0.2% crude contamination)
1,184 bbls SBF lost with cuttings
917 bbls waste SBF-cuttings (0.2% crude contamination)
352 bbls OBF lost with cuttings "
1,921 bbls waste SBF-cuttings (0.2% crude contamination)
737 bbls OBF lost with cuttings
Cost Item
DWD
OWE
SWD
SWE
GOM OBF Wells Projected to Convert from SBF to OBF Under Zero Discharge
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl)
$55,640
$27,808
$116,630
$58,223
Includes all equipment, labor, and services;
vacuum system used to transport cuttings
TOTAL Cost per Model Well ($)
Unit Cost to Grind and Inject ($/bbl)
$83,448
$91
$174,853
$91
GOM SBF Wells Projected to Remain as SBF Wells Under Zero Discharge
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Costs
(SBF lost with cuttings @ $221/bbl)
$84,530
$117,572
$187,250
$261,664
Includes all equipment, labor, and services;
vacuum system used to transport cuttings
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Grind and Inject ($/bbl)
$202,102
$146
$448,914
$146
A-37
-------
Worksheet No. 12
Zero Discharge (BAT 3) Compliance Cost Estimates (1999$)
Existing Sources; Gulf of Mexico
Technology: 100% Deep- and 80% Shallow-water Wells Haul & Land-Dispose; 20% Shallow-water Wells Inject
Model Well Types: Four types: Deep- and Shallow-water, Development and Exploratory
Per-Well Waste Volumes:
Deep-water Development:
Deep-water Exploratory:
Shallow-water Development:
Shallow-water Exploratory:
Cost Item
1,387 bbls waste SBF-cuttings (0.2% crude contamination)
532 bbls SBF lost with cuttings
3,085 bbls waste SBF-cuttings (0.2% crude contamination)
1 , 1 84 bbls SBF lost with cuttings
917 bbls waste SBF-cuttings (0.2% crude contamination)
352 bbls OBF lost with cuttings
1,921 bbls waste SBF-cuttings (0.2% crude contamination)
737 bbls OBF lost with cuttings
DWD
DWE
SWD
SWE
TOTAL
COM OBF Wells Projected to Convert from SBF to OBF Under Zero Discharge
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
Per Well Cost for Zero Discharge ($/well)
No. Wells
SUBTOTAL ANNUAL COM ZD COST ($)
$161,419
8
$1,291,352
$407,793
25
$10,194,826
$110,715
$83,448
$105,262
86
$31,910,282
$236,406
$174,853
$224,096
51
$11,428,885
170
$54,825,346
COM SBF Wells Projected to Remain as SBF Wells Under Zero Discharge
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
Per Well Cost for Zero Discharge ($/well)
No. Wells
SUBTOTAL ANNUAL COM ZD COST ($)
Total Annual COM Costs for Zero Discharge ($)
$236,963
$236,963
3
$710,889
$575,921
$575,921
8
$4,607,368
โ
0
โ
0
$5,318,258
$60,143,603
COM OBF Wells Projected to Continue as OBF Wells
Unit Cost to Haul and Dispose ($/well) $110,715 $236,406
Unit Cost to Grind and Inject ($/well) $83,448 $174,853
Weighted Average Unit Disposal Cost ($/well) $105,262 $224,096
Number of Wells 34 20 54
Total Cost per Well Type $3,578,900 $4,481,916
Total Cost $8,060,816
Total Annual COM Costs for Zero Discharge ($) 68,204,419
COM Wells Using SBF Assumed to Switch to WBF Under Zero Discharge and Fall WBF Sheen/Tox Limits
Per Well Cost for Zero Discharge ($/well)
No. Wells
SUBTOTAL ANNUAL COM ZD COST ($)
WBF Disposal Analysis: Remaining WBF
Wells + 49 SBF > WBF Discharging Wells)
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
No. Wells, Total
Projected % Wells to Fail Sheen/Tox Limitations
Projected No. Wells to Fail Sheen/Tox Limitations
No. Wells Projected to Haul & Land Dispose
80%
No. Wells Projected to Grind & Inject Onsite
20%
Total Cost to Haul & Land Dispose
Total Cost to Grind & Inject
Total Cost of Disposal, WBF Wells
Total COM Cc
$161,419
1
$161,419
$407,793
2
$815,586
$105,262
0
$0
$224,096
0
$0
$977,005
DWD
$906,022
$543,102
16
10.73%
2
2
0
$1,812,044
$0
$1,812,044
DWE
$2,724,495
$1,235,566
49
10.73%
5
5
0
$13,622,475
$0
$13,622,475
SWD
$627,810
$387,454
511
10.73%
55
44
11
$27,623,640
$4,261,994
$31,885,634
SWE
$1,429,659
$768,992
298
10.73%
32
26
6
$37,171,134
$4,613,951
$41,785,085
TOTAL
94
$80,229,293
$8,875,945
$89,105,238
st of Disposal, $158,286,662
A-38
-------
Summary Compliance Costs for Management of Large Volume SBF Wastes,
Existing Sources ('40% OBF Wells, 6% WBF Wells Convert1), 1999$
Lower (0%) WBF Failure Rate Boundary
Baseline Costs: Total Annual
Baseline Technology(a)
Discharge with 10.2% retention of base fluid
on cuttings from SBF wells
Zero Discharge-current OBF users
Zero Discharge-current WBF users
TOTAL Per Region
Com
BAT-1
BAT-2
BAT-3
jliance Costs: Total Annual
Technology Option(b)
Discharges from Cuttings Dryer and FRUs
(ROC = 4.03%); SBF wells
Discharges from Cuttings Dryer and FRUs
(ROC = 4.03%); OBF wells
Discharges from Cuttings Dryer and FRUs
(ROC = 4.03%); WBF wells
TOTAL Per Region
Discharges from Cuttings Dryer only (ROC =
3.82%); Zero Discharge FRUs; SBF wells
Discharges from Cuttings Dryer only (ROC =
3.82%); Zero Discharge FRUs; OBF wells
Discharges from Cuttings Dryer only (ROC =
3.82%); Zero Discharge FRUs; WBF wells
TOTAL Per Region
Zero Discharge: SBF wells
Zero Discharge: OBF wells
Zero Discharge: WBF wells
TOTAL Per Region
GOM
29,437,863
10,034,296
0
39,472,159
CA
0
413,282
0
413,282
AK(CI)
0
516,602
0
516,602
Total
Per Technology
29,437,863
10,964,179
0
40,402,042
NOTES
Worksheet No. 1
Worksheet No.sl, 2, and 3
GOM
35,569,256
5,992,981
0
41,562,237
35,749,388
5,992,981
0
41,742,369
5,318,258
62,886,162
0
68,204,419
Incremental Compliance Costs: Total Annual
Technology Option
BAT-1 : Discharge from Cuttings Dryer and
Fines Removal Unit
BAT-2: Discharge from Cuttings Dryer and
Zero Discharge of Fines
Zero Discharge
WBF-related Costs (Savings)
GOM
2,090,078
2,270,210
28,732,260
Technology Option GOM
BAT-1: ROP-related rig cost savings (33,280,000)
Discharged WBF cost savings (15,552,540)
Zero discharge cost savings 0
BAT-2: ROP-related rig cost savings (33,280,000)
Discharged WBF cost savings (15,552,540)
Zero discharge cost savings 0
NET Incremental Compliance Costs: Total Annual
Technology Option
BAT-1 : Discharge from Cuttings Dryer and
Fines Removal Unit
BAT-2: Discharge from Cuttings Dryer and
Zero Discharge of Fines
Zero Discharge**
GOM
(46,742,462)
(46,562,330)
28,732,260
CA
0
413,282
0
413,282
0
413,282
0
413,282
0
413,282
0
413,282
CA
0
0
0
CA
0
0
0
0
0
0
CA
0
0
0
AK(CI)
266,864
349,706
0
616,570
266,864
349,706
0
616,570
0
516,602
0
516,602
AK(CI)
99,968
99,968
0
AK(CI)
0
0
0
0
0
0
AK(CI)
99,968
99,968
0
Total
PerTechnol
35,836,120
6,755,969
0
42,592,088
36,016,252
6,755,969
0
42,772,221
5,318,258
63,816,045
0
69,134,303
Total
PerTechnol
2,190,046
2,370,178
28,732,260
Total
PerTechnol
(48,832,540)
(48,832,540)
Total
PerTechnol
(46,642,494)
(46,462,362)
28,732,260
NOTES
Worksheet No.s 4, 5, and 6
Worksheet No.s 7, 8, and 9
Worksheet No.s 10, 11, and 12
NOTES
BAT-1 compliance cost ::
total baseline cost differential
BAT-2 compliance cost ::
total baseline cost differential
BAT-3 (ZD) compliance cost ::
GOM baseline cost differential
NOTES
NOTES
BAT-1 compliance cost ::
total baseline cost differential
BAT-2 compliance cost ::
total baseline cost differential
BAT-3 (ZD) compliance cost ::
total baseline cost differential
(a) GOM: 857 WBF, 201 SBF wells, 67 OBF wells; CA: 5 WBF, 2 OBF wells; AK 4 WBF, 2 OBF wells
(b) BAT 1: GOM: 803 WBF, 264 SBF wells, 40 OBF wells; CA: 5 WBF, 2 OBF wells; AK 4 WBF, 1 SBF, 1 OBF wells
BAT 2: GOM: 803 WBF, 264 SBF wells, 40 OBF wells; CA: 5 WBF, 2 OBF wells; AK 4 WBF, 1 SBF, 1 OBF wells
BAT 3: GOM: 877 WBF, 11 SBF wells, 237 OBF wells; CA: 5 WBF, 2 OBF wells; AK 4 WBF, 2 OBF wells
A-39
-------
Worksheet No. 13
Compliance Cost Estimates (1999$): Baseline Current Practice (BPT)
New Sources; Gulf of Mexico
Technologies: Discharge of SBF cuttings, add-on cuttings dryer, avg. ret'n= 10.2% (wt) base fluid on cuttings
Model Well Types: Deep- and Shallow-water Development
Per-Well Waste Volumes:
Deep-water Development:
Shallow-water Development:
Cost Item
1 ,387 bbls waste SBF cutt ngs (0.2% crude contamination)
532 bbls SBF lost with cutt ngs
917 bbls waste SBF cutt ngs (0.2% crude contamination)
352 bbls SBF lost with cuttings
DWD
OWE
TOTAL
Drilling Fluid Costs for Wells Currently Using SBF
(SBF@ $221 /bbl lost w/ cuttings)
Per Well Baseline Cost ($/well)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL BASELINE GOM SBF COST ($)
$117,572
$117,572
$85
15
$1,763,580
$77,792
$77,792
$85
5
$388,960
$2,152,540
Cost from vendor
Average cost for full analysis
Per-well costs x no. of wells
Drilling Fluid Costs for Wells Currently Using OBF
(OBF@ $79/bbl lost w/ cuttings)
Per Well Baseline Cost ($/well)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL BASELINE GOM OBF COST ($)
$161,419
$116
0
$0
$110,715
$115
2
$221,430
$221,430
Cost from vendor
Drilling Fluid Costs for Wells Currently Using WBF
(WBF@ $45/bbl lost w/ cuttings)
Per Well Baseline Cost ($/well)
Unit Cost ($/bbl)
No. Wells Fail Limits
No. Wells
TOTAL ANNUAL BASELINE GOM WBF COST ($)
$906,022
$91
1
11
$906,022
$627,810
$387,454
$86
3
27
$1,643,075
haul
inject
$2,549,097
Cost from vendor
TOTAL ANNUAL BASELINE GOM COST ($)| $4,923,067
A-40
-------
Summary Compliance Costs for Management of Large Volume SBF Wastes,
New + Existing Sources ( '40% OBF Wells, 6% WBF Wells Convert1), 1999$
Lower (0%) WBF Failure Rate Boundary
Baseline Costs: Total Annual
Baseline Technology
Discharge with 9.42% retention of base fluid
on cuttings ( xxx SBF wells in GOM)
Zero Dischargeโcurrent OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโcurrent WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
Compliance Costs: Total Annual
BAT-1
BAT-2
BAT-3
Technology Option
BAT-1: Discharge from Cuttings Dryer and
Fines Removal Unit(R = 3.68%)*
Zero Dischargeโ current OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโ current WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
BAT-2: Discharge from Cuttings Dryer
(R = 3.48%) and Zero Discharge of Fines*
Zero Dischargeโ current OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโ current WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
BAT 3 Zero Discharge
(xxxx current SBF wells)
Zero Dischargeโ current OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโ current WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
GOM
31,590,403
10,255,726
0
41,846,129
CA
0
413,282
0
413,282
AK(CI)
0
516,602
0
516,602
Total
Per Technol
31,590,403
11,185,610
0
42,776,013
NOTES
Worksheet No. 1
Worksheet No.s 1,2, and 3
GOM
37,471,928
6,103,696
0
43,575,624
37,656,164
6,103,696
0
43,759,860
6,029,147
64,925,253
0
70,954,400
Incremental Compliance Costs: Total Annual
Technology Option
BAT-1: Discharge from Cuttings Dryer and
Fines Removal Unit
BAT-2: Discharge from Cuttings Dryer and
Zero Discharge of Fines
Zero Discharge**
WBF-related Costs (Savings)
Technology Option
BAT-1: ROP-related rig cost savings
Discharged WBF cost savings
Zero discharge cost savings
BAT-2: ROP-related rig cost savings
Discharged WBF cost savings
Zero discharge cost savings
GOM
1,729,495
1,913,731
29,108,271
GOM
(34,720,000)
(16,236,045)
0
(34,720,000)
(16,236,045)
0
NET Incremental Compliance Costs: Total Annual
Technology Option
BAT-1: Discharge from Cuttings Dryer and
Fines Removal Unit
BAT-2: Discharge from Cuttings Dryer and
Zero Discharge of Fines
Zero Discharge**
GOM
(49,226,550)
(49,042,314)
29,108,271
CA
0
413,282
0
413,282
0
413,282
0
413,282
0
413,282
0
413,282
CA
0
0
0
CA
0
0
0
0
0
0
CA
0
0
0
AK(CI)
266,864
349,706
0
616,570
266,864
349,706
0
616,570
0
516,602
0
516,602
AK(CI)
99,968
99,968
0
AK(CI)
0
0
0
0
0
0
AK(CI)
99,968
99,968
0
Total
Per Technol
37,738,792
6,866,684
0
44,605,476
37,923,028
6,866,684
0
44,789,712
6,029,147
65,855,137
0
71,884,284
Total
Per Technol
1,829,463
2,013,699
29,108,271
Total
Per Technol
(50,956,045)
(50,956,045)
Total
Per Technol
(49,126,582)
(48,942,346)
29,108,271
NOTES
Worksheet No.s 4, 5, and 6
Worksheet No.s 7, 8, and 9
Worksheet No.s 10, 11, and 12
NOTES
BAT-1 compliance cost ::
total baseline cost differential
BAT-2 compliance cost ::
total baseline cost differential
BAT-3 (ZD) compliance cost ::
GOM baseline cost differential
NOTES
NOTES
BAT-1 compliance cost ::
total baseline cost differential
BAT-2 compliance cost ::
total baseline cost differential
BAT-3 (ZD) compliance cost ::
total baseline cost differential
-------
Summary Compliance Costs for Management of Large Volume SBF Wastes,
New Sources ( '40% OBF Wells, 6% WBF Wells Convert1), 1999$
Lower (0%) WBF Failure Rate Boundary
Baseline Costs: Total Annual
Baseline Technology
Discharge with 9.42% retention of base fluid
on cuttings ( xxx SBF wells in GOM)
Zero Dischargeโcurrent OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโcurrent WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
Compliance Costs: Total Annual
BAT-1
BAT-2
BAT-3
Technology Option
BAT-1: Discharge from Cuttings Dryer and
Fines Removal Unit(R = 3.68%)*
Zero Dischargeโ current OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโ current WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
BAT-2: Discharge from Cuttings Dryer
(R = 3.48%) and Zero Discharge of Fines*
Zero Dischargeโ current OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโ current WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
BAT 3 Zero Discharge
(xxxx current SBF wells)
Zero Dischargeโ current OBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
Zero Dischargeโ current WBF users only
(xxxx GOM wells; xxxx CA wells; xxxx AK well)
TOTAL Per Region
GOM
2,152,540
221,430
0
2,373,970
CA
0
0
0
0
AK(CI)
0
0
0
0
Total
Per Technol
2,152,540
221,430
0
2,373,970
NOTES
Worksheet No. 1
Worksheet No.s 1,2, and 3
GOM
1,902,672
110,715
0
2,013,387
1,906,776
110,715
0
2,017,491
710,889
2,039,092
0
2,749,981
Incremental Compliance Costs: Total Annual
Technology Option
BAT-1: Discharge from Cuttings Dryer and
Fines Removal Unit
BAT-2: Discharge from Cuttings Dryer and
Zero Discharge of Fines
Zero Discharge**
WBF-related Costs (Savings)
Technology Option
BAT-1: ROP-related rig cost savings
Discharged WBF cost savings
Zero discharge cost savings
BAT-2: ROP-related rig cost savings
Discharged WBF cost savings
Zero discharge cost savings
GOM
(360,583)
(356,479)
376,011
GOM
(1,440,000)
(683,505)
0
(1,440,000)
(683,505)
0
NET Incremental Compliance Costs: Total Annual
Technology Option
BAT-1: Discharge from Cuttings Dryer and
Fines Removal Unit
BAT-2: Discharge from Cuttings Dryer and
Zero Discharge of Fines
Zero Discharge**
GOM
(2,484,088)
(2,479,984)
376,011
CA
0
0
0
0
0
0
0
0
0
0
0
0
CA
0
0
CA
0
0
0
0
0
0
CA
0
0
0
AK(CI)
0
0
0
0
0
0
0
0
0
0
0
0
AK(CI)
0
0
AK(CI)
0
0
0
0
0
0
AK(CI)
0
0
0
Total
Per Technol
1,902,672
110,715
0
2,013,387
1,906,776
110,715
0
2,017,491
710,889
2,039,092
0
2,749,981
Total
Per Technol
(356,479)
376,011
Total
Per Technol
(2,123,505)
(2,123,505)
Total
Per Technol
(2,484,088)
(2,479,984)
376,011
NOTES
Worksheet No.s 4, 5, and 6
Worksheet No.s 7, 8, and 9
Worksheet No.s 10, 11, and 12
NOTES
BAT-1 compliance cost ::
total baseline cost differential
BAT-2 compliance cost ::
total baseline cost differential
BAT-3 (ZD) compliance cost ::
GOM baseline cost differential
NOTES
NOTES
BAT-1 compliance cost ::
total baseline cost differential
BAT-2 compliance cost ::
total baseline cost differential
BAT-3 (ZD) compliance cost ::
total baseline cost differential
-------
Worksheet No. 14
Compliance Cost Estimates (1999$): Discharge from Cuttings Dryer and FRUs
(BAT 1 Technology) New Sources; Gulf of Mexico
Technology: Discharge via add-on drill cuttings "dryer;" fines remova unit, avg retention 4.03% (wt) base fluid on cuttings
Model Well Types: Deep- and Shallow-water Development
Per-Well Waste Volumes:
Deep-water Development:
Shallow-water Development:
Cost Item
1,035 bbls waste SBF cuttings (0.2% crude contamination)
180 bbls SBF lost with cuttings
684 bbls waste SBF cuttings (0.2% crude contamination)
119 bbls SBF lost with cuttings
DWD
SWD
TOTAL
GOM Wells Currently Using SBF and Discharging Cuttings
BAT Solids Control Equipment @ $2400/day x rental days
(Cuttings dryer plus fines removal unit that reduces
base fluid retention from 10.2% to 4.03%)
Drilling Fluid Costs
(SBF lost with cuttings @ $221/bbl)
Monitoring Analyses
SedTox Test
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL GOM Cost for SBF Wells ($)
$47,400
$39,780
$575
$50
$1,300
$89,105
$86
16
$1,425,680
$31,200
$26,299
$575
$50
$1,500
$59,624
$87
8
$476,992
$1,902,672
ncludes all equipment, labor, and materials;
days of rental from industry
Cost from vendor
Cost from vendor
Retort measured once per both discharge points/ 500 ft
GOM Wells Currently Using OBF and Zero Discharge
Disposal Cost ($10. 13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8, 500/day x days to fill and haul)
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl)
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL GOM Cost for OBF Wells ($)
GOM Wells Currently Using WBF and Zero Discharge
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
Wtd Avg TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells Fail Limits
No. Wells
TOTAL ANNUAL GOM Cost for WBF Wells ($)
NA
0
$0
$906,022
$543,102
$833,438
$91
1
10
$906,022
$9,289
$4,356
$7,127
$62,135
$27,808
$110,715
$121
1
$110,715
$627,810
$387,454
$579,739
$86
3
25
$1,643,075
$110,715
$2,549,097
Includes all equipment, labor, and materials;
days of rental from industry
Cost from vendor
Per-well costs x no. of wells
ncludes all equipment, labor, and materials;
days of rental from industry
Cost from vendor
TOTAL ANNUAL GOM Cost for Wells ($) $4,562,484
-------
Worksheet No. 15
Compliance Cost Estimates (1999$): Discharge from Cuttings Dryer and FRUs
(BAT 2 Technology) New Sources; Gulf of Mexico
Technology: Discharge via add-on drill cuttings "dryer," avg retention 3.82% (wt) base fluid on cuttings; zero discharge of fines
Model Well Types: Deep- and Shallow-water Development
Pen-Well Waste Volumes:
Waste Cuttings @ 3.82% Retention, bbl
SBF Lost with Cuttings, bbl
Waste Finesยฎ 10.2% Retention, bbl
SBF Lost with Fines, bbl
Cost Item
DWD SWD
999
166
36
14
660
109
24
9
DWD
SWD
TOTAL
COM Wells Currently Using SBF and Discharging Cuttings: Discharged Portion, Cuttings Dryer
BAT Solids Control Eguipment @ $2400/day x rental days
(Cuttings dryer plus fines removal unit that reduces
base fluid retention from 10. 2 to 4.03%)
Drilling Fluid Costs
(SBF lost with cuttings @ $221 Abl)
Monitoring Analyses
SedTox Test
Crude Contamination of Drilling Fluid @ $50/test
Retention of Base Fluids by Retort @ $50/test
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL COM Cost for SBF Wells ($)
Zero Discharge Fines Portion
Zero Discharge of Fines via Hauling
Disposal Costs @ 10.13/bbl
Handling Costs @ 4.75/bbl
Container Rental @ $25/box/day x days to fill
Drilling Fluid Costs @ $221/bbl
SBF lost with fines
Total Cost per Well, Fines Portion
No. Wells
TOTAL ANNUAL COM Cost for SBF Wells ($)
COM Wells Currently Using OBF and Zero Discharge
Disposal Cost ($10.13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8,500/day)
Drilling Fluid Costs
(OBF lost with cuttings @> $79/bbl)
TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells
TOTAL ANNUAL COM Cost for OBF Wells ($)
COM Wells Currently Using WBF and Zero Discharge
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
Wtd Avg TOTAL Cost Per Well ($)
Unit Cost ($/bbl)
No. Wells Fail Limits
No. Wells
TOTAL ANNUAL COM Cost for WBF Wells ($)
$47,400
$36,686
$575
$50
$650
$85,361
$85
16
$1,365,776
$365
$171
$495
$3,094
$4,125
16
$65,995
NA
0
$0
$906,022
$543,102
$833,438
$91
1
10
$906,022
$31,200
$24,089
$575
$50
$750
$56,664
$86
8
$453,312
$243
$114
$366
$1,989
$2,712
8
$21,693
$9,289
$4,356
$7,127
$62,135
$27,808
$110,715
$121
1
$110,715
$627,810
$387,454
$579,739
$86
3
25
$1,643,075
1,819,088
87,688
$110,715
$2,549,097
Includes all eguipment, labor, and materials;
days of rental from industry
Cost from vendor
Retort measured once / single discharge point/ 500 ft drilled;
Per-well costs x no. of wells
See Worksheet 4
See Worksheet 4
Orentas 2000
Cost from vendor
Includes all eguipment, labor, and materials;
days of rental from industry
Cost from vendor
Per-well costs x no. of wells
Includes all eguipment, labor, and materials;
days of rental from industry
Cost from vendor
Per-well costs x no. of wells
TOTAL ANNUAL COM Cost for Wells ($) $4,566,588
Percentage WBF Wells Projected to Fail Sheen/Toxicity Limit and Have a Zero Discharge Restriction:
Zero Discharge of Fines via Hauling:
Disposal Costsยฎ $10.13/bbl
Handling Cost @ $4.75/bbl
Container Rental @ $25/box/day
Number boxes
Number days to fil and haul
SedTox Test
10.13 See Worksheet 10
4.75 See Worksheet 10
25 Orentas 2000
2 2
9.90 7.31
575
-------
Worksheet No. 16
Compliance Cost Estimates (1999$): Zero Discharge (BAT 3 Technology)
New Sources; Gulf of Mexico
Technology: Zero-Discharge via Haul and Land-Dispose
Model Well Types: Deep- and Shallow-water Development
Per-Well Waste Volumes:
Deep-water Development:
Shallow-water Development:
Cost Item
1 ,387 bbls waste SBF (OBF) cuttings (0.2% crude contamination)
532 bbls SBF (OBF) lost with cuttings
917 bbls waste OBF (SBF) cuttings (0.2% crude contamination)
352 bbls OBF (SBF) lost with cuttings
DWD
SWD
GOM Wells Using SBF Assumed to Switch to OBF Under Zero Discharge
Disposal Cost ($10.13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8,500/day)
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Haul and Dispose ($/bbl)
$14,050
$6,588
$14,603
$84,150
$42,028
$161,419
$176
$9,289
$4,356
$7,127
$62,135
$27,808
$110,715
$121
Average of $9.50 and $10.75, guoted
from vendors
Vendor guote; includes crains, labor, trucks
to landfill, etc.
Vendor cost estimate; 39 boxes estimated capacity reguired
Vendors
Vendor guote
GOM Wells Using SBF Assumed to Retain SBF Under Zero Discharge
Disposal Cost ($10.13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8,500/day)
Drilling Fluid Costs
(SBF lost with cuttings @ $221/bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Haul and Dispose ($/bbl)
$14,050
$6,588
$14,603
$84,150
$117,572
$236,963
$171
$9,289
$4,356
$7,127
$62,135
$77,792
$160,699
$175
Average of $9.50 and $10.75, guoted
from vendors
Vendor guote; includes crains, labor, trucks
to landfill, etc.
Vendor cost estimate; 39 boxes estimated capacity reguired
Vendors
Vendor guote
GOM Wells Using WBF Assumed to Retain WBF Under Zero Discharge
Disposal Cost ($10.13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
($25/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8,500/day)
Drilling Fluid Costs
(WBF lost with cuttings @ $45/bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Haul and Dispose ($/bbl)
$102,495
$48,061
$213,124
$168,300
$374,042
$906,022
$90
$75,681
$35,487
$116,198
$124,270
$276,174
$627,810
$84
Average of $9.50 and $10.75, guoted
from vendors
Vendor guote; includes crains, labor, trucks
to landfill, etc.
Vendor cost estimate; 39 boxes estimated capacity reguired
Vendors
Vendor guote
A-45
-------
Worksheet No. 17
Compliance Cost Estimates (1999$): Zero Discharge (BAT 3 Technology)
New Sources; 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:
Shallow-water Development:
Cost Item
1,387
532
917
352
DWD
bbls waste SBF cuttings (0.2% crude contamination)
bbls SBF lost with cuttings
bbls waste OBF cuttings (0.2% crude contamination)
bbls OBF lost with cuttings
SWD
Information below is detailed in
GOM Wells Using SBF Assumed to Switch to OBF Under Zero Discharge
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig, thus
rental days = 2.5 x drilling days)
Drilling Fluid Costs
(OBF lost with cuttings @ $79/bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Grind and Inject ($/bbl)
NA
$ 55,640
$ 27,808
$ 83,448
$ 91
Includes all equipment, labor, and services; vacuum
system used to transport cuttings
Cost from vendor
GOM Wells Using SBF Assumed to Retain SBF Under Zero Discharge
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig)
Drilling Fluid Costs
(SBF lost with cuttings @ $221 /bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Grind and Inject ($/bbl)
NA
$ 55,640
$ 77,792
$ 133,432
$ 146
Includes all equipment, labor, and services; vacuum
system used to transport cuttings
Cost from vendor
GOM Wells Using WBF Assumed to Retain WBF Under Zero Discharge
Onsite Injection System @ $4280/day
(drilling days = 40% of time on rig)
Drilling Fluid Costs
(SBF lost with cuttings @ $45/bbl)
TOTAL Cost per Model Well ($)
Unit Cost to Grind and Inject ($/bbl)
Drilling days
drilling days = 40% of time on rig
Onsite Injection System, /day
$ 169,060
$ 374,042
$ 543,102
$ 54
$ 111 ,280
$ 276,174
$ 387,454
$ 52
7.9
0.4
4280
5.2
0.4
4280
Includes all equipment, labor, and services; vacuum
system used to transport cuttings
Cost from vendor
A-46
-------
Worksheet No. 18
Compliance Cost Estimates (1999$): Zero Discharge (BAT 3 Technology)
New Sources; Gulf of Mexico
Technology:
Deep- and 80% Shallow-water Wells Haul & Land-Dispose; 20% Shallow Inject
Model Well Types:
Deep- and Shallow-water Development
Per-Well Waste Volumes:
Deep-water Development:
Shallow-water Development:
1,387 bbls waste SBF cuttings (0.2% crude contamination)
532 bbls SBF lost with cuttings
917 bbls waste OBF cuttings (0.2% crude contamination)
352 bbls OBF lost with cuttings
Cost Item
DWD
SWD
TOTAL
Notes
Veils Using SBF Assumed to Switch to OBF Under Zero Discharge
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
Weighted Average Per Well Cost ($/well)
Weighted Average Unit Cost ($/bbl)
No. Wells
SUBTOTAL ANNUAL GOM ZD COST ($)
161,419
NA
161,419
116
8
1,291,352
110,715
83,448
105,262
115
747,739
From Worksheet No. 3
From Worksheet No. 4
Assumes 80% of shallow water sells haul,
2,039,092
ells Using SBF Assumed to Retain SBF Under Zero Discharge
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
Weighted Average Per Well Cost ($/well)
Weighted Average Unit Cost ($/bbl)
No. Wells
SUBTOTAL ANNUAL GOM ZD COST ($)
236,963
NA
236,963
171
3
710,889
160,699
133,432
155,246
146
0
From Worksheet No. 3
Assumes 100% of deep water wells haul
710,889
GOM Wells Using WBF Assumed to Retain WBF Under Zero Discharge
Unit Cost to Haul and Dispose ($/well)
Unit Cost to Grind and Inject ($/well)
Weighted Average Per Well Cost ($/well)
Weighted Average Unit Cost ($/bbl)
No. Wells Fail Limits
No. Wells
SUBTOTAL ANNUAL GOM ZD COST ($)
906,022
543,102
833,438
91
2
15
1,812,044
627,810
387,454
579,739
86
3
27
1,643,075
From Worksheet No. 3
Assumes 100% of deep water wells haul
3,455,119
Total Annual GOM Costs for Zero Discharge ($)
6,205,100
A-47
-------
Worksheet No. 19
Compliance Cost Estimates (1999$), Small Volume SBF Wastes
BAT Option (Zero Discharge)
[ Estimated Small-Volume Waste Amount per well = 75 bbls ]
Cost Item
GOM
(Costs from Wksht No. 10)
Disposal cost @ $10.13/bbl
Handling cost @ 4.75/bbl
Container rental @ $25/25-bbl box/day
Cost Per Well
Total Number of Wells
Total Regional Cost
CALIFORNIA
(no longer applicable: no SBF wells)
Disposal cost @ $12.47/bbl
Handling cost @ $5.86/bbl
Container Rental @ $40/25-bbl box/day
Trucking cost @ $354/50-bbl truckload
Cost Per Well
Total Number of Wells
Total Regional Cost
COOK INLET (not applicable; wastes
injected onsite, no add'l cost)
Disposal cost @ $540 per 8-bbl box
8-bbl box purchase cost @ $135/box
Trucking cost @ $1 ,944 per 8-box truckload
Cost Per Well
Total Number of Wells
Total Regional Cost
Total Annual Cost
Cost
$760
$356
$105
$1,221
$935
$440
$120
$708
$2,203
$5,400
$1 ,350
$3,888
$10,638
Existing Sources
Baseline
201
$245,421
0
$0
0
$0
$245,421
BAT
1 &2
264
$322,344
0
$0
0
$0
$322,344
BAT 3
11
$13,431
0
$0
0
$0
$13,431
New Sources
Baseline
20
$24,420
0
$0
0
$0
$24,420
BAT
1 &2
24
$29,304
0
$0
0
$0
$29,304
BAT 3
3
$3,663
0
$0
0
$0
$3,663
Total Existing & New Sources
Baseline
221
$269,841
0
$0
0
$0
$269,841
BAT
1 &2
288
$351,648
0
$0
0
$0
$351,648
BAT 3
14
$17,094
0
$0
0
$0
$17,094
-------
Worksheet No. 20:
WBF Upper Bound (10.73%) Analysis for Zero Discharge Wells
(Costs incurred only if WBF wells are projected to fail toxicity of sheen limits)
WBF Disposal Analysis
WBF Waste Volumes (per ODD data)
Deep-water Devel 1,901
8,217
Deep-water Explor
bbls cuttings
bbls WBF discharged
Shallow-water Develop
Shallow-water Explor
4,376 bbls cuttings
18,916 bbls WBF discharged
1,404 bbls cuttings
6,067 bbls WBF discharged
2,723 bbls cuttings
11,769 bbls WBF discharged
WBF Disposal Analysis
Disposal Cost ($10.13/bbl)
Handling Cost ($4.75/bbl)
Container Rental
x WBF days to fill and haul
Supply Boat Cost ($8,500/day)
x WBF days to fill and haul
Drilling Fluid Costs
TOTAL Cost / Model Well ($)
DWD
$102,495
$48,061
$213,124
$168,300
$374,042
$906,022
OWE
$235,948
$110,637
$1,129,414
$387,430
$861,066.00
$2,724,495
SWD
$75,681
$35,487
$116,198
$124,270
$276,174
$627,810
SWE
$146,804
$68,837
$437,227
$241 ,060
$535,732
$1,429,659
5.00%
$45.00
adherent drilling fluid
per bbl, WBF
A-49
-------
Worksheet No. 21 : Baseline Current Practice (BPT), Existing Sources, California
WBF Upper Bound (10.73%) Analysis for Zero Discharge Wells
(Costs incurred only if WBF wells are projected to fail their toxicity or sheen limits)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
DWD
DWD
OWE
OWE
SWD
SWD
SWE
SWE
1,901
8,217
4,376
18,916
1,404
6,067
2,723
1 1 ,769
bbls waste cuttings
bbls WBF discharged
bbls waste cuttings
bbls WBF discharged
bbls waste cuttings
bbls WBF discharged
bbls waste cuttings
bbls WBF discharged
% WBF wells projected to fail toxicity and/or /sheen limitations 1 0.73%
WBF HAUL & LAND DISPOSE COSTS
Disposal Cost ($ 8.41 /bbl)
Handling Cost ($ 3.95/bbl)
Container Rental
($40/box/day * "x" boxes* "y" days to fill & haul)
Supply Boat Cost ($8,500/day x days to fill and haul)
Trucking Cost ($354/truck load)
Drilling Fluid Costs
(WBF lost with cuttings @ $72/bbl)
No. Wells
Total Cost / WBF Well (Haul)
No. Wells Fail Limits
TOTAL CA WBF Haul & Land Dispose Costs
Unit Costs
bbl waste, DBF
no. bxx waste, OBF
bbl/bx
bbl WBF, tot
bxx WBF
Days to fill & haul , WBF
Container Rental
bx/trk
no trks
cost/truck
WBF cost (+CA multiplier, 1 .6)
DWD
$85,123
$40,008
$341 ,352
$168,300
$76,582
$728,496
0
$1,439,861
0
$0
DWD
1,387
59
23.5
10,118
431
19.8
$40
2
216
$355
$72.00
OWE
$195,957
$92,100
$1 ,804,968
$387,430
$175,855
$1 ,677,024
0
$4,333,333
0
$0
OWE
3,085
131
23.5
23,292
990
45.58
$40
2
496
$355
$72.00
SWD
$62,855
$29,542
$186,551
$124,270
$56,727
$537,912
3
$997,860
0
$0
SWD
917
39
23.5
7,471
319
14.62
$40
2
160
$355
$72.00
SWE
$121,922
$57,304
$703,328
$241 ,060
$109,909
$1 ,043,424
2
$2,276,949
0
$0
SWE
1,921
82
23.4
14,492
620
28.36
$40
2
310
$355
$72.00
$0|
A-50
-------
Worksheet No. 21A: Baseline Current Practice (BPT), Existing Sources, California
WBF Upper Bound (10.73%) Analysis for Zero Discharge Wells
(Costs incurred only if WBF wells are projected to fail their toxicity or sheen limits)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
WBF Cuttings, bbl/well (from ODD)
WBDrilling Fluid, bbl/well (from ODD)
DWD
DWD
OWE
OWE
SWD
SWD
SWE
SWE
1,901
8,217
4,376
18,916
1,404
6,067
2,723
1 1 ,769
bbls waste cuttings
bblsWBF discharged
bbls waste cuttings
bbls WBF discharged
bbls waste cuttings
bbls WBF discharged
bbls waste cuttings
bbls WBF discharged
% WBF wells projected to fail toxicity and/or /sheen limitations 1 0.73%
WBF GRIND & INJECT COSTS
Onsite Injection System @ $4280/day
x rental days x CA geographic multiplier
Drilling Fluid Costs
Total Cost / WBF Well (Grind & Inject)
Unit Cost ($/bbl)
No. Wells Fail Limits
No. Wells
TOTAL CA WBF Grind & Inject Costs
Unit Costs
Onsite Inject System
Drilling days
Drilling days Operating Days
Rental Days
Geographic multiplier
WBF Drilling Fluid
bbl WBF Lost to Disposal
Ib/bbl wet cuttings (cuttings + 5% df)
Ib/bbl WBF
Disposal Cost ($8.41 /bbl)
WBDrilling Fluid + Cuttings, bbl/well (from ODD)
DWD
$299,600
$728,496
$1,028,096
$102
0
0
$0
DWD
$4,280
17.5
0.4
43.8
1.6
$45.00
10,118
566
461
$85,123
10,118
OWE
$135,248
$1 ,677,024
$1,812,272
$78
0
0
$0
OWE
$4,280
7.9
0.4
19.8
1.6
$45.00
23,292
$195,957
23,292
SWD
$89,024
$537,912
$626,936
$84
0
1
$0
SWD
$4,280
5.2
0.4
13.0
1.6
$45.00
7,471
$62,855
7,471
SWE
$186,608
$1 ,043,424
$1,230,032
$0
0
1
$0
SWE
$4,280
10.9
0.4
27.3
1.6
$45.00
14,492
$121,922
14,492
$0|
A-51
-------
Worksheet No. 22A: BPT, Existing Sources, Alaska
WBF Upper Bound (10.73%) Analysis for Zero Discharge Wells
(Costs incurred only if WBF wells are projected to fail their toxicity or sheen limits)
WBDrilling Fluid, bbl/day (from ODD)
WBF DISPOSAL ANAL
Onsite Injection System
@ $8560/day
Drilling Fluid Cost
Total Cost / Model Well
Unit Cost ($/bbl)
No. Wells
No. Wells Fail Limts
Onsite Injection System
@ $8560/day
SWD
SWD
SWE
SWE
1 ,404 bbls waste cuttings (0.2% crude contamination)
6,067 bbls WBF discharged
2,723 bbls waste cuttings (0.2% crude contamination)
1 1 ,769 bbls WBF discharged
/SIS
DWD
NA
OWE
NA
SWD
$222,560
$27,302
$249,862
$178
3
0
$0
SWE
$466,520
$52,961
$519,481
$191
1
0
$0
Total Annual Baseline WBF $0
Cook Inlet Cost($)
2x factor for
increased drilling
time for WBF
compared to
OBF/SBF
5.00% adherent fluid
$90.00 /bbl, AK WBF
COM WBF $45.00
AK:GOM multiplier 2
% WBF wells projected to fail toxicity and/or /sheen limitations 1 0.73%
A-52
-------
WORKSHEET 23:
WBF COST ADJUSTMENTS TO BAT 1 AND BAT 2 EXISTING 5
REDUCTION IN RIG TIME-ASSOCIATED COSTS
No. days, SBF interval
WBF-to-SBF drilling efficiency
Estimated days to drill, WBF
Additional days required to drill, WBF
Projected no. WBF > SBF wells (BAT 1 ,2)
Estimated drilling day reductions
Estimated average daily rig cost
Estimated rig-time cost reductions, per well type
Total estimated WBF zero discharge disposal costs, per well type
Estimated days to drill, WBF
Average daily WBF discharge rate, bbl /day
Projected no. WBF > SBF wells (BAT 1 ,2)
Estimated drilling day reductions
Average daily WBF discharge rate, bbl /day
Estimated WBF discharge, bbl
Estimated average WBF cost, per bbl
Estimated WBF discharge costs, per well type
Total estimated WBF zero discharge disposal cost
ZERO DISCHARGE COSTS, WBF WELLS PROJECTED TO FAIL
PERMIT LIMITS AND REQUIRE ZERO DISCHARGE
Projected no. WBF > SBF wells (BAT 1 ,2)
% WBF wells failing permit limits
Estimated WBF wells requiring zero discharge
haul
inject
Estimated zero discharge cost per well
haul
inject
Estimated zero discharge cost per well hauled
Estimated zero discharge cost per well injected
Estimated WBF zero discharge disposal costs, per well type
Total estimated WBF zero discharge disposal costs,
Total estimated WBF cost adjustments
SOURCE
DWD
7.9
0.5
15.8
7.9
1
8
$80,000
$640,000
DWD
15.8
415
1
15.8
415
6,557
$45.00
$295,065
DWD
1
10.73%
0
0
0
$906,022
$543,102
$0
$0
$0
OPTIONS
OWE
17.5
0.5
35.0
17.5
2
35
$80,000
$2,800,000
OWE
35.0
415
2
70
415
29,050
$45.00
$1,307,250
OWE
2
10.73%
0
0
0
$2,724,495
$1,235,566
$0
$0
$0
SWD
5.2
0.5
10.4
5.2
32
166
$80,000
$13,280,000
SWD
10.4
415
32
332.8
415
138,112
$45.00
$6,215,040
SWD
32
10.73%
3
2
1
$627,810
$387,454
$1,255,620
$387,454
$1,643,074
SWE
10.9
0.5
21.8
10.9
19
207
$80,000
$16,560,000
SWE
21.8
415
19
414.2
415
171,893
$45.00
$7,735,185
SWE
19
10.73%
2
2
0
$1,429,659
$768,992
$2,859,318
$0
$2,859,318
Totals
$33,280,000
$15,552,540
$4,502,392
$53,334,932
A-53
-------
WORKSHEET 23A:
WBF COST ADJUSTMENTS TO BAT 1 AND BAT 2 NEW SOURCE OPTIONS
REDUCTION IN RIG TIME-ASSOCIATED COSTS
No. days, SBF interval
WBF-to-SBF drilling efficiency
Estimated days to drill, WBF
Additional days required to drill, WBF
Projected no. WBF > SBF wells (BAT 1 ,2)
Estimated drilling day reductions
Estimated average daily rig cost
Estimated riq-time cost reductions, per well type
Total estimated WBF zero discharge disposal costs, per well type
Estimated days to drill, WBF
Average daily WBF discharge rate, bbl /day
Projected no. WBF > SBF wells (BAT 1 ,2)
Estimated drilling day reductions
Average daily WBF discharge rate, bbl /day
Estimated WBF discharge, bbl
Estimated average WBF cost, per bbl
Estimated WBF discharge costs, per well type
Total estimated WBF zero discharge disposal cost
DWD
7.9
0.5
15.8
7.9
1
8
$80,000
$640,000
DWD
15.8
415
1
15.8
415
6,557
$45.00
$295,065
OWE
17.5
0.5
35.0
17.5
0
0
$80,000
$0
SWD
5.2
0.5
10.4
5.2
2
10
$80,000
$800,000
SWE
10.9
0.5
21.8
10.9
0
0
$80,000
$0
OWE
35.0
415
0
0
415
0
$45.00
$0
SWD
10.4
415
2
20.8
415
8,632
$45.00
$388,440
SWE
21.8
415
0
0
415
0
$45.00
$0
ZERO DISCHARGE COSTS, WBF WELLS PROJECTED TO FAIL
PERMIT LIMITS AND REQUIRE ZERO DISCHARGE
Projected no. WBF > SBF wells (BAT 1 ,2)
% WBF wells failing permit limits
Estimated WBF wells requiring zero discharge
haul
inject
Estimated zero discharge cost per well
haul
inject
Estimated zero discharge cost per well hauled
Estimated zero discharge cost per well injected
Estimated WBF zero discharge disposal costs, per well type
Total estimated WBF zero discharge disposal costs,
DWD
1
10.73%
0
0
0
$906,022
$543,102
$0
$0
$0
OWE
0
10.73%
0
0
0
$2,724,495
$1,235,566
$0
$0
$0
SWD
2
10.73%
0
0
0
$627,810
$387,454
$0
$0
$0
SWE
0
10.73%
0
0
0
$1,429,659
$768,992
$0
$0
$0
Totals
$1,440,000
$683,505
$0
Total estimated WBF cost adjustments
$2,123,505
A-54
-------
APPENDIX VIII-3
(Deleted)
A-55
-------
APPENDIX VIII-4
Pollutant Loadings (Removals) Worksheets
A-56
-------
WORKSHEET No. 1:
Deep Water Development Model Well
BPT Baseline Loadings Model Well: DWD Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 778,050
Whole Drilling Fluid Discharged per Well (bbl) = 533
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
101,357.9
313.0
101,670.9
71,166.2
778,050.0
849,216.2
950,887.1
0.5347
0.2916
0.6917
0.0019
1.5199
0.0783
0.0071
0.4056
0.5053
0.0498
17.0799
1.3308
2.4979
0.9607
0.0783
0.0498
0.0854
14.2688
37.3978
Annual Pollutant
Loadings (Ibs.) per DWD
Model OBF Well
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
BPT Baseline Loadings Model Well: DWD
Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
645.4704
41845.7278
1091.9956
1.0390
6.2270
3.0099
28.2970
3.4063
4.3036
0.0166
5.5936
0.2384
43,635.3
Total Pollutant Loadings * 994,561 .4
Annual Pollutant
Loadings (Ibs.) per DWD
Model OBF Well
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-57
-------
BAT/NSPS Option 1 Loadings Model Well: DWD
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 778,050
Whole Drilling Fluid Discharged per Well (bbl) = 1 80.5
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
34,296.1
105.9
34,402.0
24,080.3
778,050.0
802,130.3
836,532.3
0.1809
0.0987
0.2341
0.0006
0.5143
0.0265
0.0024
0.1373
0.1710
0.0169
5.7793
0.4503
0.8452
0.3251
0.0265
0.0169
0.0289
4.8281
12.6542
Annual Pollutant
Reductions (Ibs.) per
DWD Model SBF Well
[BPT Load-Option Load]
67,061 .8
207.1
67,268.9
47,085.9
0.0
47,085.9
114,354.8
0.3537
0.1930
0.4576
0.0012
1.0056
0.0518
0.0047
0.2684
0.3343
0.0330
1 1 .3006
0.8805
1.6527
0.6357
0.0518
0.0330
0.0565
9.4407
24.7437
Annual Pollutant
Reductions (Ibs.) per
DWD Model OBF Well
[BPT Load-Option
Load!
(34,296.1)
(105.9)
(34,402.0)
(24,080.3)
(778,050.0)
(802,130.3)
(836,532.3)
(0.1809)
(0.0987)
(0.2341)
(0.0006)
(0.5143)
(0.0265)
(0.0024)
(0.1373)
(0.1710)
(0.0169)
(5.7793)
(0.4503)
(0.8452)
(0.3251)
(0.0265)
(0.0169)
(0.0289)
(4.8281)
(12.6542)
BAT/NSPS Option 1 Loadings Model Well: DWD
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
218.4055
14159.1918
369.4947
0.3516
2.1070
1.0185
9.5756
1.1527
1 .4563
0.0056
1.8928
0.0807
14,764.7
Total Pollutant Loadings * 851 ,31 0.2
Annual Pollutant
Reductions (Ibs.) per
DWD Model SBF Well
[BPT Load-Option Load]
427.0648
27,686.5360
722.5009
0.6875
4.1200
1.9914
18.7214
2.2536
2.8473
0.0110
3.7007
0.1577
28,870.6
143,251.2
Annual Pollutant
Reductions (Ibs.) per
DWD Model OBF Well
[BPT Load-Option
Load!
(218.4055)
(14,159.1918)
(369.4947)
(0.3516)
(2.1070)
(1.0185)
(9.5756)
(1.1527)
(1 .4563)
(0.0056)
(1 .8928)
(0.0807)
(14,764.7)
(851,310.2)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-58
-------
BAT/NSPS Option 2 Loadings Model Well: DWD
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 758,397
Whole Drilling Fluid Discharged per Well (bbl) = 1 65.9
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
31 ,533.7
97.4
31,631.1
22,140.7
758,396.9
780,537.6
812,168.6
0.1663
0.0907
0.2151
0.0006
0.4727
0.0244
0.0022
0.1262
0.1572
0.0155
5.3138
0.4140
0.7771
0.2989
0.0244
0.0155
0.0266
4.4392
11.6349
Annual Pollutant
Reductions (Ibs.) per
DWD Model SBF Well
[BPT Load-Option Load]
69,824.2
215.6
70,039.8
49,025.5
19,653.1
68,678.7
138,718.5
0.3684
0.2009
0.4766
0.0013
1.0472
0.0539
0.0049
0.2794
0.3481
0.0343
11.7661
0.9168
1 .7208
0.6618
0.0539
0.0343
0.0588
9.8296
25.8
Annual Pollutant
Reductions (Ibs.) per
DWD Model OBF Well
[BPT Load-Option
Load!
(31 ,533.7)
(97.4)
(31,631.1)
(22,140.7)
(758,396.9)
(780,537.6)
(812,168.6)
(0.1663)
(0.0907)
(0.2151)
(0.0006)
(0.4727)
(0.0244)
(0.0022)
(0.1262)
(0.1572)
(0.0155)
(5.3138)
(0.4140)
(0.7771)
(0.2989)
(0.0244)
(0.0155)
(0.0266)
(4.4392)
(11.6349)
BAT/NSPS Option 2 Loadings Model Well: DWD
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
200.8139
13018.7269
339.7334
0.3233
1 .9373
0.9362
8.8010
1.0594
1 .3385
0.0052
1.7397
0.0741
13575.5
Total Pollutant Loadings * 825,756.2
Annual Pollutant
Reductions (Ibs.) per
DWD Model SBF Well
[BPT Load-Option Load]
444.6565
28,827.0009
752.2622
0.7158
4.2897
2.0738
19.4959
2.3468
2.9651
0.0114
3.8538
0.1642
30,059.8
168,805.1
Annual Pollutant
Reductions (Ibs.) per
DWD Model OBF Well
[BPT Load-Option
Load!
(200.8139)
(13,018.7269)
(339.7334)
(0.3233)
(1 .9373)
(0.9362)
(8.8010)
(1 .0594)
(1 .3385)
(0.0052)
(1 .7397)
(0.0741)
(13,575.5)
(825,756.2)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-59
-------
Zero Discharge Option Model Well: DWD
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Dry Cuttings Generated per Well (Ibs) = 778,050
Whole Drilling Fluid Discharged per Well (bbl) = 533.4
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Annual Pollutant
Reductions (Ibs.) per
DWD Model SBF Well
[BPT Load-Option Load]
101,357.9
313.0
101,670.9
71,166.2
778,050.0
849,216.2
950,887.1
0.5347
0.2916
0.6917
0.0019
1.5199
0.0783
0.0071
0.4056
0.5053
0.0498
1 7.0799
1.3308
2.4979
0.9607
0.0783
0.0498
0.0854
14.2688
37.4
Annual Pollutant
Reductions (Ibs.) per
DWD Model OBF Well
[BPT Load-Option
Load!
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Zero Discharge Option Model Well: DWD
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWD Model SBF Well
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Total Pollutant Loadings * 0.0
Annual Pollutant
Reductions (Ibs.) per
DWD Model SBF Well
[BPT Load-Option Load]
645.4704
41,845.7278
1 ,091 .9956
1.0390
6.2270
3.0099
28.2970
3.4063
4.3036
0.0166
5.5936
0.2384
43,635.3
994,561 .4
Annual Pollutant
Reductions (Ibs.) per
DWD Model OBF Well
[BPT Load-Option
Load!
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-60
-------
WORKSHEET No. 2:
Deep Water Exploratory Model Well
BPT Baseline Loadings
Model Well:
OWE
Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) =
Whole Drilling Fluid Discharged per Well (bbl) =
1,729,910
1186
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
225,358.4
695.9
226,054.3
158,230.4
1,729,910.0
1,888,140.4
2,114,194.6
1.1887
0.6484
1.5379
0.0042
3.3792
0.1741
0.0158
0.9019
1.1234
0.1108
37.9753
2.9589
5.5539
2.1361
0.1741
0.1108
0.1899
31.7252
83.1501
Annual Pollutant
Loadings (Ibs.) per DWE
Model OBF Well
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
BPT Baseline Loadings
Model Well:
DWE
Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
1435.1335
93039.4487
2427.9340
2.3102
13.8452
6.6919
62.9122
7.5731
9.5682
0.0369
12.4361
0.5300
97,018.4
Total Pollutant Loadings * 2,21 1 ,299.6
Annual Pollutant
Loadings (Ibs.) per DWE
Model OBF Well
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-61
-------
BAT/NSPS Option 1 Loadings Model Well: DWE
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 1 ,729,91 0
Whole Drilling Fluid Discharged per Well (bbl) = 401 .3
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
76,253.7
235.5
76,489.2
53,539.8
1,729,910.0
1 ,783,449.8
1 ,859,939.0
0.4023
0.2194
0.5204
0.0014
1.1435
0.0589
0.0054
0.3052
0.3801
0.0375
12.8496
1.0012
1.8792
0.7228
0.0589
0.0375
0.0642
10.7347
28.1352
Annual Pollutant
Reductions (Ibs.) per
DWE Model SBF Well
[BPT Load-Option Load]
149,104.7
460.4
149,565.1
104,690.5
0.0
104,690.5
254,255.6
0.7865
0.4290
1.0175
0.0028
2.2357
0.1152
0.0105
0.5967
0.7433
0.0733
25.1257
1.9577
3.6746
1.4133
0.1152
0.0733
0.1256
20.9904
55.0149
Annual Pollutant
Reductions (Ibs.) per DWE
Model DBF Well [BPT
Load-Option Load]
(76,253.7)
(235.5)
(76,489.2)
(53,539.8)
(1,729,910.0)
(1 ,783,449.8)
(1 ,859,939.0)
(0.4023)
(0.2194)
(0.5204)
(0.0014)
(1.1435)
(0.0589)
(0.0054)
(0.3052)
(0.3801)
(0.0375)
(12.8496)
(1.0012)
(1 .8792)
(0.7228)
(0.0589)
(0.0375)
(0.0642)
(10.7347)
(28.1352)
BAT/NSPS Option 1 Loadings Model Well: DWE
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
485.601 1
31481.4312
821.5315
0.7817
4.6847
2.2645
21.2890
2.5627
3.2378
0.0125
4.2083
0.1793
32,827.8
Total Pollutant Loadings * 1 ,892,796.1
Annual Pollutant
Reductions (Ibs.) per
DWE Model SBF Well
[BPT Load-Option Load]
949.5324
61,558.0175
1 ,606.4025
1.5285
9.1604
4.4274
41 .6232
5.0104
6.3304
0.0244
8.2278
0.3506
64,190.6
318,503.5
Annual Pollutant
Reductions (Ibs.) per DWE
Model DBF Well [BPT
Load-Option Load]
(485.6011)
(31,481.4312)
(821.5315)
(0.7817)
(4.6847)
(2.2645)
(21 .2890)
(2.5627)
(3.2378)
(0.0125)
(4.2083)
(0.1793)
(32,827.8)
(1,892,796.1)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-62
-------
BAT/NSPS Option 2 Loadings Model Well: DWE
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 1 ,686,21 3
Whole Drilling Fluid Discharged per Well (bbl) = 368.9
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
70,111.8
216.5
70,328.3
49,227.4
1,686,213.4
1 ,735,440.8
1,805,769.1
0.3698
0.2017
0.4784
0.0013
1.0512
0.0542
0.0049
0.2806
0.3495
0.0345
11.8146
0.9206
1.7279
0.6646
0.0542
0.0345
0.0591
9.8701
25.8690
Annual Pollutant
Reductions (Ibs.) per
DWE Model SBF Well
[BPT Load-Option Load]
155,246.6
479.4
155,726.0
109,002.9
43,696.6
152,699.6
308,425.5
0.8190
0.4467
1 .0595
0.0029
2.3280
0.1199
0.0109
0.6213
0.7739
0.0763
26.1607
2.0384
3.8260
1.4715
0.1199
0.0763
0.1308
21.8551
57.3
Annual Pollutant
Reductions (Ibs.) per DWE
Model OBF Well [BPT
Load-Option Load]
(70,111.8)
(216.5)
(70,328.3)
(49,227.4)
(1,686,213.4)
(1 ,735,440.8)
(1,805,769.1)
(0.3698)
(0.201 7)
(0.4784)
(0.0013)
(1.0512)
(0.0542)
(0.0049)
(0.2806)
(0.3495)
(0.0345)
(11.8146)
(0.9206)
(1 .7279)
(0.6646)
(0.0542)
(0.0345)
(0.0591)
(9.8701)
(25.8690)
BAT/NSPS Option 2 Loadings Model Well: DWE
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
446.4879
28945.7308
755.3605
0.7187
4.3074
2.0817
19.5702
2.3558
2.9764
0.0115
3.8685
0.1649
30183.6
Total Pollutant Loadings * 1 ,835,979.7
Annual Pollutant
Reductions (Ibs.) per
DWE Model SBF Well
[BPT Load-Option Load]
988.6456
64,093.7179
1,672.5735
1.5914
9.5378
4.6102
43.3420
5.2173
6.5918
0.0254
8.5676
0.3651
66,834.8
375,319.9
Annual Pollutant
Reductions (Ibs.) per DWE
Model OBF Well [BPT
Load-Option Load]
(446.4879)
(28,945.7308)
(755.3605)
(0.7187)
(4.3074)
(2.0817)
(19.5702)
(2.3558)
(2.9764)
(0.0115)
(3.8685)
(0.1649)
(30,183.6)
(1 ,835,979.7)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-63
-------
Zero Discharge Option Model Well: DWE
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Dry Cuttings Generated per Well (Ibs) = 1 ,729,91 0
Whole Drilling Fluid Discharged per Well (bbl) = 1 1 85.9
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Annual Pollutant
Reductions (Ibs.) per
DWE Model SBF Well
[BPT Load-Option Load]
225,358.4
695.9
226,054.3
158,230.4
1,729,910.0
1,888,140.4
2,114,194.6
1.1887
0.6484
1 .5379
0.0042
3.3792
0.1741
0.0158
0.9019
1.1234
0.1108
37.9753
2.9589
5.5539
2.1361
0.1741
0.1108
0.1899
31.7252
83.2
Annual Pollutant
Reductions (Ibs.) per DWE
Model DBF Well [BPT
Load-Option Load]
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Zero Discharge Option Model Well: DWE
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
DWE Model SBF Well
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Total Pollutant Loadings * 0.0
Annual Pollutant
Reductions (Ibs.) per
DWE Model SBF Well
[BPT Load-Option Load]
1,435.1335
93,039.4487
2,427.9340
2.3102
13.8452
6.6919
62.9122
7.5731
9.5682
0.0369
12.4361
0.5300
97,018.4
2,211,299.6
Annual Pollutant
Reductions (Ibs.) per DWE
Model DBF Well [BPT
Load-Option Load]
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-64
-------
WORKSHEET No. 3:
Shallow Water Development Model Well
BPT Baseline Loadings Model Well: SWD Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 514,150
Whole Drilling Fluid Discharged per Well (bbl) = 353
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
66,979.2
206.8
67,186.0
47,028.0
514,150.0
561,178.0
628,364.0
0.3533
0.1927
0.4571
0.0012
1.0045
0.0517
0.0047
0.2681
0.3339
0.0329
11.2867
0.8794
1.6507
0.6349
0.0517
0.0329
0.0564
9.4291
24. 71
Annual Pollutant
Loadings (Ibs.) per SWD
Model OBF Well
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
BPT Baseline Loadings Model Well: SWD
Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
426.5
27,652
721.6
0.6866
4.1149
1 .9891
18.7002
2.2510
2.8441
0.0110
3.6965
0.1575
28,835
Total Pollutant Loadings * 628,364
Annual Pollutant
Loadings (Ibs.) per SWD
Model OBF Well
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-65
-------
BAT/NSPS Option 1 Loadings Model Well: SWD
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 514,150
Whole Drilling Fluid Discharged per Well (bbl) = 1 19.3
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this value
used in subsequent eng./nwqi/ea/econ.
modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
22,663.5
70.0
22,733.5
15,912.7
514,150.0
530,062.7
552,796.2
0.1196
0.0652
0.1547
0.0004
0.3399
0.0175
0.0016
0.0907
0.1130
0.0111
3.8190
0.2976
0.5585
0.2148
0.0175
0.0111
0.0191
3.1905
8.3621
Annual Pollutant
Reductions (Ibs.) per
SWD Model SBF Well
[BPT Load-Option Load]
44,315.7
136.8
44,452.5
31,115.3
0.0
31,115.3
75,567.8
0.2338
0.1275
0.3024
0.0008
0.6645
0.0342
0.0031
0.1774
0.2209
0.0218
7.4677
0.5819
1.0921
0.4201
0.0342
0.0218
0.0373
6.2386
16.3511
Annual Pollutant
Reductions (Ibs.) per
SWD Model OBF Well
[BPT Load-Option
Load!
(22,663.5)
(70.0)
(22,733.5)
(15,912.7)
(514,150.0)
(530,062.7)
(552,796.2)
(0.1196)
(0.0652)
(0.1547)
(0.0004)
(0.3399)
(0.0175)
(0.0016)
(0.0907)
(0.1130)
(0.0111)
(3.8190)
(0.2976)
(0.5585)
(0.2148)
(0.0175)
(0.0111)
(0.0191)
(3.1905)
(8.3621)
BAT/NSPS Option 1 Loadings Model Well: SWD
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
144.3265
9356.6589
244.1690
0.2323
1.3924
0.6732
6.3289
0.7618
0.9625
0.0037
1.2511
0.0533
9,756.8
Total Pollutant Loadings * 552,796.2
Annual Pollutant
Reductions (Ibs.) per
SWD Model SBF Well
[BPT Load-Option Load]
282.2124
18,295.7811
477.4421
0.4543
2.7226
1.3159
12.3713
1.4892
1.8815
0.0073
2.4455
0.1042
19,078.2
94,663.1
Annual Pollutant
Reductions (Ibs.) per
SWD Model OBF Well
[BPT Load-Option
Load!
(144.3265)
(9,356.6589)
(244.1690)
(0.2323)
(1 .3924)
(0.6732)
(6.3289)
(0.7618)
(0.9625)
(0.0037)
(1.2511)
(0.0533)
(9,756.8)
(562,561.7)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-66
-------
BAT/NSPS Option 2 Loadings Model Well: SWD
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 501 ,163
Whole Drilling Fluid Discharged per Well (bbl) = 1 09.7
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this value
used in subsequent eng./nwqi/ea/econ.
modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
20,838.1
64.3
20,902.4
14,631.0
501,162.8
515,793.8
536,696.2
0.1100
0.0600
0.1423
0.0004
0.3126
0.0161
0.0015
0.0834
0.1039
0.0102
3.5114
0.2736
0.5135
0.1975
0.0161
0.0102
0.0176
2.9335
7.6886
Annual Pollutant
Reductions (Ibs.) per
SWD Model SBF Well
[BPT Load-Option Load]
46,141.1
142.5
46,283.6
32,397.0
12,987.2
45,384.1
91 ,667.8
0.2434
0.1328
0.3149
0.0009
0.6919
0.0356
0.0032
0.1847
0.2300
0.0227
7.7753
0.6058
1.1371
0.4374
0.0356
0.0227
0.0389
6.4956
17.0
Annual Pollutant
Reductions (Ibs.) per
SWD Model OBF Well
[BPT Load-Option
Load!
(20,838.1)
(64.3)
(20,902.4)
(14,631.0)
(501,162.8)
(515,793.8)
(536,696.2)
(0.1100)
(0.0600)
(0.1423)
(0.0004)
(0.3126)
(0.0161)
(0.0015)
(0.0834)
(0.1039)
(0.0102)
(3.5114)
(0.2736)
(0.5135)
(0.1975)
(0.0161)
(0.0102)
(0.0176)
(2.9335)
(7.6886)
BAT/NSPS Option 2 Loadings Model Well: SWD
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
132.7016
8603.0184
224.5022
0.2136
1 .2802
0.6190
5.8196
0.7005
0.8851
0.0034
1.1504
0.0490
8970.9
Total Pollutant Loadings * 545,675.2
Annual Pollutant
Reductions (Ibs.) per
SWD Model SBF Well
[BPT Load-Option Load]
293.8373
19,049.4217
497.1089
0.4730
2.8347
1.3701
12.8806
1.5505
1 .9590
0.0076
2.5462
0.1085
19,864.1
1 1 1 ,549.6
Annual Pollutant
Reductions (Ibs.) per
SWD Model OBF Well
[BPT Load-Option
Load!
(132.7016)
(8,603.0184)
(224.5022)
(0.2136)
(1 .2802)
(0.6190)
(5.8196)
(0.7005)
(0.8851)
(0.0034)
(1.1504)
(0.0490)
(8,970.9)
(545,675.2)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-67
-------
Zero Discharge Option Model Well: SWD
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Dry Cuttings Generated per Well (Ibs) = 514,150
Whole Drilling Fluid Discharged per Well (bbl) = 352.5
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this value
used in subsequent eng./nwqi/ea/econ.
modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Annual Pollutant
Reductions (Ibs.) per
SWD Model SBF Well
[BPT Load-Option Load]
66,979.2
206.8
67,186.0
47,028.0
514,150.0
561,178.0
628,364.0
0.3533
0.1927
0.4571
0.0012
1.0045
0.0517
0.0047
0.2681
0.3339
0.0329
1 1 .2867
0.8794
1.6507
0.6349
0.0517
0.0329
0.0564
9.4291
24.7
Annual Pollutant
Reductions (Ibs.) per
SWD Model OBF Well
[BPT Load-Option
Load!
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Zero Discharge Option Model Well: SWD
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWD Model SBF Well
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Total Pollutant Loadings * 0.0
Annual Pollutant
Reductions (Ibs.) per
SWD Model SBF Well
[BPT Load-Option Load]
426.5389
27,652.4400
721.6111
0.6866
4.1149
1 .9891
18.7002
2.2510
2.8441
0.0110
3.6965
0.1575
28,835.0
657,224.8
Annual Pollutant
Reductions (Ibs.) per
SWD Model OBF Well
[BPT Load-Option
Load!
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-68
-------
WORKSHEET No. 4:
Shallow Water Exploratory Model Well
BPT Baseline Loadings
Model Well:
SWE
Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) =
Whole Drilling Fluid Discharged per Well (bbl) =
1,077,440
739
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
140,360.0
433.4
140,793.4
98,550.6
1 ,077,440.0
1,175,990.6
1,316,784.0
0.7404
0.4038
0.9578
0.0026
2.1046
0.1084
0.0099
0.5617
0.6997
0.0690
23.6522
1 .8429
3.4591
1 .3304
0.1084
0.0690
0.1183
19.7594
51.7884
Annual Pollutant
Loadings (Ibs.) per SWE
Model OBF Well
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
BPT Baseline Loadings
Model Well:
SWE
Existing Sources
Technology = Discharge Assuming 10.20% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
893.8443
57947.7681
1512.1904
1 .4388
8.6232
4.1678
39.1829
4.7166
5.9592
0.0230
7.7454
0.3301
60,426.0
Total Pollutant Loadings * 1 ,377,263.9
Annual Pollutant
Loadings (Ibs.) per SWE
Model OBF Well
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-69
-------
BAT/NSPS Option 1 Loadings Model Well: SWE
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 1 ,077,440
Whole Drilling Fluid Discharged per Well (bbl) = 249.9
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
47,493.1
146.7
47,639.8
33,346.2
1 ,077,440.0
1,110,786.2
1,158,426.0
0.2505
0.1366
0.3241
0.0009
0.7121
0.0367
0.0033
0.1901
0.2368
0.0233
8.0031
0.6236
1.1705
0.4502
0.0367
0.0233
0.0400
6.6859
1 7.5234
Annual Pollutant
Reductions (Ibs.) per
SWE Model SBF Well
[BPT Load-Option Load]
92,866.9
286.8
93,153.6
65,204.4
0.0
65,204.4
158,358.0
0.4899
0.2672
0.6338
0.0017
1.3926
0.0717
0.0065
0.3717
0.4630
0.0456
15.6491
1.2193
2.2887
0.8803
0.0717
0.0456
0.0782
13.0735
34.2649
Annual Pollutant
Reductions (Ibs.) per SWE
Model DBF Well [BPT
Load -Option Load]
(47,493.1)
(146.7)
(47,639.8)
(33,346.2)
(1 ,077,440.0)
(1,110,786.2)
(1,158,426.0)
(0.2505)
(0.1366)
(0.3241)
(0.0009)
(0.7121)
(0.0367)
(0.0033)
(0.1901)
(0.2368)
(0.0233)
(8.0031)
(0.6236)
(1.1705)
(0.4502)
(0.0367)
(0.0233)
(0.0400)
(6.6859)
(17.5234)
BAT/NSPS Option 1 Loadings Model Well: SWE
Existing Sources
Technology = Discharge Assuming 4.03% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
302.4470
19607.5826
51 1 .6745
0.4869
2.9178
1.4102
13.2572
1.5958
2.0163
0.0078
2.6206
0.1117
20,446.1
Total Pollutant Loadings * 1 ,178,890.4
Annual Pollutant
Reductions (Ibs.) per
SWE Model SBF Well
[BPT Load-Option Load]
591.3974
38,340.1855
1,000.5158
0.9520
5.7054
2.7577
25.9256
3.1208
3.9430
0.0152
5.1248
0.2184
39,979.9
198,373.6
Annual Pollutant
Reductions (Ibs.) per SWE
Model DBF Well [BPT
Load -Option Load]
(302.4470)
(19,607.5826)
(51 1 .6745)
(0.4869)
(2.9178)
(1.4102)
(13.2572)
(1 .5958)
(2.0163)
(0.0078)
(2.6206)
(0.1117)
(20,446.1)
(1,178,890.4)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-70
-------
BAT/NSPS Option 2 Loadings Model Well: SWE
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Dry Cuttings Generated per Well (Ibs) = 1 ,050,224
Whole Drilling Fluid Discharged per Well (bbl) = 229.8
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
43,667.7
134.8
43,802.6
30,660.3
1 ,050,224.4
1 ,080,884.7
1,124,687.3
0.2304
0.1256
0.2980
0.0008
0.6548
0.0337
0.0031
0.1748
0.2177
0.0215
7.3585
0.5733
1 .0762
0.4139
0.0337
0.0215
0.0368
6.1474
16.1120
Annual Pollutant
Reductions (Ibs.) per
SWE Model SBF Well
[BPT Load-Option Load]
96,692.2
298.6
96,990.8
67,890.3
27,215.6
95,105.9
192,096.7
0.5100
0.2782
0.6598
0.0018
1.4498
0.0747
0.0068
0.3870
0.4820
0.0475
16.2937
1.2695
2.3829
0.9165
0.0747
0.0475
0.0815
13.6120
35.7
Annual Pollutant
Reductions (Ibs.) per SWE
Model OBF Well [BPT
Load -Option Load]
(43,667.7)
(134.8)
(43,802.6)
(30,660.3)
(1 ,050,224.4)
(1 ,080,884.7)
(1,124,687.3)
(0.2304)
(0.1256)
(0.2980)
(0.0008)
(0.6548)
(0.0337)
(0.0031)
(0.1748)
(0.2177)
(0.0215)
(7.3585)
(0.5733)
(1 .0762)
(0.4139)
(0.0337)
(0.0215)
(0.0368)
(6.1474)
(16.1120)
BAT/NSPS Option 2 Loadings Model Well: SWE
Existing Sources
Technology = Discharge Assuming 3.82% (wt) Retention on Discharged Cuttings and
0.2% (vol.) Crude Contamination
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
278.0861
18028.2721
470.4613
0.4476
2.6828
1 .2967
12.1909
1.4675
1 .8541
0.0071
2.4098
0.1027
18799.3
Total Pollutant Loadings * 1 ,143,503.4
Annual Pollutant
Reductions (Ibs.) per
SWE Model SBF Well
[BPT Load-Option Load]
615.7582
39,919.4960
1,041.7291
0.9912
5.9404
2.8711
26.9919
3.2492
4.1051
0.0158
5.3356
0.2274
41 ,626.7
233,760.5
Annual Pollutant
Reductions (Ibs.) per SWE
Model OBF Well [BPT
Load -Option Load]
(278.0861)
(18,028.2721)
(470.4613)
(0.4476)
(2.6828)
(1 .2967)
(12.1909)
(1 .4675)
(1.8541)
(0.0071)
(2.4098)
(0.1027)
(18,799.3)
(1,143,503.4)
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-71
-------
Zero Discharge Option Model Well: SWE
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Dry Cuttings Generated per Well (Ibs) = 1 ,077,440
Whole Drilling Fluid Discharged per Well (bbl) = 738.6
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS (associated with discharged SBF)
TSS (associated with dry cuttings)
TSS (total)
Total Conventional Pollutants (this
value used in subsequent
eng./nwqi/ea/econ. modeling)
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol
Total Organic Priority Pollutants
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total Metals Priority Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Annual Pollutant
Reductions (Ibs.) per
SWE Model SBF Well
[BPT Load-Option Load]
140,360.0
433.4
140,793.4
98,550.6
1 ,077,440.0
1,175,990.6
1,316,784.0
0.7404
0.4038
0.9578
0.0026
2.1046
0.1084
0.0099
0.5617
0.6997
0.0690
23.6522
1.8429
3.4591
1 .3304
0.1084
0.0690
0.1183
19.7594
51.8
Annual Pollutant
Reductions (Ibs.) per SWE
Model DBF Well [BPT
Load -Option Load]
0
0
0
0
0
0
0.0
0
0
0
0
0.0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Zero Discharge Option Model Well: SWE
Existing Sources
Technology = Zero Discharge of All Cuttings Wastes (assuming 10.20% (wt) retention on zero discharged cuttings)
Pollutant Name
Non-Conventional Pollutants
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols
Total biphenyls
Total dibenzothiophenes
Total Non-Conventional Pollutants
Annual Pollutant
Loadings (Ibs.) per
SWE Model SBF Well
0
0
0
0
0
0
0
0
0
0
0
0
0.0
Total Pollutant Loadings * 0.0
Annual Pollutant
Reductions (Ibs.) per
SWE Model SBF Well
[BPT Load-Option Load]
893.8443
57,947.7681
1,512.1904
1.4388
8.6232
4.1678
39.1829
4.7166
5.9592
0.0230
7.7454
0.3301
60,426.0
1 ,377,263.9
Annual Pollutant
Reductions (Ibs.) per SWE
Model DBF Well [BPT
Load -Option Load]
0
0
0
0
0
0
0
0
0
0
0
0
0.0
0.0
* Sum Total of Conventional, Priority, and Non-Conventional Pollutants
A-72
-------
WORKSHEETS:
Gulf of Mexico:
Zero Discharge Summary, Existing Sources
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Baseline: Zero Discharge
Shallow Water (<
Development
86
628,364
54,039,305
0
0
0
42
628,364
26,391,288
5,278,258
21,113,031
1 ,000 ft) Deep Water (>1 ,000 ft)
Exploratory Development Exploratory Total
51
1,316,784
67,155,986
0
0
0
25
1,316,784
32,919,601
6,583,920
26,335,681
16
950,887
15,214,194
0
0
0
0
950,887
0
0
0
48
2,114,195
101,481,343
0
0
0
0
2,114,195
0
0
0
201
237,890,828
0
0
0
67
59,310,889
11,862,178
47,448,711
86 51 16 48 202
2,125 1,260 395 1,186 4,967
2,212 1,312 411 1,234 5,169
2,479,814 1,470,587 461,361 1,384,082 5,795,843
BAT 1 : Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
124
552,796
68,546,728
0
0
0
25
628,364
15,709,100
3,141,820
12,567,280
Exploratory
74
1,158,426
85,723,524
0
0
0
15
1,316,784
19,751,761
3,950,352
15,801,409
Development
17
836,532
14,221,049
0
0
0
0
950,887
0
0
0
Exploratory
49
1 ,859,939
91,137,013
0
0
0
0
2,114,195
0
0
0
Total
264
259,628,314
0
0
0
40
35,460,861
7,092,172
28,368,689
Total Toxic Organics Discharge 42 25 6 17 90
Total Toxic Metals Discharge 1,037 619 142 410 2,208
Total Toxics Discharge 1,079 644 148 426 2,297
Total Non-conventionals Discharge 1,209,845 722,004 165,866 478,084 2,575,799
A-73
-------
(Gulf of Mexico)
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings, Discharge
Onsite Injection (0%S: 0%D)
Onshore Disposal (100%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
BAT 2: Onshore Disposal
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
124
16,100
1 ,996,395
66,550,333
0
1 ,996,395
25
628,364
15,709,100
3,141,820
12,567,280
Exploratory
74
33,739
2,496,661
83,226,863
0
2,496,661
15
1,316,784
19,751,761
3,950,352
15,801,409
Development
17
24,364
414,182
13,806,867
0
414,182
0
950,887
0
0
0
Exploratory
49
54,170
2,654,327
88,482,686
0
2,654,327
0
2,114,195
0
0
0
Total
264
7,561,565
252,066,749
0
7,561,565
40
35,460,861
7,092,172
28,368,689
38.76 23 5 15 83
953 569 131 377 2,030
992 592 136 392 2,112
1,112,397 663,850 152,506 439,576 2,368,329
BAT 3: Onshore Disposal
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
0
628,364
0
0
0
128
628,364
80,430,593
16,086,119
64,344,474
Exploratory
0
1,316,784
0
0
0
76
1,316,784
100,075,587
20,015,117
80,060,470
Development
3
950,887
0
2,852,661
0
2,852,661
8
950,887
7,607,097
0
7,607,097
Exploratory
8
2,114,195
0
16,913,557
0
16,913,557
25
2,114,195
52,854,866
0
52,854,866
Total
11
0
19,766,219
0
19,766,219
237
240,968,143
36,101,236
204,866,907
Total SBF+OBFZero Discharge Loadings:
Total Zero Disharge Injection Loadings 16,086,119 20,015,117 0 0 36,101,236
Total Zero Discharge Onshore Loadings 64,344,474 80,060,470 10,459,758 69,768,423 224,633,126
A-74
-------
WORKSHEETS:
California : Zero Discharge Summary, Existing Sources
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
Baseline: Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
628,364
0
0
0
0
1
628,364
628,364
628,364
0
0
1,316,784
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
0
950,887
0
0
0
0
0
950,887
0
0
0
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
2
1,945,148
1,945,148
0
0 0000
0 0000
0 0000
0 0000
BAT 1 : Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
0
552,796
0
0
0
0
1
628,364
628,364
628,364
0
Exploratory
0
1,158,426
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
Development
0
836,532
0
0
0
0
0
950,887
0
0
0
Exploratory
0
1 ,859,939
0
0
0
0
0
2,114,195
0
0
0
Total
0
0
0
0
0
2
1,945,148
1,945,148
0
Total Toxic Organics Discharge 0 0000
Total Toxic Metals Discharge 0 0000
Total Toxics Discharge 0 0000
Total Non-conventionals Discharge 0 0000
A-75
-------
California
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings, Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
BAT 2: Onshore Disposal
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
0
16,100
0
0
0
0
1
628,364
628,364
628,364
0
Exploratory
0
33,739
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
Development
0
24,364
0
0
0
0
0
950,887
0
0
0
Exploratory
0
54,170
0
0
0
0
0
2,114,195
0
0
0
Total
0
0
0
0
0
2
1,945,148
1,945,148
0
0.00 0000
0 0000
0 0000
0 0000
BAT 3: Onshore Disposal
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
0
628,364
0
0
0
0
1
628,364
628,364
628,364
0
Exploratory
0
1,316,784
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
Development
0
950,887
0
0
0
0
0
950,887
0
0
0
Exploratory
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
Total
0
0
0
0
0
2
1,945,148
1,945,148
0
Total SBF+OBFZero Discharge Loadings:
Total Zero Disharge Injection Loadings 628,364 1,316,784 0 0 1,945,148
Total Zero Discharge Onshore Loadings 0 0000
A-76
-------
WORKSHEET?:
Alaska : Zero Discharge Summary, Existing Sources
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
Baseline: Zero Discharge Loadings
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
628,364
0
0
0
0
1
628,364
628,364
628,364
0
0
1,316,784
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
0
950,887
0
0
0
0
0
950,887
0
0
0
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
2
1,945,148
1,945,148
0
0 0000
0 0000
0 0000
0 0000
BAT 1: Zero Discharge Loadings
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
1
552,796
552,796
0
0
0
0
628,364
0
0
0
Exploratory
0
1,158,426
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
Development
0
836,532
0
0
0
0
0
950,887
0
0
0
Exploratory
0
1 ,859,939
0
0
0
0
0
2,114,195
0
0
0
Total
1
552,796
0
0
1
1,316,784
1,316,784
0
Total Toxic Organics Discharge 0 0000
Total Toxic Metals Discharge 8 0008
Total Toxics Discharge 9 0009
Total Non-conventionals Discharge 9,757 000 9,757
A-77
-------
Alaska
Onshore Disposal
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings, Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
BAT 2: Onshore Disposal
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
1
16,100
16,100
536,696
16,100
0
0
628,364
0
0
0
Exploratory
0
33,739
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
Development
0
24,364
0
0
0
0
0
950,887
0
0
0
Exploratory
0
54,170
0
0
0
0
0
2,114,195
0
0
0
Total
1
16,100
536,696
16,100
0
1
1,316,784
1,316,784
0
0.31 0000
8 0008
8 0008
8,971 000 8,971
BAT 3: Onshore Disposal
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development
0
628,364
0
0
0
0
1
628,364
628,364
628,364
0
Exploratory
0
1,316,784
0
0
0
0
1
1,316,784
1,316,784
1,316,784
0
Development
0
950,887
0
0
0
0
0
950,887
0
0
0
Exploratory
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
Total
0
0
0
0
0
2
1,945,148
1,945,148
0
Total SBF+OBFZero Discharge Loadings:
Total Zero Disharge Injection Loadings 628,364 1,316,784 0 0 1,945,148
Total Zero Discharge Onshore Loadings 0 0000
A-78
-------
WORKSHEETS:
Gulf of Mexico:
Zero Discharge Summary, New Sources
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Wells, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Wells, Zero Discharge
Onsite Injection (20%S:0%D)
Haul/Onshore Disposal (80%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S:0%D)
Haul/Onshore Disposal (80%S:100%D)
Baseline: Zero Discharge Loadings
ShallowWa
Development
5
628,364
3,141,820
0
0
0
2
628,364
1,256,728
0
1,256,728
er (<1 ,000 ft) Deep Water (>1 ,000 ft)
Exploratory Development Exploratory Total
0
1,316,784
0
0
0
0
0
1,316,784
0
0
0
15
950,887
14,263,307
0
0
0
0
950,887
0
0
0
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
20
17,405,127
0
0
0
2
1,256,728
0
1,256,728
5 0 15 0 20
124 0 371 0 494
129 0 386 0 514
144,175 0 432,526 0 576,701
NSPS 1 : Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
8
552,796
4,422,370
0
0
0
1
628,364
628,364
0
628,364
0
1,158,426
0
0
0
0
0
1,316,784
0
0
0
16
836,532
13,384,517
0
0
0
0
950,887
0
0
0
0
1 ,859,939
0
0
0
0
0
2,114,195
0
0
0
24
17,806,886
0
0
0
1
628,364
0
628,364
Total Toxic Organics Discharge 3 0508
Total Toxic Metals Discharge 67 0 134 0 201
Total Toxics Discharge 70 0 1 39 0 209
Total Non-conventionals Discharge 78,055 0 156,109 0 234,164
A-79
-------
Gulf of Mexico NSPS 2
Onshore Disposal
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings, Discharge
Onsite Injection (0%S: 0%D)
Onshore Disposal (100%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
8
16,100
128,800
4,293,570
0
128,800
1
628,364
628,364
0
628,364
0
33,739
0
0
0
0
0
1,316,784
0
0
0
16
24,364
389,818
12,994,698
0
389,818
0
950,887
0
0
0
0
54,170
0
0
0
0
0
2,114,195
0
0
0
24
518,618
17,288,268
0
518,618
1
628,364
0
628,364
2.50 0508
62 0 123 0 185
64 0 128 0 192
71,768 0 143,535 0 215,303
NSPS 3: Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
628,364
0
0
0
0
7
628,364
4,398,548
628,364
3,770,184
0
1,316,784
0
0
0
0
0
1,316,784
0
0
0
3
950,887
2,852,661
0
950,887
1 ,901 ,774
8
950,887
7,607,097
1 ,901 ,774
5,705,323
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
3
2,852,661
0
950,887
1 ,901 ,774
15
12,005,645
2,530,138
9,475,507
Total SBF+OBFZero Discharge Loadings:
Total Zero Disharge Injection Loadings 628,364 0 2,852,661 0 3,481,025
Total Zero Discharge Onshore Loadings 3,770,184 0 7,607,097 0 11,377,281
A-80
-------
WORKSHEET 9:
California : Zero Discharge Summary, New Sources
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
Baseline: Zero Discharge Loadings
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
628,364
0
0
0
0
0
628,364
0
0
0
0
1,316,784
0
0
0
0
0
1,316,784
0
0
0
0
950,887
0
0
0
0
0
950,887
0
0
0
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
0
0
0
0
0 0000
0 0000
0 0000
0 0000
NSPS 1 : Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
552,796
0
0
0
0
0
628,364
0
0
0
0
1,158,426
0
0
0
0
0
1,316,784
0
0
0
0
836,532
0
0
0
0
0
950,887
0
0
0
0
1 ,859,939
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
0
0
0
Total Toxic Organics Discharge 0 0000
Total Toxic Metals Discharge 0 0000
Total Toxics Discharge 0 0000
Total Non-conventionals Discharge 0 0000
A-81
-------
California NSPS 2
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings, Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (80%; 0%DWE)
Onshore Disposal (20%; 100%DWE)
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
16,100
0
0
0
0
0
628,364
0
0
0
0
33,739
0
0
0
0
0
1,316,784
0
0
0
0
24,364
0
0
0
0
0
950,887
0
0
0
0
54,170
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
0
0
0
0
0.00 0000
0 0000
0 0000
0 0000
NSPS 3: Zero Discharge
ShallowWa
Development
0
628,364
0
0
0
0
0
628,364
0
0
0
er (<1 ,000 ft) Deep Water (>1 ,000 ft)
Exploratory Development Exploratory Total
0
1,316,784
0
0
0
0
0
1,316,784
0
0
0
0
950,887
0
0
0
0
0
950,887
0
0
0
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
0
0
0
0
Total SBF+OBFZero Discharge Loadings:
Total Zero Disharge Injection Loadings 0 0000
Total Zero Discharge Onshore Loadings 0 0000
A-82
-------
WORKSHEET 10:
Cook Inlet, Alaska : Zero Discharge Summary, New Sources
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
Baseline: Zero Discharge Loadings
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
628,364
0
0
0
0
0
628,364
0
0
0
0
1,316,784
0
0
0
0
0
1,316,784
0
0
0
0
950,887
0
0
0
0
0
950,887
0
0
0
0
2,114,195
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
0
0
0
0
0 0000
0 0000
0 0000
0 0000
NSPS 1 : Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
552,796
0
0
0
0
628,364
0
0
0
0
1,158,426
0
0
0
0
1,316,784
0
0
0
0
836,532
0
0
0
0
950,887
0
0
0
0
1 ,859,939
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
0
0
0
Total Toxic Organics Discharge 0 0000
Total Toxic Metals Discharge 0 0000
Total Toxics Discharge 0 0000
Total Non-conventionals Discharge 0 0000
A-83
-------
Alaska NSPS 2
Onshore Disposal
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings, Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
Total Toxic Organics Discharge
Total Toxic Metals Discharge
Total Toxics Discharge
Total Non-conventionals Discharge
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Total Loadings Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
No. wells, OBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (100%)
Onshore Disposal ( 0%)
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
16,100
0
0
0
0
0
628,364
0
0
0
0
33,739
0
0
0
0
0
1,316,784
0
0
0
0
24,364
0
0
0
0
0
950,887
0
0
0
0
54,170
0
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0
0
0
0
0.00 0000
0 0000
0 0000
0 0000
NSPS 3: Zero Discharge
Shallow Water (<1 ,000 ft) Deep Water (>1 ,000 ft)
Development Exploratory Development Exploratory Total
0
628,364
0
0
0
0
0
628,364
0
0
0
0
1,316,784
0
0
0
0
0
1,316,784
0
0
0
0
950,887
0
0
0
0
0
950,887
0
0
0
0
2,114,195
0
0
0
0
0
0
0
0 0
0
2,114,195
0
0
0
0
0
0 0
Total SBF+OBFZero Discharge Loadings:
Total Zero Disharge Injection Loadings 0 0000
Total Zero Discharge Onshore Loadings 0 0000
A-84
-------
WORKSHEET No. 11:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: CONVENTIONAL POLLUTANTS FROM DISCHARGED CUTTINGS, EXISTING SOURCES
POLLUTANTS FROM DISCHARGED CUTTINGS Shallow Well
(Conventionals) GOM CA AK
( from ODD: Table XI-2, p XI-4)
well depth, TD 10,559 7,607 10,633
no. wells , total by region (from Exh. 2) 857 5 4
% WBF (total-DBF) wells discharging (from Exh. 1) 45.06% 51.25% 36.23%
no. wells discharging cuttings, by region 386 3 1
cuttings discharged , bbl per well 1,475 1,242 1,480
CUTTINGS TSS ANALYSIS:
Ibs TSS per well 812,209 683,907 814,962
total Ibs TSS 313,512,578 2,051,722 814,962
Gulf of Mexico
California
Alaska
total volume cuttings, bbl 569,350 3,726 1,480
Gulf of Mexico
California
Alaska
CUTTINGS OIL ANALYSIS: I
% wells, by type and region (from Exh. 1) B 51.00% 58.00% 41.00%
total no. wells, by region (from Exh. 2) 857 5 4
no. wells, by type and region 437 3 2
% wells using MO spot or lube & discharging (from Exh. 1) 10.41% 11.83% 8.37%
no. wells using MO and discharging 45
cuttings discharged per well, bbl 1,475 1,242 1,480
fraction adherent fluid (from Exh. 3) 5.0% 5.0% 5.0%
volume adherent fluid, per well, bbl 74 62 74
MO, Ibs per well 666 558 666
total Ibs MO 29,970
Gulf of Mexico
California
Alaska
total volume MO, bbl 3,330
Gulf of Mexico
California
Alaska
TOTAL CONVENTIONAL POLLUTANTS
Ibs conventional pollutants discharged 313,542,548 2,051,722 814,962
Gulf of Mexico
California
Alaska
bbl conventional pollutants discharged 572,680 3,726 1,480
Gulf of Mexico
California
Alaska
Deep Well
GOM CA AK
13,037 10,082 12,354
857 5 4
36.80% 31.54% 44.31%
315 2 2
2,458 1,437 2,413
1,353,498 791,284 1,328,718
426,351,776 1,582,568 2,657,437
774,270 2,874 4,826
49.00% 42.00% 59.00%
857 5 4
420 2 2
8.50% 7.28% 10.23%
36
2,458 1,437 2,413
123 72 121
1,107 648 1,089
39,852
4,428
426,391,628 1,582,568 2,657,437
778,698 2,874 4,826
Totals
866
709
746,971 ,042
739,864,353
3,634,290
3,472,399
1,356,526
1,343,620
6,600
6,306
866
866
81
69,822
69,822
7,758
7,758
747,040,864
739,934,175
3,634,290
3,472,399
1 ,364,284
1,351,378
6,600
6,306
A-85
-------
WORKSHEET No. 12:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: CONVENTIONAL POLLUTANTS FROM DISCHARGED DRILLING FLUID, EXISTING SOURCES
POLLUTANTS FROM DISCHARGED DRILLING FLUIDS
(Conventionals)
( from ODD: Table XI-2, p XI-4)
well depth, TD (from Exh. 5A)
no. wells , total (from Exh. 2)
no. wells discharging fluids (from Exh. 5A)
drilling fluids (bbl) per well
Shallow Well
GOM CA AK
10,559 7,607 10,633
857 5 4
386 3 1
6,938 5,939 6,963
WB FLUIDS TSS ANALYSIS:
Ibs TSS / bbl (from Exh. 3)
Ibs TSS per well
total Ibs TSS
Gulf of Mexico
California
Alaska
total volume, bbl, WB fluids
Gulf of Mexico
California
Alaska
WB FLUIDS OIL ANALYSIS:
% wells using MO spot or lube, discharging (from Exh. 1)
no. wells using MO and discharging (from Exh. 5A)
WB fluids discharged per well, bbl
MO, Ibs per bbl (from Exh. 3)
MO, Ibs per well
total Ibs MO
Gulf of Mexico
California
Alaska
total volume MO, bbl
Gulf of Mexico
California
Alaska
1,061,514 908,667 1,065,339
409,744,404 2,726,001 1,065,339
Deep Well
GOM CA AK
13,037 10,082 12,354
857 5 4
315 2 2
9,752 6,777 9,458
153 153 153
1,492,056 1,036,881 1,447,074
469,997,640 2,073,762 2,894,148
Totals
866
709
888,501,294
879,742,044
4,799,763
3,959,487
2,678,068 17,817 6,963 3,071,880 13,554 18,916 5,807,198
5,749,948
31,371
25,879
10.41% 11.83% 8.37%
45
6,938 5,939 6,963
999
62,442 53,451 62,667
2,809,890
8.50% 7.28% 10.23%
36
9,752 6,777 9,458
999
87,768 60,993 85,122
3,159,648
81
9
85,122
5,969,538
5,969,538
9,421 - - 10,593 - - 20,014
423,935 - - 381,363 - - 805,299
TOTAL CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants discharged
Gulf of Mexico
California
Alaska
bbl conventional pollutants discharged
Gulf of Mexico
California
Alaska
412,554,294 2,726,001 1,065,339 473,157,288 2,073,762 2,894,148 894,470,832
885,711,582
4,799,763
3,959,487
2,687,489 17,817 6,963 3,082,473 13,554 18,916 5,827,212
5,769,962
31,371
25,879
Avg COM drilling fluid discharged, bbl/day (20-day drilling program)
Avg adherent fluid (5%) on cuttings discharged COM, bbl/day
Total avg per well COM drilling fluid discharged, bbl/day
no. wells discharging fluids
Total GOM drilling fluid discharges, bbl/day
GOM-wide wtd avg drilling fluid discharges, bbl/day
347 297 348 488 339 473
434 646
351 300 352 494 342 479 2,318
386 315 701
135,327 155,530 290,856
415
-------
WORKSHEET No. 13:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: TOXIC/NON-CONVENTIONAL POLLUTANTS
FROM DISCHARGED DRILLING FLUID, EXISTING SOURCES
POLLUTANTS FROM DISCHARGED DRILLING FLUIDS
(Toxics & Non-conventionals)
TOXICS
( from ODD: Table XI-2, p XI-4)
Well Depth, TD (from Exh. 5A)
No. wells , total (from Exh. 2)
No. wells discharging cuttings (from Exh. 5A)
Drilling fluidsDischarged (bbl) per well
WB FLUIDS TOXICS/NON-CONVENTIONALS:
Ibs toxics/non-conventionals/ bbl (from Exh. 3)
Ibs toxics/non-conventionals per well
total Ibs toxics/non-conventionals
Shallow Well
COM CA AK
10,559 7,607 10,633
857 5 4
386 3 1
6,938 5,939 6,963
37.7 37.7 37.7
261,629 223,957 262,572
100,988,785 671,871 262,572
Deep Well
COM CA AK
857 5 4
315 2 2
9,752 6,777 9,458
37.7 37.7 37.7
367,744 255,558 356,657
115,839,265 511,115 713,314
Totals
866
709
218,986,922
Gulf of Mexico 216,828,049
California 1,182,987
Alaska 975,886
total volume, bbl, WB fluids 2,678,068 17,817 6,963 3,071,880 13,554 18,916 5,807,198
Gulf of Mexico 5,749,948
California 31,371
Alaska 25,879
WB FLUIDS MINERAL OIL TOXICS/NON-CONVENTIONALS:
% wells using MO spot or lube, discharging (from Exh. 1)
no. wells using MO and discharging (from Exh. 5A)
WB fluids discharged per well, bbl
mineral oil toxics, Ib / bbl (from Exh. 3)
mineral oil toxics, Ibs /well
total Ibs mineral oil toxics
10.41% 11.83% 8.37%
45
6,938 5,939 6,963
0.324 0.324 0.324
2,247 1,924 2,256
101,134
8.50% 7.28% 10.23%
36
9,752 6,777 9,458
0.324 0.324 0.324
3,159 2,195 3,064
113,722
81
14,845
214,856
Gulf of Mexico 214,856
California
Alaska
TOTAL TOXIC/NON-CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants discharged 101,089,918 671,871 262,572 115,952,987 511,115 713,314 219,201,778
Gulf of Mexico 217,042,905
California 1,182,987
Alaska 975,886
A-87
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WORKSHEET No. 14:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: CONVENTIONAL POLLUTANTS FROM DISCHARGED CUTTINGS, NEW SOURCES
POLLUTANTS FROM DISCHARGED CUTTINGS
(Conventionals)
( from ODD: Table XI-2, p XI-4)
well depth, TD
no. wells , total by region (from Exh. 2)
% WBF (total-DBF) wells discharging (from Exh. 1)
no. wells discharging cuttings, by region
cuttings discharged , bbl per well
CUTTINGS TSS ANALYSIS:
IbsTSS per well
total Ibs TSS
Gulf of Mexico
California
Alaska
total volume cuttings, bbl
Gulf of Mexico
California
Alaska
CUTTINGS OIL ANALYSIS:
% wells , by type and region (from Exh. 1)
total no. wells, by region (from Exh. 2)
no. wells, by type and region
% wells using MO spot or lube & discharging (from Exh. 1)
no. wells using MO and discharging
cuttings discharged per well, bbl
fraction adherent fluid (from Exh. 3)
volume adherent fluid, per well, bbl
MO, Ibs per well
total Ibs MO
Gulf of Mexico
California
Alaska
total volume MO, bbl
Gulf of Mexico
California
Alaska
TOTAL CONVENTIONAL POLLUTANTS
Ibs conventional pollutants discharged
Gulf of Mexico
California
Alaska
bbl conventional pollutants discharged
Gulf of Mexico
California
Alaska
Shallow Well
GOM CA AK
' 38
45.06% 51 .25% 36.23%
17 00
1,475 1,242 1,480
812,209 683,907 814,962
13,807,549 0 0
25,075 0 0
51.00%| 58.00%| 41.00%
38
19 00
10.41%| 11.83%! 8.37%
2 00
74 62 74
666 558 666
1 ,332 0 0
148 0 0
13,808,881 0 0
25,223 0 0
Deep Well
GOM CA
13,037 10,082
38
36.80% 31.54%
14 0
2,458 1,437
1,353,498 791,284
18,948,968 0
34,412 0
49.00%| 42.00%
38
19 0
8.50%| 7.28%
2 0
2,458 1,437
123 72
1,107 648
2,214 0
246 0
18,951,182 0
34,658 0
Totals
AK
12,354
38
44.31%
0 31
2,413
1,328,718
0 32,756,517 I
32,756,517
I
0 59,487
59,487
59.00%
38
0 19
10.23%
0 4 |
2,413
5.0%
121
1,089
0 3,546 |
3,546
0 394 |
394
0 32,760,063 I
32,760,063
0 59,881 |
59,881
A-88
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WORKSHEET No. 15:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: CONVENTIONAL POLLUTANTS FROM DISCHARGED DRILLING FLUID, NEW SOURCES
POLLUTANTS FROM DISCHARGED DRILLING FLUIDS
(Conventionals)
( from ODD: Table XI-2, p XI-4)
well depth, TD (from Exh. 5A)
no. wells , total (from Exh. 2)
no. wells discharging fluids (from Exh. 5A)
drilling fluids (bbl) per well
Shallow Well Deep V
GOM CA AK GOM CA
10,559 7,607 10,633 13,037
38 - - 38
17 0 0 14
6,938 5,939 6,963 9,752
WB FLUIDS TSS ANALYSIS: I
IbsTSS/bbl (from Exh. 3) 153 153 153 153
IbsTSSperwell 1,061,514 908,667 1,065,339 1,492,056 1,C
total Ibs TSS | 18,045,738 - - 20,888,784
Gulf of Mexico
California
Alaska
total volume, bbl, WB fluids
Gulf of Mexico
California
Alaska
117,946 - - 136,528
i/ell Totals
AK
10,082 12,354
38
0 0 31
6,777 9,458
153 153
36,881 1,447,074
38,934,522
38,934,522
254,474
254,474
WB FLUIDS OIL ANALYSIS:
% wells using MO spot or lube, discharging (from Exh. 1)
no. wells using MO and discharging (from Exh. 5A)
WB fluids discharged per well, bbl
MO, Ibs per bbl (from Exh. 3)
MO, Ibs per well
total Ibs MO
Gulf of Mexico
California
Alaska
total volume MO, bbl
Gulf of Mexico
California
Alaska
10.41% 11.83% 8.37% 8.50%
2 - - 2
6,938 5,939 6,963 9,752
999 9
62,442 53,451 62,667 87,768
124,884 - - 175,536
419 - - 589
837 - - 1,177
7.28% 10.23%
4
6,777 9,458
99 9
60,993 85,122 85,122
300,420
300,420
1,007
2,014
TOTAL CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants discharged
Gulf of Mexico
California
Alaska
bbl conventional pollutants discharged
Gulf of Mexico
California
Alaska
18,170,622 - - 21,064,320
118,365 - - 137,117
39,234,942
39,234,942
255,481
255,481
Avg COM drilling fluid discharged, bbl/day (20-day drilling program)
347 297 348 488
339 473
Avg adherent fluid (5%) on cuttings discharged COM, bbl/day - -
Total avg per well COM drilling fluid discharged, bbl/day
no. wells discharging fluids
Total GOM drilling fluid discharges, bbl/day
GOM-wide wtd avg drilling fluid discharges, bbl/day
347 297 348 488
17 14
5,897 6,826
339 473 2,291
31
12,724
410
-------
WORKSHEET No. 16:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: TOXIC/NON-CONVENTIONAL POLLUTANTS FROM DISCHAREGD DRILLING FLUID, NEW SOURCES
POLLUTANTS FROM DISCHARGED DRILLING FLUIDS
(Toxics & Non-conventionals)
TOXICS
( from ODD: Table XI-2, p XI-4)
Well Depth, TD (from Exh. 5A)
No. wells , total (from Exh. 2)
No. wells discharging cuttings (from Exh. 5A)
Drilling fluidsDischarged (bbl) per well
WB FLUIDS TOXICS/NON-CONVENTIONALS:
Ibs toxics/non-conventionals/ bbl (from Exh. 3)
Ibs toxics/non-conventionals per well
total Ibs toxics/non-conventionals
Shallow Well
COM CA AK
10,559 7,607 10,633
38
17 0 0
6,938 5,939 6,963
37.7 37.7 37.7
261,629 223,957 262,572
4,447,693
Deep Well
COM CA AK
38
14 0 0
9,752 6,777 9,458
37.7 37.7 37.7
367,744 255,558 356,657
5,148,412
Totals
38
31
9,596,104
Gulf of Mexico 9,596,104
California
Alaska
total volume, bbl, WB fluids 117,946 - - 136,528 - - 254,474
Gulf of Mexico 254,474
California
Alaska
WB FLUIDS MINERAL OIL TOXICS/NON-CONVENTIONALS:
% wells using MO spot or lube, discharging (from Exh. 1)
no. wells using MO and discharging (from Exh. 5A)
WB fluids discharged per well, bbl
mineral oil toxics, Ib / bbl (from Exh. 3)
mineral oil toxics, Ibs /well
total Ibs mineral oil toxics
000
2
6,938 5,939 6,963
0.324 0.324 0.324
2,247 1,924 2,256
4,495
000
2
9,752 6,777 9,458
0.324 0.324 0.324
3,159 2,195 3,064
6,318
4
14,845
10,813
Gulf of Mexico 10,813
California
Alaska
TOTAL TOXIC/NON-CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants discharged 4,452,187 - - 5,154,730 - - 9,606,917
Gulf of Mexico 9,606,917
California
Alaska
A-90
-------
APPENDIX VIII-5
Pollutant Loadings (Removals)
Supporting Worksheets
A-91
-------
WORKSHEET A:
Input Data for Model Wells - Base Fluid Retention and Drill Cuttings Volume Calculations,
Synthetic-based Fluid Analyses
Densities for SBF Components and Drill Cuttings:
SBF Base fluid (Ibs/bbl):
SBF Barite (Ibs/bbl):
SBF Water (Ibs/bbl):
Dry Formation Cuttings (Ibs/bbl):
Formation Oil (as diesel) (Ibs/bbl):
SBF Fraction Data:
Basefluid Fraction of Standard SBF (wt./wt.):
Barite Fraction of Standard SBF (wt./wt.):
Water Fraction of Standard SBF (wt./wt.):
SBF Formulation Density (Ibs./gal.):
Model Well Volume Data:
Shallow Water, Exploratory (barrels):
Deep Water, Exploratory (barrels):
Shallow Water, Development (barrels):
Deep Water, Development (barrels):
Formation Oil Contamination:
for Solids Control Equipment
Fraction of Total Wet Cuttings Discharge (V/V) for SolidsControl Equipment
Various BPT and BAT/NSPS Options:
Primary Shale Shakers:
Secondary Shale Shakers:
Fines Removal Unit:
BAT/NSPS Option 1
Cuttings Dryer:
Fines Removal Unit:
BAT/NSPS Option 2
Base Fluid Fraction of Discharged Wet Cuttings (W/W) for BAT/NSPS Options
BAT/NSPS Option 1 (Two Discharges):
BAT/NSPS Option 2 (One Discharge):
Base Fluid Fraction of Wet Cuttings (W/W)
Primary Shale Shakers:
Secondary Shale Shakers:
Cuttings Dryer:
Fines Removal Unit:
Equations Used to Calculate Loadings
Total Cuttings Waste Discharged (Ibs) = (DC)/(1-(1/SF)*CRN)
SBF Basefluid Discharged (Ibs) = CRN * TW
SBF Water Discharged (Ibs) = (WF/SF)*(CRN *TW)
SBF Barite Discharged (Ibs) = (BF/SF)*(CRN *TW)
where:
Notes:
TW = Total Cuttings Waste Discharged (Ibs)
DC = Dry Drill Cuttings Discharged (Ibs)
CRN = SBF Basefluid Fraction on TW (Cuttings Retention Number) (wt./wt.)
SF = SBF Basefluid Fraction (wt./wt.) in Drilling Fluid Formulation
WF = SBF Water Fraction (wt./wt.) in Drilling Fluid Formulation
BF = SBF Barite Fraction (wt./wt.) in Drilling Fluid Formulation
SBFV = Whole Synthetic Based Fluid Volume
" Assume SF + WF + BF = 1
* DC is calculated from model well size
* SBFV is the sum total of SBF basefluid, barite, and water (in bbl) discharged
* Total Cuttings Waste Discharged in BAT/NSPS Option 2 is equivalent to the volume
fraction of total cuttings waste discharged from cuttings dryer multiplied against
the total cuttings waste calculated in BAT/NSPS Option 1
* Total Cuttings Waste Not Discharged in BAT/NSPS Option 2 is equivalent to the volume
fraction of total cuttings waste discharged from the fines removal unit (FRU)
multiplied against the total cuttings waste calculated in BAT/NSPS Option 1
* Dry Drill Cuttings Discharged in BAT/NSPS Option 2 is equivalent to the arithmetric
difference between the BAT/NSPS Option 2 Total Cuttings Waste Discharged and
the BAT/NSPS Option 2 SBF (Basefluid, Barite, Water) Discharged
* Dry Drill Cuttings Not Discharged in BAT/NSPS Option 2 is equivalent to the arithmetric
difference between the BAT/NSPS Option 2 Total Cuttings Waste Not Discharged and
the BAT/NSPS Option 2 SBF (Basefluid, Barite, Water) Not Discharged
A-92
-------
WORKSHEET No. B:
ANALYSIS OF WBF PASS/FAIL PERMIT LIMITS (SHEEN; TOXICITY); FAILS HAULED TO ONSHORE DISPOSAL(a,b,c)
Gulf of Mexico
shallow
shallow, no lube
shallow, no lube, no spot
shallow, no lube, + spot
shallow, + lube
shallow, + lube, no spot
shallow, + lube, + spot
total % shallow wells
deep
deep, OBF (no discharge)
deep, WBF (discharge)
deep, no lube
deep, no lube, no spot
deep, no lube, + spot
deep, + lube
deep, + lube, no spot
deep, + lube, + spot
total % deep wells
California
shallow
shallow, no lube
shallow, no lube, no spot
shallow, no lube, + spot
shallow, + lube
shallow, + lube, no spot
shallow, + lube, + spot
total % shallow wells
deep
deep, OBF (no discharge)
deep, WBF (discharge)
Ideep, no lube
deep, no lube, no spot
deep, no lube, + spot
deep, + lube
deep, + lube, no spot
deep, + lube, + spot
total % deep wells
Alaska
shallow
shallow, no lube
shallow, no lube, no spot
shallow, no lube, + spot
shallow, + lube
shallow, + lube, no spot
shallow, + lube, + spot
total % shallow wells
deep
deep, OBF (no discharge)
deep, WBF (discharge)
deep, no lube
hdeep, no lube, no spot
deep, no lube, + spot
deep, + lube
deep, + lube, no spot
deep, + lube, + spot
total % deep wells
(44.88% * 78%
(44.88% *
(6. 12%* 78%
(6.12%*
(43. 12%* 78%
(43.12%*
(6. 12%* 78%
(6.12%*
(5 1.04%* 78%
(51.04%*
(6.96% * 78%
(6.96% *
(36.96% * 78%
(36.96% *
(3.93% * 78%
(3.93% *
(36.08% * 78%
(36.08% *
(4.92% * 78%
(4.92% *
(5 1.92%* 78%
(51.92%*
(7.08% * 78%
(7.08% *
0
(51% GOM wells) =
(51%* 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(51%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(49% GOM wells) =
(1 5% of deep wells) =
(85% of deep wells) =
(49% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(49%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(58% CA wells) =
(58% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(58%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(42% CA wells) =
(1 5% of deep wells) =
(85% of deep wells) =
(42% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(42%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(41 %AK wells) =
(41%* 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(41%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(59% AK wells) =
(1 5% of deep wells) =
(85% of deep wells) =
(59% * 88% all wells) =
all wells do not use spot) =
22% all wells need spot) =
(59%* 12% all wells) =
all wells do not use spot) =
22% all wells need spot) =
'o Wells/region
Shallow/deep
% split
51.00%
49.00%
7.35%
41.65%
58.00%
42.00%
6.30%
35.70%
41.00%
59.00%
8.85%
50.15%
No lube
/lube
% split
44.88%
6.12%
36.65%
5.00%
41.65%
51.04%
6.96%
31.42%
4.28%
35.70%
36.08%
4.92%
44.13%
6.02%
50.15%
No spot
/spot
% split
35.01%
9.87%
4.77%
1.35%
28.59%
8.06%
3.90%
1.10%
41.65%
39.81%
11.23%
5.43%
1.53%
24.50%
6.91%
3.34%
0.94%
35.70%
28.14%
7.94%
3.84%
1.08%
34.42%
9.71%
4.69%
1.32%
50.15%
Proj'd Tox /
Sheen Limit
Failure Rate
1.0%
33.0%
33.0%
56.0%
100%
1.0%
33.0%
33.0%
56.0%
1.0%
33.0%
33.0%
56.0%
100%
1.0%
33.0%
33.0%
56.0%
1.0%
33.0%
33.0%
56.0%
100%
1.0%
33.0%
33.0%
56.0%
Proj'd %
Wells Fail
Permit Lim
0.350%
3.258%
1.575%
0.754%
5.940%
7.35%
0.286%
2.661%
1.286%
0.616%
12.20%
0.398%
3.706%
1.792%
0.857%
6.753%
6.30%
0.245%
2.281%
1.103%
0.528%
10.46%
0.281%
2.619%
1.266%
0.606%
4.773%
8.85%
0.344%
3.204%
1.549%
0.741%
14.69%
Proj'd %
Wells Pass
Permit Lim
34.66%
6.62%
3.20%
0.59%
45.06%
0.00%
28.30%
5.40%
2.61%
0.48%
36.80%
39.41%
7.52%
3.64%
0.67%
51.25%
0.00%
24.26%
4.63%
2.24%
0.41%
31.54%
27.86%
5.32%
2.57%
0.48%
36.23%
0.00%
34.08%
6.51%
3.15%
0.58%
44.31%
Sum lubes(l)
spot(s), or l+s
that Pass
10.41%
8.50%
11.83%
7.28%
8.37%
10.23%
(a) Percentage Distribution of Water-based Drilling Fluid Types, (no oil, +MO lube, +MO spot, or+MO lube & spot)
(b) Cells shaded in blue are data input from ODD: Table XI-10, p XI-17; other percentages shown are derived from these input values)
(c) The terms "shallow" and "deep" as used in the offshore effluent limitaiton guideline do NOT have the same meaning as the same terms as used in the synthetics effluent guideline;
these terms in the offshore rule refers to the relative target depth of the well, whereas in the synthetics rule they refer to the water depth in which operations occur.
A-93
-------
WORKSHEET No. C:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: WELL DEPTHS AND VOLUMES OF DISCHARGED CUTTINGS AND DRILLING FLUIDS
(from ODD: Table XI-2, p XI-4)
(from ODD: Table XI-2, p XI-4)
well depth, TD
cuttings discharged , bbl per well
drilling fluids (bbl) per well
COM |
10,559
1,475
6,938
CA |
Shallow Well
7,607
1,242
5,939
AK
10,633
1,480
6,963
COM
13,037
2,458
9,752
CA
Deep Well
10,082
1,437
6,777
AK
12,354
2,413
9,458
Current Well Counts, SBF Effluent Limitations Guideline (see "Well Count Input Sheet," this file)
Est'd % WBF > SBF
Baseline 0%
BAT 1 6%
BAT 2 6%
EXISTING SOURCES, WBF Wells
COM CA AK Subtotal
857.0
803.0
803.0
5
5
5
4
4
4
866
812
812
NEW SOURCES, WBF Wells
COM CA AK Subtotal
38
35
35
0
0
0
0
0
0
38
35
35
Total
904
847
847
WBF/Water Phase Composition/Contribution to Toxic/Non-conventional Pollutant Loadings, Offshore Record
(from ODD: Table XI-3, p XI-5 and Table XI-6, p XI-9)
1 Drilling
| Fuids
barite
1 kg/bbl tox+non-Conv
I Ib/bbl tox+non-Conv
[mineral oil
ITSS
Composition,
Ibs/bbl
98
9
153
Total nonC+toxics+Ba
384,792 mg/kg dry
17.1 kg/bbl
37.7 Ib/bbl
2.9 Ib/bbl
153.0 Ib/bbl
Cuttings
Density
Adherent mud
Mud TSS
Ad'nt mud TSS
(fromODD, p XI-6)
543 Ibs/bbl
Ib/bbl
7.7 Ib/bbl
Total TSS per bbl cuttings
551 Ib/bbl
WBF/ Mineral Oil Phase Contribution to Toxic/Non-conventional Pollutant Loadings
(from ODD: Table XI-5, p XI-7)
MO (9 Ib/bbl)
30.51 mg nonconventionals/ml MO:
0.05 mg toxics/ml MO,
kg toxic+Non-conventional Pollutants per bbl MO
Ibs toxic + Non-conventional Pollutants per bbl MO
0.14700 kg/bbl
0.00024 kg/bbl
0.147 kg/bbl
0.324 Ib/bbl
>n-conventional = 99.8%
toxics = 0.2%
461
11.0
2.1
23.1
543
566
b/bbl mud
Ib/gal mud
gal of 5% mud
wt of 5% mud
Ib/bbl cuttings
Ib/bbl wet cuttings
A-94
-------
WORKSHEET No. D:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUIDS: CONVENTIONAL POLLUTANTS FROM ZERO DISCHARGE CUTTINGS
(INJECTED ONSITE OR HAULED FOR ONSHORE DISPOSAL) DUE TO PROJECTED SHEEN OR TOXICITY TEST FAILURES, EXISTING SOURCES
POLLUTANTS FROM CUTTINGS HAULED OR INJECTED
(Coventionals)
( from ODD: Table XI-2, p XI-4)
well depth, TD
no. wells , total by region (from Exh. 2)
No. WBF wells zero discharge cuttings
Cuttings (bbl) per well
CUTTINGS TSS ANALYSIS:
Ibs TSS per well
total Ibs TSS
Gulf of Mexico
California
Alaska
total volume cuttings, bbl
Gulf of Mexico
California
Alaska
CUTTINGS OIL ANALYSIS:
% wells , by type and region (from Exh. 1)
total no. wells, by region (from Exh. 2)
no. wells, by type and region
no. wells zero discharge
cuttings per well, bbl
fraction adherent fluid
volume adherent fluid, per well, bbl
MO, Ibs per well
total Ibs MO
Gulf of Mexico
California
Alaska
total volume MO, bbl
Gulf of Mexico
California
Alaska
TOTAL CONVENTIONAL POLLUTANTS
Ibs conventional pollutants zero discharge
Gulf of Mexico
California
Alaska
% injected onsite onsite
% hauled onshore onshore
Ibs pollutants injected
Ibs pollutants disposed onshore
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
bbl conventional pollutants zero discharged
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
Shallow Well
GOM CA AK
10,559 7,607 10,633
857 5 4
51 00
1,475 1,242 1,480
812,209 683,907 814,962
41,349,547
75,092
51 .00% 58.00% 41 .00%
857 5 4
437 3 2
48 ^C)^ ^0
74.0 62 74
666 558 666
31,968
3,552
41,381,515
20% 20% 100%
80% 80% 0%
8,276,303
33,105,212
78,644
Deep Well
GOM CA AK
13,037 10,082 12,354
857 5 4
42 0 0
2,458 1,437 2,413
1,353,498 791,284 1,328,718
56,846,903
103,236
49.00% 42.00% 59.00%
857 5 4
420 2 2
39 0 0
2,458 1,437 2,413
5.0% 5.0% 5.0%
123 72 121
1,107 648 1,089
43,173
4,797
56,890,076
0% 0% 100%
100% 100% 0%
56,890,076
108,033
Totals
866
93
98,196,451
98,196,451
178,328
178,328
866
87
75,141
75,141
8,349
8,349
98,271,592
98,271,592
8,276,303
89,995,289
8,276,303
89,995,289
186,677
15,729
170,948
-------
WORKSHEET No. E:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUIDS: CONVENTIONAL POLLUTANTS FROM DRILLING FLUIDS ZERO DISCHARGED
(INJECTED ONSITE OR HAULED FOR ONSHORE DISPOSAL) DUE TO PROJECTED SHEEN OR TOXICITY TEST FAILURES.EXISTING SOURCES
POLLUTANTS FROM DRILLING FLUIDS HAULED OR INJECTED
(Conventionals)
( from ODD: Table XI-2, p XI-4)
Well Depth, TD
No. wells , total
No. wells hauling fluids
Drilling fluids (bbl) per well
WB FLUIDS TSS ANALYSIS:
IbsTSS/bbl
Ibs TSS per well
total Ibs TSS
Shallow Well
COM CA AK
10,559 7,607 10,633
857 5\ 4
51 Q| 0
6,938 5,939 6,963
153 153 153
1,061,514 908,667 1,065,339
54,041,678
Deep Well
COM CA AK
9,752 6,777 9,458
153 153 153
1,492,056 1,036,881 1,447,074
62,666,352
Totals
866
93
116,708,030
Gulf of Mexico 116,708,030
California
Alaska
total volume, bbl, WB fluids 353,214 - - 409,584 - - 762,798
Gulf of Mexico 762,798
California
Alaska
WB FLUIDS OIL ANALYSIS:
% wells using MO spot or lube, hauling
no. wells using hauling
WB fluids discharged per well, bbl
MO, Ibs per bbl
MO, Ibs per well
total Ibs MO
5.59% 6.75% 4.77%
48
6,938 5,939 6,963
999
62,442 53,451 62,667
2,997,216
4.56% 4.16% 5.84%
39
9,752 6,777 9,458
999
87,768 60,993 85,122
3,422,952
87
9
85,122
6,420,168
Gulf of Mexico 6,420,168
California
Alaska
total volume MO, bbl 10,049 - - 11,476 - - 21,525
Gulf of Mexico 482,344 - - 447,572 - - 929,916
California
Alaska
TOTAL CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants zero discharge
Gulf of Mexico
California
Alaska
% injected onsite onsite
% hauled onshore onshore
Ibs pollutants Injected
Ibs pollutants disposed onshore
57,038,894
20% 20% 100%
80% 80% 0%
11,407,779
45,631,115
66,089,304
0% 0% 100%
100% 100% 0%
66,089,304
123,128,198
123,128,198
11,407,779
111,720,419
Gulf of Mexico injected onsite 11,407,779
California injected onsite
Alaska injected onsite
GulfofMexico disposed onshore 111,720,419
California disposed onshore
Alaska disposed onshore
bbl conventional pollutants zero discharged
363,262
421,060
123,128,198
784,323
Gulf of Mexico injected onsite 72,652
California injected onsite
Alaska injected onsite
Alaska disposed onshore
-------
WORKSHEET No. F:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: TOXIC/NON-CONVENTIONAL POLLUTANTS FROM ZERO DISCHARGE
DRILLING FLUIDS (INJECTED ONSITE OR HAULED FOR ONSHORE DISPOSAL) DUE TO SHEEN/TOXICITY TEST FAILURES, EXISTING SOURCES
POLLUTANTS FROM DISCHARGED DRILLING FLUIDS
(Toxics & Non-conventionals)
TOXICS HAULED
( from ODD: Table XI-2, p XI-4)
Well Depth, TD
No. wells , total
No. wells discharging cuttings
Drilling fluidsDischarged (bbl) per well
WB FLUIDS TOXICS/NON-CONVENTIONALS:
Ibs toxics/non-conventionals/ bbl (from Exh. 3)
Ibs toxics/non-conventionals per well
total Ibs toxics/non-conventionals
Gulf of Mexico
California
Alaska
total volume, bbl, WB fluids
Shallow Well
GOM CA AK
10,559 7,607 10,633
857 5 4
51 0 0
6,938 5,939 6,963
37.7 37.7 37.7
261,629 223,957 262,572
13,319,531
Deep Well
GOM CA AK
13,037 10,082 12,354
857 5 4
42 0 0
9,752 6,777 9,458
37.7 37.7 37.7
367,744 255,558 356,657
15,445,235
353,214 - - 409,584
Gulf of Mexico
California
Alaska
WB FLUIDS MINERAL OIL TOXICS/NON-CONVENTIONALS:
% wells using MO spot or lube, discharging (from Exh. 1)
no. wells using MO and discharging (from Exh. 5A)
WB fluids discharged per well, bbl
mineral oil toxics, Ib / bbl (from Exh. 3)
mineral oil toxics, Ibs /well
total Ibs mineral oil toxics
Gulf of Mexico
California
Alaska
total volume MO, bbl
Gulf of Mexico
California
Alaska
5.59% 0.00% 0.00%
48
6,938 5,939 6,963
0.324 0.324 0.324
2,247 1,924 2,256
107,876
0.00% 0.00% 0.00%
39
9,752 6,777 9,458
0.324 0.324 0.324
3,159 2,195 3,064
123,199
362 - - 413 - -
17,361 - - 16,109
TOTAL TOXIC/NON-CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants discharged 13,427,407 - - 15,568,434
Gulf of Mexico
California
Alaska
% injected onsite onsite
% hauled onshore onshore
Ibs pollutants injected
Ibs pollutants disposed onshore
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
20% 20% 100%
80% 80% 0%
2,685,481
10,741,926
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
bbl conventional pollutants discharged
353,575
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
0% 0% 100%
100% 100% 0%
15,568,434
Totals
866
93
28,764,766
28,764,766
762,798
762,798
87
14,845
231,075
231,075
775
33,470
28,995,841
28,995,841
2,685,481
26,310,360
2,685,481
26,310,360
409,997
28,995,841
763,572
70,715
692,857
-------
WORKSHEET G:
Baseline (WBF) Existing Sources - Lower Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onslte Discharge and Zero Discharge/Onshore Disposal Loadings
COM CA AK Total
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
838,205,767 3,634,290 3,472,399 845,312,456
1,008,839,780 4,799,763 3,959,487 1,017,599,030
246,038,746 1,182,987 975,886 248,197,619
1,254,878,526 5,982,750 4,935,373 1,265,796,649
2,093,084,293 9,617,040 8,407,772 2,111,109,104
.
Total Drilling Fluids -
TOTAL ZD/ONSHORE DISPOSAL LOADINGS ...
Onsite Injection ...
Haul/Onshore Disposal ...
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
2,093,084,293 9,617,040 8,407,772 2,111,109,104
BAT 1 & 2 (WBF) Existing Sources - Lower Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onslte Discharge and Zero Discharge/Onshore Disposal Loadings
COM CA AK Total
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
786,319,752 3,634,290 3,472,399 793,426,441
946,379,702 4,799,763 3,959,487 955,138,952
230,802,429 1,182,987 975,886 232,961,301
1,177,182,130 5,982,750 4,935,373 1,188,100,253
1,963,501,883 9,617,040 8,407,772 1,981,526,694
.
Total Drilling Fluids ...
TOTAL ZD/ONSHORE DISPOSAL LOADINGS ...
Onsite Injection ...
Haul/Onshore Disposal ...
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
1,963,501,883 9,617,040 8,407,772 1,981,526,694
A-98
-------
WORKSHEET G:
BAT 3 (WBF) Existing Sources - Lower Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onslte Discharge and Zero Discharge/Onshore Disposal Loadings
COM CA AK Total
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Toxics 4
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Toxics 4
Conventionals
Conventionals
Non-conventionals
Total Drilling Fluids
Conventionals
Conventionals
Non-conventionals
858,659,743 3,634,290 3,472,399 865,766,432
1,033,437,358 4,799,763 3,959,487 1,042,196,608
252,024,882 1,182,987 975,886 254,183,755
1,285,462,241 5,982,750 4,935,373 1,296,380,363
2,144,121,984 9,617,040 8,407,772 2,162,146,796
Total Drilling Fluids -
TOTAL ZD/ONSHORE DISPOSAL LOADINGS ...
Onsite Injection ...
Haul/Onshore Disposal ...
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
2,144,121,984 9,617,040 8,407,772 2,162,146,796
DISCHARGE S >ยป
2,111,109,104
1,981,526,694
2,162,146,796
total toxic/non-conv: baseline
BAT 1 & 2
BATS
Incr BAT 1 &2
Incr BAT 3
248,197,619 total Conventionals:
232,961,301
254,183,755
(15,236,318)
5,986,136
baseline
BAT 1 & 2
BATS
Incr BAT 1 &2
Incr BAT 3
1,862,911,486
1,748,565,393
1,907,963,040
(114,346,092)
45,051,555
A-99
-------
WORKSHEET H:
Baseline (WBF) Existing Sources - Upper Bound WBF Failure Rate (10.73%)
Summary of Total Baseline Water-Based Fluids Onslte Discharge and Zero Discharge/Onshore Disposal Loadings
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ZD/ONSHORE DISPOSAL LOADINGS
Onsite Injection
Haul/Onshore Disposal
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
COM CA AK
739,934,175 3,634,290 3,472,399
885,711,582 4,799,763 3,959,487
217,042,905 1,182,987 975,886
1,102,754,487 5,982,750 4,935,373
1,842,688,662 9,617,040 8,407,772
98,271,592
123,128,198
28,995,841
152,124,039
250,395,631
22,369,563
228,026,068
2,093,084,293 9,617,040 8,407,772
Total
747,040,864
894,470,832
219,201,778
1,113,672,610
1,860,713,474
98,271,592
123,128,198
28,995,841
152,124,039
250,395,631
22,369,563
228,026,068
2,111,109,104
BAT 1 & 2 (WBF) Existing Sources - Upper Bound WBF Failure Rate (10.73%)
Summary of Total Baseline Water-Based Fluids Onslte Discharge and Zero Discharge/Onshore Disposal Loadings
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
TOTAL ZD/ONSHORE DISPOSAL
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
LOADINGS
Onsite Injection
Haul/Onshore Disposal
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
GOM
694,720,056
831,497,994
203,762,708
1,035,260,702
1,729,980,757
91,599,697
114,881,708
27,039,721
141,921,429
233,521,125
20,959,454
212,561,671
1,963,501,883
CA
3,634,290
4,799,763
1,182,987
5,982,750
9,617,040
0
0
0
0
0
0
0
9,617,040
AK
3,472,399
3,959,487
975,886
4,935,373
8,407,772
0
0
0
0
0
0
0
8,407,772
Total
701,826,745
840,257,244
205,921,580
1,046,178,824
1,748,005,569
91,599,697
114,881,708
27,039,721
141,921,429
233,521,125
20,959,454
212,561,671
1,981,526,694
A-100
-------
WORKSHEET H:
BAT 3 (WBF) Existing Sources - Upper Bound WBF Failure Rate (10.73%)
Summary of Total Baseline Water-Based Fluids Onslte Discharge and Zero Discharge/Onshore Disposal Loadings
COM CA AK
Total
ONSITE DISCHARGE: Loadings, Cuttings Conventionals
ONSITE DISCHARGE: Loadings, Fluids Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings Conventionals
ZD/ONSHORE DISPOSAL: Loadings, Fluids Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ZD/ONSHORE DISPOSAL LOADINGS
Onsite Injection
Haul/Onshore Disposal
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
758,074,474 3,634,290 3,472,399
907,414,308 4,799,763 3,959,487
222,347,169 1,182,987 975,886
1,129,761,477 5,982,750 4,935,373
1,887,835,951 9,617,040 8,407,772
100,585,269
126,023,050
29,677,713
155,700,764
256,286,033
22,886,577
233,399,455
2,144,121,984 9,617,040 8,407,772
765,181,163
916,173,558
224,506,042
1,140,679,600
1,905,860,763
100,585,269
126,023,050
29,677,713
155,700,764
256,286,033
22,886,577
233,399,455
2,162,146,796
DISCHARGE S >ยป
1,860,713,474
1,748,005,569
1,905,860,763
total toxic/non-conv: baseline
BAT 1 & 2
BATS
Incr BAT 1 &2
Incr BAT 3
219,201,778 total Conventionals:
205,921,580
224,506,042
(13,280,197)
5,304,264
baseline
BAT 1 & 2
BATS
Incr BAT 1 &2
Incr BAT 3
1,641,511,696
1,542,083,989
1,681,354,721
(99,427,707)
39,843,025
A-101
-------
WORKSHEET AA: SUMMARY OF EXISTING SOURCE DRILLING FLUID DISPOSAL LOADINGS BY REGION, OPTION, FLUID TYPE, AND LOCATION
Gulf of Mexico โ Lower Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
2,093,084,293
237,890,828
0
2,330,975,121
1,963,501,883
259,628,314
0
2,223,130,197
1,963,501,883
252,066,749
0
2,215,568,632
2,144,121,984
0
0
2,144,121,984
Zero Discharge Alternative Disposal Methods
Onsite Injection
0
0
11,862,178
11,862,178
0
0
7,092,172
7,092,172
0
0
7,092,172
7,092,172
0
0
36,101,236
36,101,236
Haul/ Onshore Disposal
0
0
47,448,711
47,448,711
0
0
28,368,689
28,368,689
0
7,561,565
28,368,689
35,930,254
0
19,766,219
204,866,907
224,633,126
Total Media
Pollutant Loadings
2,093,084,293
237,890,828
59,310,889
2,390,286,010
1,963,501,883
259,628,314
35,460,861
2,258,591,058
1,963,501,883
259,628,314
35,460,861
2,258,591,058
2,144,121,984
19,766,219
240,968,143
2,404,856,346
Net Loadings (Reductions), Ibs
Onsite (marine)
Discharges
-107,844,924
-115,406,489
-186,853,137
Onshore
Disposal
-23,850,028
-16,288,463
201,423,473
All Media
Totals
-131,694,952
-131,694,952
14,570,336
California โ Lower Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
9,617,040
0
0
9,617,040
9,617,040
0
0
9,617,040
9,617,040
0
0
9,617,040
9,617,040
0
0
9,617,040
Zero Discharge Alternative Disposal Methods
Onsite Injection
0
0
1,945,148
1,945,148
0
0
1,945,148
1,945,148
0
0
1,945,148
1,945,148
0
0
1,945,148
1,945,148
Haul/ Onshore Disposal
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total Media
Pollutant Loadings
9,617,040
0
1,945,148
11,562,188
9,617,040
0
1,945,148
11,562,188
9,617,040
0
1,945,148
11,562,188
9,617,040
0
1,945,148
11,562,188
Net Loadings (Reductions), Ibs
Onsite (marine)
Discharges
0
0
0
Onshore
Disposal
0
0
0
All Media
Totals
.
-
A-102
-------
WORKSHEET AA: SUMMARY OF EXISTING SOURCE DRILLING FLUID DISPOSAL LOADINGS BY REGION, OPTION, FLUID TYPE, AND LOCATION
Cook Inlet, Alaska - Lower Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
8,407,772
0
0
8,407,772
8,407,772
552,796
0
8,960,568
8,407,772
536,696
0
8,944,468
8,407,772
0
0
8,407,772
Zero Discharge Alternative Disposal Methods
Onsite Injection
0
0
1,945,148
1,945,148
0
0
1,316,784
1,316,784
0
16,100
1,316,784
1,332,884
0
0
1,945,148
1,945,148
Haul/ Onshore Disposal
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total Media
Pollutant Loadings
8,407,772
0
1,945,148
10,352,920
8,407,772
552,796
1,316,784
10,277,352
8,407,772
552,796
1,316,784
10,277,352
8,407,772
0
1,945,148
10,352,920
Net Loadings (Reductions), Ibs
Onsite (marine)
Discharges
552,796
536,696
0
Onshore
Disposal
-628,364
-612,264
0
All Media
Totals
-75,568
-75,568
-
TOTAL - Lower Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
2,111,109,104
237,890,828
0
2,348,999,932
1,981,526,694
260,181,110
0
2,241,707,804
1,981,526,694
252,603,445
0
2,234,130,139
2,162,146,796
0
0
2,162,146,796
Zero Discharge Alternative Disposal Methods
Onsite Injection
0
0
15,752,474
15,752,474
0
0
10,354,104
10,354,104
0
16,100
10,354,104
10,370,204
0
0
39,991,532
39,991,532
Haul/ Onshore Disposal
0
0
47,448,711
47,448,711
0
0
28,368,689
28,368,689
0
7,561,565
28,368,689
35,930,254
0
19,766,219
204,866,907
224,633,126
Total Media
Pollutant Loadings
2,111,109,104
237,890,828
63,201,185
2,412,201,117
1,981,526,694
260,181,110
38,722,793
2,280,430,597
1,981,526,694
260,181,110
38,722,793
2,280,430,597
2,162,146,796
19,766,219
244,858,439
2,426,771,454
Net Loadings (Reductions), Ibs
Onsite (marine)
Discharges
-107,292,128
-114,869,793
-186,853,137
Onshore
Disposal
-24,478,392
-16,900,727
201,423,473
All Media
Totals
-131,770,520
-131,770,520
14,570,336
A-103
-------
WORKSHEET AA: SUMMARY OF EXISTING SOURCE DRILLING FLUID DISPOSAL LOADINGS BY REGION, OPTION, FLUID TYPE, AND LOCATION
INCREMENTAL LOADINGS (REDUCTIONS) Existing Sources
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
-129,582,410
22,290,282
0
-107,292,128
-129,582,410
14,712,617
0
-114,869,793
51,037,691
-237,890,828
0
-186,853,137
Zero Discharge Alternative Disposal Methods
Onsite Injection
0
0
-5,398,370
-5,398,370
0
16,100
-5,398,370
-5,382,270
0
0
24,239,058
24,239,058
Haul/ Onshore Disposal
0
0
-19,080,022
-19,080,022
0
7,561,565
-19,080,022
-11,518,457
0
19,766,219
157,418,196
177,184,415
Total Media
Pollutant Loadings
-129,582,410
22,290,282
-24,478,392
-131,770,520
-129,582,410
22,290,282
-24,478,392
-131,770,520
51,037,691
-218,124,609
181,657,254
14,570,336
SUMMARY TOTAL LOADINGS (REDUCTIONS)
Existing Sources
Baseline
BAT 1
BAT 2
BAT 3
total
total
total
total
Onsite
Discharge
2,348,999,932
2,241,707,804
2,234,130,139
2,162,146,796
Zero Discharge Alternative Disposal Methods
Onsite Injection
15,752,474
10,354,104
10,370,204
39,991,532
Haul/ Onshore Disposal
47,448,711
28,368,689
35,930,254
224,633,126
Total Media
Pollutant Loadings
2,412,201,117
2,280,430,597
2,280,430,597
2,426,771,454
SUMMARY INCREMENTAL LOADINGS (REDUCTIONS)
Existing Sources
Baseline
BAT 1
BAT 2
BAT 3
total
total
total
Onsite
Discharge
NA
-107,292,128
-114,869,793
-186,853,137
Zero Discharge Alternative Disposal Methods
Onsite Injection
NA
-5,398,370
-5,382,270
24,239,058
Haul/ Onshore Disposal
NA
-19,080,022
-11,518,457
177,184,415
Total Media
Pollutant Loadings
NA
-131,770,520
-131,770,520
14,570,336
A-104
-------
WORKSHEET No. I:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUIDS: CONVENTIONAL POLLUTANTS FROM ZERO DISCHARGE CUTTINGS,
(INJECTED ONSITE OR HAULED FOR ONSHORE DISPOSAL) DUE TO PROJECTED SHEEN OR TOXICITY TEST FAILURES, NEW SOURCES
POLLUTANTS FROM CUTTINGS HAULED OR INJECTED
(Coventionals)
( from ODD: Table XI-2, p XI-4)
well depth, TD
no. wells , total by region (from Exh. 2)
% WBF (total - OBF) wells failing permit limits (from Exh. 1)
No. WBF wells zero discharge cuttings
Cuttings (bbl) per well
CUTTINGS TSS ANALYSIS:
Ibs TSS /bbl (from Exh. 3)
Ibs TSS perwell
total Ibs TSS
Gulf of Mexico
California
Alaska
total volume cuttings, bbl
Shallow Well
GOM
38
5.94% |
2
1,475
CA
7.607
6.75%|
0
1,242
AK
10,633
4.77%
0
1,480
812,209
1,624,418
683,907
0
814,962
0
Deep Well
GOM
38
4.85%|
2
2,458
1,353,498
2,706,995
CA
0
1,437
791,284
0
AK
12,354
5.84%
0
2,413
551
1,328,718
0
Totals
38
4
4,331,413
4,331,413
2,950
Gulf of Mexico
California
Alaska
CUTTINGS OIL ANALYSIS:
% wells , by type and region (from Exh. 1)
total no. wells, by region (from Exh. 2)
no. wells, by type and region
% wells using MO spot or lube, zero discharge
no. wells zero discharge
cuttings perwell, bbl
fraction adherent fluid
volume adherent fluid, perwell, bbl
MO, Ibs per bbl
MO, Ibs per well
total Ibs MO
Gulf of Mexico
California
Alaska
total volume MO, bbl
51.00%|
38
19
5.59%|
2
74.0
666
1,332
148
Gulf of Mexico
California
Alaska
TOTAL CONVENTIONAL POLLUTANTS
Ibs conventional pollutants zero discharge
0
58.00%|
0
6.75%|
0
62
558
0
0
0
4,916
41.00%
0
4.77%
*
666
0
49.00%|
38
19
4.56%|
123
1,107
2,214
0 246
1,625,750
Gulf of Mexico
California
Alaska
% injected onsite onsite
% hauled onshore onshore
Ibs pollutants injected
Ibs pollutants disposed onshore
20%
80%
325,150
1,300,600
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
bbl conventional pollutants zero discharged 3,098
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
0
20%
80%
0
0
0
0
0
42.00%|
0
4.16%|
0
1,437
5.0%
72
648
0
0
0
7,866
7,866
59.00%
0
5.84%
0
2,413
5.0%
121
1,089
0
38
4
3,546
3,546
0 394
394
2,709,209
100%
0%
0
0
0%
100%
0
2,709,209
0 5,162
0
0%
100%
0
0
0
0
4,334,959
4,334,959
100%
0%
0
0
325,150
4,009,809
325,150
4,009,809
0 8,260
620
7,640
-------
WORKSHEET No. J:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUIDS: CONVENTIONAL POLLUTANTS FROM DRILLING FLUIDS ZERO DISCHARGED
(INJECTED ONSITE OR HAULED FOR ONSHORE DISPOSAL) DUE TO PROJECTED SHEEN OR TOXICITY TEST FAILURES, NEW SOURCES
POLLUTANTS FROM DRILLING FLUIDS HAULED OR INJECTED
(Conventionals)
( from ODD: Table XI-2, p XI-4)
Well Depth, TD
No. wells , total
No. wells hauling fluids
Drilling fluids (bbl) per well
WB FLUIDS TSS ANALYSIS:
Ibs TSS / bbl
Ibs TSS per well
total Ibs TSS
Gulf of Mexico
California
Alaska
total volume, bbl, WB fluids
Gulf of Mexico
California
Alaska
WB FLUIDS OIL ANALYSIS:
% wells using MO spot or lube, hauling
no. wells using hauling
WB fluids discharged per well, bbl
MO, Ibs per bbl
MO, Ibs per well
total Ibs MO
Gulf of Mexico
California
Alaska
total volume MO, bbl
Gulf of Mexico
California
Alaska
TOTAL CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants zero discharge
Gulf of Mexico
California
Alaska
% injected onsite onsite
% hauled onshore onshore
Ibs pollutants injected
Ibs pollutants disposed onshore
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
bbl conventional pollutants zero discharged
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Alaska disposed onshore
Shallow Well
GOM CA AK
10,559 7,607 10,633
38
200
6,938 5,939 6,963
153 153 153
1,061,514 908,667 1,065,339
2,123,028
13,876
5.59% 6.75% 4.77%
2
6,938 5,939 6,963
999
62,442 53,451 62,667
124,884
419
837
2,247,912
20% 20% 100%
80% 80% 0%
449,582
1,798,330
14,295
Deep Well
GOM CA AK
13,037 10,082 12,354
38
200
9,752 6,777 9,458
153 153 153
1,492,056 1,036,881 1,447,074
2,984,112
19,504
4.56% 4.16% 5.84%
2
9,752 6,777 9,458
999
87,768 60,993 85,122
175,536
589
1,177
3,159,648
0% 0% 100%
100% 100% 0%
3,159,648
20,093
Totals
38
4
5,107,140
5,107,140
33,380
33,380
4
9
85,122
300,420
300,420
1,007
2,014
5,407,560
5,407,560
449,582
4,957,978
449,582
4,957,978
5,407,560
34,387
2,859
-
-------
WORKSHEET No. K:
POLLUTANT LOADINGS FROM WATER-BASED DRILLING FLUID: TOXIC/NON-CONVENTIONAL POLLUTANTS FROM ZERO DISCHARGE
DRILLING FLUIDS (INJECTED ONSITE OR HAULED FOR ONSHORE DISPOSAL) DUE TO SHEEN/TOXICITY TEST FAILURES, NEW SOURCES
POLLUTANTS FROM DISCHARGED DRILLING FLUIDS
(Toxics & Non-conventionals)
TOXICS HAULED
( from ODD: Table XI-2, p XI-4)
Well Depth, TD
No. wells , total
No. wells discharging cuttings
Drilling fluidsDischarqed (bbl) per well
WB FLUIDS TOXICS/NON-CONVENTIONALS:
Ibstoxics/non-conventionals/ bbl (from Exh. 3)
Ibs toxics/non-conventionals per well
total Ibs toxics/non-conventionals
Shallow Well
GOM CA AK
10,559 7,607 10,633
38
200
6,938 5,939 6,963
37.7 37.7 37.7
261,629 223,957 262,572
523,258
Deep Well
GOM CA A
13,037 10,082
38
2 0
9,752 6,777
37.7 37.7
367,744 255,558
735,487
Gulf of Mexico
California
Alaska
total volume, bbl, WB fluids 13,876 - - 19,504
Gulf of Mexico
California
Alaska
WB FLUIDS MINERAL OIL TOXICS/NON-CONVENTIONALS:
% wells using MO spot or lube, discharging (from Exh. 1)
no. wells using MO and discharging (from Exh. 5A)
WB fluids discharged per well, bbl
mineral oil toxics, Ib / bbl (from Exh. 3)
mineral oil toxics, Ibs / well
total Ibs mineral oil toxics
5.59% 0.00% 0.00%
2
6,938 5,939 6,963
9.000 9.000 9.000
62,442 53,451 62,667
124,884
0.00% 0.00%
2
9,752 6,777
9.000 9.000
87,768 60,993
175,536
Gulf of Mexico
California
Alaska
total volume MO, bbl 419 - - 589
GulfofMexico 837 - - 1,177
California
Alaska
TOTAL TOXIC/NON-CONVENTIONAL POLLUTANTS:
Ibs conventional pollutants discharged 648,142 - - 911,023
Gulf of Mexico
California
Alaska
% injected onsite onsite
% hauled onshore onshore
Ibs pollutants injected
Ibs pollutants disposed onshore
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
20% 20% 100%
80% 80% 0%
129,628
518,514
0% 0%
100% 100%
911,023
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
bbl conventional pollutants discharged
14,295
20,093
Gulf of Mexico injected onsite
California injected onsite
Alaska injected onsite
Gulf of Mexico disposed onshore
California disposed onshore
Alaska disposed onshore
Totals
<
12,354
38
0 4
9,458
37.7
356,657
1 ,258,745
1,258,745
33,380
33,380
0.00%
4
9,458
9.000
85,122 412,443
300,420
300,420
1,007
2,014
1,559,165
1,559,165
100%
0%
129,628
1 ,429,537
129,628
1,429,537
1,559,165
34,387
2,859
31,528
A-107
-------
WORKSHEET L:
Baseline (WBF) New Sources - Lower Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onsite Discharge and Zero Discharge/Onshore Disposal Loadings
ONSITE
ONSITE
DISCHARGE: Loadings, Cuttings
DISCHARGE: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE
ZD/ONSHORE
DISPOSAL: Loadings, Cuttings
DISPOSAL: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
COM CA AK
37,095,021
44,642,502
11,166,082
55,808,584
92,903,606
.
.
Total
37,095,021
44,642,502
11,166,082
55,808,584
92,903,606
-
-
TOTAL ZD/ONSHORE DISPOSAL LOADINGS ...
Onsite Injection ...
Haul/Onshore Disposal ...
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
92,903,606
92,903,606
BAT 1 & 2 (WBF) New Sources - Lower Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onsite Discharge and Zero Discharge/Onshore Disposal Loadings
COM CA AK Total
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
34,928,208 - - 34,928,208
42,001,164 - - 42,001,164
10,533,551 - - 10,533,551
52,534,715 - - 52,534,715
87,462,923 - - 87,462,923
.
Total Drilling Fluids -
TOTAL ZD/ONSHORE DISPOSAL LOADINGS ...
Onsite Injection ...
Haul/Onshore Disposal ...
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
87,462,923 - - 87,462,923
A-108
-------
WORKSHEET L:
BAT 3 (WBF) New Sources - Lower Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onsite Discharge and Zero Discharge/Onshore Disposal Loadings
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
Total Drilling Fluids
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Conventionals
Conventionals
Toxics + Non-conventionals
COM CA
40,072,937
48,257,586
12,057,084
60,314,670
100,387,607
-
AK Total
40,072,937
48,257,586
12,057,084
60,314,670
100,387,607
-
Total Drilling Fluids ...
TOTAL ZD/ONSHORE DISPOSAL LOADINGS ...
Onsite Injection ...
Haul/Onshore Disposal ...
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
100,387,607
100,387,607
92,903,606
87,462,923
100,387,607
total toxic/non-conv: baseline
BAT 1 & 2
BATS
IncrBAT! &2
IncrBATS
11,166,082 total Conventionals:
10,533,551
12,057,084
(632,532)
891 ,002
baseline
BAT 1 & 2
BATS
IncrBAT! &2
IncrBATS
81,737,523
76,929,372
88,330,523
(4,808,151)
6,592,999
A-109
-------
WORKSHEET M:
Baseline (WBF) New Sources - Upper Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onsite Discharge and Zero Discharge/Onshore Disposal Loadings
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Toxics
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Toxics
Conventionals
Conventionals
+โข Non-conventionals
Total Drilling Fluids
Conventionals
Conventionals
+โข Non-conventionals
Total Drilling Fluids
TOTAL ZD/ONSHORE DISPOSAL LOADINGS
Onsite Injection
Haul/Onshore Disposal
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
COM CA
32,760,063
39,234,942
9,606,917
48,841,859
81,601,922
4,334,959
5,407,560
1,559,165
6,966,725
1 1 ,301 ,684
904,361
10,397,324
92,903,606
AK Total
32,760,063
39,234,942
9,606,917
48,841,859
81,601,922
4,334,959
5,407,560
1,559,165
6,966,725
1 1 ,301 ,684
904,361
10,397,324
92,903,606
BAT 1 & 2 (WBF) New Sources - Upper Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onsite Discharge and Zero Discharge/Onshore Disposal Loadings
COM CA AK
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Toxics
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Toxics
TOTAL ZD/ONSHORE DISPOSAL LOADINGS
Conventionals
Conventionals
+ Non-conventionals
Total Drilling Fluids
Conventionals
Conventionals
+ Non-conventionals
Total Drilling Fluids
Onsite Injection
Haul/Onshore Disposal
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
30,593,249
36,593,604
8,974,385
45,567,989
76,161,239
4,334,959
5,407,560
1,559,165
6,966,725
1 1 ,301 ,684
904,361
10,397,324
87,462,923
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
30,593,249
36,593,604
8,974,385
45,567,989
76,161,239
4,334,959
5,407,560
1,559,165
6,966,725
1 1 ,301 ,684
904,361
10,397,324
87,462,923
A-110
-------
WORKSHEET M:
BAT 3 (WBF) New Sources - Upper Bound WBF Failure Rate (0%)
Summary of Total Baseline Water-Based Fluids Onsite Discharge and Zero Discharge/Onshore Disposal Loadings
ONSITE DISCHARGE: Loadings, Cuttings
ONSITE DISCHARGE: Loadings, Fluids
Toxics
TOTAL ONSITE DISCHARGE LOADINGS
ZD/ONSHORE DISPOSAL: Loadings, Cuttings
ZD/ONSHORE DISPOSAL: Loadings, Fluids
Toxics
Conventionals
Conventionals
+โข Non-conventionals
Total Drilling Fluids
Conventionals
Conventionals
+โข Non-conventionals
Total Drilling Fluids
TOTAL ZD/ONSHORE DISPOSAL LOADINGS
Onsite Injection
Haul/Onshore Disposal
TOTAL ONSITE AND ZD/ONSHORE BASELINE WBF POLLUTANT LOADINGS
COM CA
35,737,978
42,850,026
10,497,919
53,347,945
89,085,922
4,334,959
5,407,560
1,559,165
6,966,725
1 1 ,301 ,684
904,361
10,397,324
100,387,607
AK Total
35,737,978
42,850,026
10,497,919
53,347,945
89,085,922
4,334,959
5,407,560
1,559,165
6,966,725
1 1 ,301 ,684
904,361
10,397,324
100,387,607
81,601,922
76,161,239
89,085,922
total toxic/non-conv: baseline
BAT 1 & 2
BATS
IncrBAT! &2
IncrBATS
9,606,917 total Conventionals:
8,974,385
10,497,919
(632,532)
891 ,002
baseline
BAT 1 & 2
BATS
IncrBAT! &2
IncrBATS
71,995,005
67,186,853
78,588,004
(4,808,151)
6,592,999
A-111
-------
WORKSHEET BB: NEW SOURCE DRILLING FLUID DISPOSAL LOADINGS BY REGION, OPTION, FLUID TYPE, AND LOCATION
Gulf of Mexico โ Lower WBF Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
92,903,606
17,405,127
0
110,308,733
87,462,923
20,241,106
0
107,704,029
87,462,923
19,722,488
0
107,185,411
100,387,607
0
0
100,387,607
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
0
0
0
0
0
0
0
0
0
0
0
0
879,710
879,710
aul/ Onshore Dispos;
0
0
1,256,728
1,256,728
0
0
628,364
628,364
0
518,618
628,364
1,146,982
0
2,852,661
11,125,935
13,978,597
Total Media
Pollutant Loadings
92,903,606
17,405,127
1,256,728
111,565,461
87,462,923
20,241,106
628,364
108,332,393
87,462,923
20,241,106
628,364
108,332,393
100,387,607
2,852,661
12,005,645
115,245,913
Onsite (marine) Onshore
Discharges Disposal
-2,604,704 -628,364
-3,123,322 -109,746
-9,921,126 13,601,578
All Media
Totals
(3,233,068)
(3,233,068)
3,680,452
California โ Lower WBF Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
Zero Discharge Alternative Disposal Methoc
Onsite Injection
aul/ Onshore Dispos;
Total Media
Pollutant Loadings
Onsite (marine) Onshore
Discharges Disposal
0 0
0 0
0 0
All Media
Totals
.
.
-
A-112
-------
Cook Inlet, AK - Lower WBF Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
Zero Discharge Alternative Disposal Methoc
Onsite Injection
aul/ Onshore Dispos;
Total Media
Pollutant Loadings
Onsite (marine) Onshore
Discharges Disposal
0 0
0 0
0 0
All Media
Totals
.
.
-
Total โ Lower WBF Failure Rate
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
92,903,606
17,405,127
0
110,308,733
87,462,923
20,241,106
0
107,704,029
87,462,923
19,722,488
0
107,185,411
100,387,607
0
0
100,387,607
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
0
0
0
0
0
0
0
0
0
0
0
0
879,710
879,710
aul/ Onshore Dispos;
0
0
1,256,728
1,256,728
0
0
628,364
628,364
0
518,618
628,364
1,146,982
0
2,852,661
11,125,935
13,978,597
Total Media
Pollutant Loadings
92,903,606
17,405,127
1,256,728
111,565,461
87,462,923
20,241,106
628,364
108,332,393
87,462,923
20,241,106
628,364
108,332,393
100,387,607
2,852,661
12,005,645
115,245,913
Onsite (marine) Onshore
Discharges Disposal
-2,604,704 -628,364
-3,123,322 -109,746
-9,921,126 13,601,578
All Media
Totals
(3,233,068)
(3,233,068)
3,680,452
A-113
-------
INCREMENTAL LOADINGS (REDUCTIONS)
Lower WBF Failure Rate, New Sources
Baseline
wbf
sbf
obf
total
BAT 1
wbf
sbf
obf
total
BAT 2
wbf
sbf
obf
total
BAT 3
wbf
sbf
obf
total
Onsite
Discharge
-5,440,683
2,835,979
0
-2,604,704
-5,440,683
2,317,361
0
-3,123,322
7,484,001
-17,405,127
0
-9,921,126
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
0
0
0
0
0
0
0
0
879,710
879,710
aul/ Onshore Dispos;
0
0
-628,364
-628,364
0
518,618
-628,364
-109,746
0
2,852,661
9,869,207
12,721,869
Total Media
Pollutant Loadings
-5,440,683
2,835,979
-628,364
-3,233,068
-5,440,683
2,835,979
-628,364
-3,233,068
7,484,001
-14,552,466
10,748,917
3,680,452
SUMMARY TOTAL LOADINGS (REDUCTIONS):
Lower WBF Failure Rate, New Sources
Baseline
BAT 1
total
total
BAT 2
BAT 3
total
total
Onsite
Discharge
110,308,733
107,704,029
107,185,411
100,387,607
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
0
879,710
aul/ Onshore Dispos;
1,256,728
628,364
1,146,982
13,978,597
Total Media
Pollutant Loadings
111,565,461
108,332,393
108,332,393
115,245,913
SUMMARY INCREMENTAL LOADINGS (REDUCTIONS):
Lower WBF Failure Rate, New Sources
Baseline
BAT 1
total
BAT 2
BAT 3
total
total
Onsite
Discharge
NA
-2,604,704
-3,123,322
-9,921,126
Zero Discharge Alternative Disposal Methoc
Onsite Injection
NA
0
0
879,710
aul/ Onshore Dispos;
NA
-628,364
-109,746
12,721,869
Total Media
Pollutant Loadings
NA
-3,233,068
-3,233,068
3,680,452
A-114
-------
WORKSHEET CC: NEW AND EXISTING SOURCE DRILLING FLUID DISPOSAL LOADINGS BY REGION, OPTION, FLUID TYPE, AND LOCATION
Gulf of Mexico โ Lower WBF Failure Rate
Baseline
BAT 1
BAT 2
BAT 3
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
Onsite
Discharge
2,185,987,899
255,295,955
0
2,441,283,854
2,050,964,806
279,869,420
0
2,330,834,226
2,050,964,806
271,789,237
0
2,322,754,043
2,244,509,591
0
0
2,244,509,591
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
11,862,178
11,862,178
0
0
7,092,172
7,092,172
0
0
7,092,172
7,092,172
0
0
36,980,946
36,980,946
aul/ Onshore Dispos;
0
0
48,705,439
48,705,439
0
0
28,997,053
28,997,053
0
8,080,183
28,997,053
37,077,236
0
22,618,880
215,992,842
238,611,723
Total Media
Pollutant Loadings
2,185,987,899
255,295,955
60,567,617
2,501,851,471
2,050,964,806
279,869,420
36,089,225
2,366,923,451
2,050,964,806
279,869,420
36,089,225
2,366,923,451
2,244,509,591
22,618,880
252,973,788
2,520,102,259
Onsite (marine) Onshore
Discharges Disposal
-110,449,628 -24,478,392
-118,529,811 -16,398,209
-196,774,263 215,025,051
All Media
Totals
(134,928,020)
(134,928,020)
18,250,789
California โ Lower WBF Failure Rate
Baseline
BAT 1
BAT 2
BAT 3
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
Onsite
Discharge
9,617,040
0
0
9,617,040
9,617,040
0
0
9,617,040
9,617,040
0
0
9,617,040
9,617,040
0
0
9,617,040
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
1,945,148
1,945,148
0
0
1,945,148
1,945,148
0
0
1,945,148
1,945,148
0
0
1,945,148
1,945,148
aul/ Onshore Dispos;
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total Media
Pollutant Loadings
9,617,040
0
1,945,148
11,562,188
9,617,040
0
1,945,148
11,562,188
9,617,040
0
1,945,148
11,562,188
9,617,040
0
1,945,148
11,562,188
Onsite (marine) Onshore
Discharges Disposal
0 0
0 0
0 0
All Media
Totals
.
.
-
A-115
-------
Alaska โ lower WBF Failure Rate
Baseline
BAT 1
BAT 2
BAT 3
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
Onsite
Discharge
8,407,772
0
0
8,407,772
8,407,772
552,796
0
8,960,568
8,407,772
536,696
0
8,944,468
8,407,772
0
0
8,407,772
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
1,945,148
1,945,148
0
0
1,316,784
1,316,784
0
16,100
1,316,784
1,332,884
0
0
1,945,148
1,945,148
aul/ Onshore Dispos;
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total Media
Pollutant Loadings
8,407,772
0
1,945,148
10,352,920
8,407,772
552,796
1,316,784
10,277,352
8,407,772
552,796
1,316,784
10,277,352
8,407,772
0
1,945,148
10,352,920
Onsite (marine) Onshore
Discharges Disposal
552,796 -628,364
536,696 -612,264
0 0
All Media
Totals
(75,568)
(75,568)
-
TOTAL โ Lower Failure Rate
Baseline
BAT 1
BAT 2
BAT 3
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
Onsite
Discharge
2,204,012,710
255,295,955
0
2,459,308,665
2,068,989,617
280,422,216
0
2,349,411,833
2,068,989,617
272,325,933
0
2,341,315,550
2,262,534,402
0
0
2,262,534,402
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
15,752,474
15,752,474
0
0
10,354,104
10,354,104
0
16,100
10,354,104
10,370,204
0
0
40,871,242
40,871,242
aul/ Onshore Dispos;
0
0
48,705,439
48,705,439
0
0
28,997,053
28,997,053
0
8,080,183
28,997,053
37,077,236
0
22,618,880
215,992,842
238,611,723
Total Media
Pollutant Loadings
2,204,012,710
255,295,955
64,457,913
2,523,766,578
2,068,989,617
280,422,216
39,351,157
2,388,762,990
2,068,989,617
280,422,216
39,351,157
2,388,762,990
2,262,534,402
22,618,880
256,864,084
2,542,017,367
Onsite (marine) Onshore
Discharges Disposal
-109,896,832 -25,106,756
-117,993,115 -17,010,473
-196,774,263 215,025,051
All Media
Totals
(135,003,588)
(135,003,588)
18,250,789
A-116
-------
INCREMENTAL LOADINGS (REDUCTIONS)
ALL SOURCES, Lower WBF Failure Rate
Baseline
BAT 1
BAT 2
BAT 3
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
wbf
sbf
obf
total
Onsite
Discharge
-135,023,093
25,126,261
0
-109,896,832
-135,023,093
17,029,978
0
-117,993,115
58,521,692
-255,295,955
0
-196,774,263
Zero Discharge Alternative Disposal Methoc
Onsite Injection
0
0
-5,398,370
-5,398,370
0
16,100
-5,398,370
-5,382,270
0
0
25,118,768
25,118,768
aul/ Onshore Dispos;
0
0
-19,708,386
-19,708,386
0
8,080,183
-19,708,386
-11,628,203
0
22,618,880
167,287,403
189,906,284
Total Media
Pollutant Loadings
-135,023,093
25,126,261
-25,106,756
-135,003,588
-135,023,093
25,126,261
-25,106,756
-135,003,588
58,521,692
-232,677,075
192,406,171
18,250,789
SUMMARY TOTAL LOADINGS (REDUCTIONS)
ALL SOURCES, Lower WBF Failure Rate
Baseline
BAT 1
total
total
BAT 2
BAT 3
total
total
Onsite
Discharge
2,459,308,665
2,349,411,833
2,341,315,550
2,262,534,402
Zero Discharge Alternative Disposal Methoc
Onsite Injection
15,752,474
10,354,104
10,370,204
40,871,242
aul/ Onshore Dispos;
48,705,439
28,997,053
37,077,236
238,611,723
Total Media
Pollutant Loadings
2,523,766,578
2,388,762,990
2,388,762,990
2,542,017,367
SUMMARY INCREMENTAL LOADINGS (REDUCTIONS)
ALL SOURCES, Lower WBF Failure Rate
Baseline
BAT 1
total
BAT 2
BAT 3
total
total
Onsite
Discharge
NA
-109,896,832
-117,993,115
-196,774,263
Zero Discharge Alternative Disposal Methoc
Onsite Injection
NA
-5,398,370
-5,382,270
25,118,768
aul/ Onshore Dispos;
NA
-19,708,386
-11,628,203
189,906,284
Total Media
Pollutant Loadings
NA
-135,003,588
-135,003,588
18,250,789
A-117
-------
SBF Drilling Waste Pollutant Concentrations
Pollutant Name
Conventional Pollutants
Total Oil as SBF Basefluid
Total Oil as Formation Oil
Total Oil (SBF Basefluid + Form. Oil)
TSS as barite
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
Phenol (ug/g)
Priority Pollutants, Metals
Cadmium
Mercury
Antimony
Arsenic
Berylium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Non-Conventional Pollutants
Aluminum
Barium ****
Iron
Tin
Titanium
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Alkylated phenols (ug/g)
Total biphenyls
Total dibenzothiophenes (ug/g)
Average Concentration of Pollutants
in Drilling Waste
mg/ml *
1.43
0.78
1.85
6
mg/kg -barite
1.1
0.1
5.7
7.1
0.7
240.0
18.7
35.1
13.5
1.1
0.7
1.2
200.5
mg/kg -barite
9,069.9
588,000
15,344.3
14.6
87.5
mg/ml *
8.05
75.68
9.11
11.51
52.9
14.96
760
Ibs/bbl-drilling fluid
190.491
0.588
191.079
133.749
Ibs/bbl-drilling fluid
0.0010024
0.0005468
0.0012968
0.000003528
Ibs/lb-dry SBF ***
0.0000011
0.0000001
0.0000057
0.0000071
0.0000007
0.0002400
0.0000187
0.0000351
0.0000135
0.0000011
0.0000007
0.0000012
0.0002005
Ibs/lb-dry SBF ***
0.0090699
0.5880000
0.0153443
0.0000146
0.0000875
Ibs/bbl-drilling fluid
0.0056429
0.0530502
0.0063859
0.0080683
0.0000311
0.0104867
0.0004469
Reference
Derived from SBF
formulation and densities
(see "Model Well Input
Calculated from diesel
oil composition in
Offshore Dev. Doc.,
Table VI I-9 **
Offshore Dev. Doc.,
Table XI-6
Offshore Dev. Doc.,
Table XI-6
Calculated from diesel
oil composition in
Offshore Dev. Doc.,
Table VI I-9 **
* Except where noted
** Includes assumption of 0.2% formation oil contamination
***The dry weight (Ibs) of the barite component in a SBF is equivalent to the term "Ib-dry SBF"
**** Barium is derived from assumptions list on Page XI-8, Offshore Dev. Doc.
[i.e. barite is pure barium sulfate (BaSO4) and by molecular weights barium sulfate is 58.8% by weight barium]
A-118
-------
WORKSHEET No. O:
Revised Drilling Fluid Well Counts, to include Water-base Fluid wells
(well counts reflect number of wells < USING > not hauling or discharging the mud types listed)
%OBF > SBF
%WBF > SBF
COM
CA
AK
COM
CA
AK
Baseline
0%
20%
20%
0%
0%
0%
BAT 1
40%
40%
40%
6%
6%
6%
BAT 2
40%
40%
40%
6%
6%
6%
BATS
0%
0%
0%
0%
0%
0%
BASELINE
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
SWD
511
86
42
3
0
1
3
0
1
SWE
298
51
25
2
0
1
1
0
1
DWD
12
16
0
0
0
0
0
0
0
OWE
36
48
0
0
0
0
0
0
0
TOTALS
857
201
67
5
-
2
4
-
2
1,125
7
6
1,138
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
Note: By definition "exploratory" wells are exclud
SWD
27
5
2
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
DWD
11
15
0
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
TOTALS
38
20
2
-
-
-
-
-
-
ed from the "new sources" category
60
-
-
60
1,198
BAT OPT 1
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
SWD
479
124
25
3
0
1
3
1
0
SWE
279
74
15
2
0
1
1
0
1
DWD
11
17
0
0
0
0
0
0
0
OWE
34
49
0
0
0
0
0
0
0
TOTALS
803
264
40
5
-
2
4
1
1
1,107
7
6
1,120
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
SWD
25
8
1
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
DWD
10
16
0
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
TOTALS
35
24
1
-
-
-
-
-
-
Note: By definition "exploratory" wells are excluded from the "new sources" category
60
-
-
60
1,180
A-119
-------
BAT OPT 2
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
SWD
479
124
25
3
0
1
3
1
0
SWE
279
74
15
2
0
1
1
0
1
DWD
11
17
0
0
0
0
0
0
0
OWE
34
49
0
0
0
0
0
0
0
TOTALS |
803
264
40
5
-
2
4
1
1
1,107
7
6
1,120
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
SWD
25
8
1
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
DWD
10
16
0
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
TOTALS
35
24
1
-
-
-
-
-
-
Note: By definition "exploratory" wells are excluded from the "new sources" category
60
-
-
60
1,180
BAT OPT 3
Existing Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
SWD
511
0
128
3
0
1
3
0
1
SWE
298
0
76
2
0
1
1
0
1
DWD
17
3
8
0
0
0
0
0
0
OWE
51
8
25
0
0
0
0
0
0
TOTALS
877
11
237
5
-
2
4
-
2
1,125
7
6
1,138
New Sources
SBF/OBF/WBF
WBF
SBF
OBF
WBF
SBF
OBF
WBF
SBF
OBF
Region
Gulf of Mexico
Gulf of Mexico
Gulf of Mexico
Offshore California
Offshore California
Offshore California
Cook Inlet, Alaska
Cook Inlet, Alaska
Cook Inlet, Alaska
SWD
27
0
7
0
0
0
0
0
0
SWE
0
0
0
0
0
0
0
0
0
DWD
15
3
8
0
0
0
0
0
0
OWE
0
0
0
0
0
0
0
0
0
TOTALS
42
3
15
-
-
-
-
-
-
Note: By definition "exploratory" wells are excluded from the "new sources" category
60
-
-
60
1,198
A-120
-------
WORKSHEET No. P:
Drilling Fluid Well Counts, including Water-base Fluids Wells
Background indicates
data from L Henry
[response to CAJ
questions
(new+existing sources)
GM-Deep GM-Shal
59 836
79 142
69
138 1,047
GM
59 836
79 142
0 69
138 1,047
GULF OF MEXICO OPERATIONS
% Total % DW No.
Wells by Wells by We
DF-tvpe Wells DF-type DWD OWE Ren
Total Annual 1,127 48 76
% of SW wells 38. 7% I 61.3%
DF-tvpe
WBF
SBF
OBF
% Total Wells:
Existing Sources:
New Sources:
80% 902 25% 12 19
10% 113 75% 36 57
10% 112 0% 0 0
50% 100%
50% 0%
SW
Is
i'g SWD SWE
,003 645 358
64.3% 35.7%
871 560 311
20 13 7
112 72 40
95% 100%
5% 0%
Existing Sources:
WBF
WBF>SBF(a)
SBF
OBF>SBF(a)
OBF(a)
WBF+OBF>SBF(a)
New Sources:
WBF
WBF>SBF(a)
SBF
OBF>SBF(a)
OBF(a)
WBF+OBF>SBF(a)
BASELINE DISCHARGES
12 36
0 0
0 0
0 0
BASELINE DISCHARGES
11 0
0 0
0 0
0 0
(a) Estimate represents OBF wells = | 0% [assumed to convertto SBF underthe
an assumed! 0% (conversion of WBF wells to SBF.
511 298
0 0
0 0
0 0
27 0
0 0
0 0
2 0
0 0
basel ne scenario, plus
Background indicates well
counts from EPA NODA;
EPA counts are ignored.
but %Dev & %Expl applied
to industry data, which given
only at shallow+deep level.
857 857
0
201 201
0
67 67
1,125
38 38
0
20 20
0
2 2
60 1,185
Adi'tforwelllred'n, enhanced directional drilling, WBF>SBF: 0
0.6
0.1
0.3
0.6
0.1
0.3
Existing Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
New Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
BAT OPT 1
BAT OPT 1
(b) Estimate represents OBF we
an assumed I 6%
Existing Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
New Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
DISCHARGES
11
1
16
0
0
1
DISCHARGES
10
1
15
0
0
1
-1
34
2
47
0
0
2
0
0
0
0
0
0
s = | 40% [assumed to convert to SBF under any disch
Iconversion of WBF wells toSBF.
28
28
84
84
-11
479
32
75
17
25
49
25
2
5
1
1
3
arge options, plus
639
639
-6
279
19
45
10
15
29
0
0
0
0
0
0
803
54
183
27
40
1,107
35
3
20
1
1
60
374
374
BAT OPT 2 DISCHARGES
11
1
16
0
0
1
34
2
47
0
0
2
479
32
75
17
25
49
279
19
45
10
15
29
BAT OPT 2 DISCHARGES
(b) Estimate represents OBF we
an assumed | 6%
Existing Sources:
WBF
WBF>SBF(c)
SBF(c)
OBF>SBF(c)
OBF(c)
WBF+OBF>SBF(c )
New Sources:
WBF
WBF>SBF(c)
SBF(c)
OBF>SBF(c)
OBF(c)
WBF+OBF>SBF(c )
10
1
15
0
0
1
0
0
0
0
0
0
s = I 40% [assumed to convert to SBF under any disch
Iconversion of WBF wells toSBF.
28
28
84
84
25
2
5
1
1
3
arge options, plus
639
639
0
0
0
0
0
0
803
54
183
27
40
1,107
35
3
20
1
1
60
374
374
BAT OPT 3 (ZERO DISCHARGE)
17
0
3
0
8
0
51
0
8
0
25
0
511
0
0
0
128
0
298
0
0
0
76
0
BAT OPT 3 (ZERO DISCHARGE)
15
0
3
0
8
0
0
0
0
0
0
0
27
0
0
0
7
0
0
0
0
0
0
0
(c) Estimate represents OBF wells = | 0% [assumed to convert to SBF under zero discharge option, plus
an assumed I 0% I 0%
877
0
11
0
237
1,125
42
0
3
0
15
60
803
264
40
35
24
1
1,167
803
264
40
35
24
1
1,167
877
11
237
42
3
15
1,185
-------
Background indicates
data from L Henry
response to CAJ
questions
CA-Deep CA-Shal
0 5
0 0
0 7
CA
CA
CA
CA
CA
CA
CA
CALIFORNIA OPERATIONS
% Total % DW
Wells by Wells by
DF-type Wells DF-type
Total Annual 26
WBF(d)
SBF (d)
OBF(d)
DWD OWE
15 0
25.0% 25.0%
0% 0%
75.0% 75.0%
No. SW
Wells
Rem'g SWD SWE
11 11 0
86.8% 86.8%
0% 0%
13.2% 13.2%
Existing Sources:
WBF>SBF(a)
SBF
OBF>SBF(a)
OBF
WBF+OBF>SBF(a)
New Sources:
WBF>SBF(a)
SBF
OBF>SBF(a)
OBF
WBF+OBF>SBF(a)
BASELINE DISCHARGES
BASELINE DISCHARGES (e)
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
Background indicates
well counts from EPA
NODA; counts ignored
but %s D & E applied to
industry data given only
at shallow+deep level.
5 5
0
0 0
0
2 2
7
0 0
0
0 0
0
0 0
0 7
(a) Estimate represents OBF wells = 20% assumed to convert to SBF under the basel ne scenario, plus
an assumed 0% conversion ofWBF wellstoSBF.
(d) Currently, no SBF is used in California operations; estimated percentage of OBF+SBF usage for deep- and
shallow-water wells are based on available Gulf of Mex co usage data.
(e) There are no new sources projected for California operations.
Existing Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
New Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
BAT OPT 1 DISCHARGES
BAT OPT 1 DISCHARGES
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
3 2
0 0
0 0
0 0
1 1
0 0
0 0
0 0
0 0
0 0
0 0
0 0
5 5
0
0 0
0
2 2
7
0 0
0
0 0
0
0 0
0 7
(b) Estimate represents OBF wells = I 40% [assumed to convert to SBF under any discharge options, plus
an assumed! 6% (conversion of WBF wellstoSBF.
Existing Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
New Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
BAT OPT 2 DISCHARGES
BAT OPT 2 DISCHARGES
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
3 2
0 0
0 0
0 0
1 1
0 0
0 0
0 0
0 0
0 0
0 0
0 0
(b) Estimate represents OBF wells = I 40% [assumed to convert to SBF under any discharge options, plus
an assumed! 6% (conversion of WBF wellstoSBF.
5 5
0
0 0
0
2 2
7
0 0
0
0 0
0
0 0
0 7
Existing Sources:
WBF
WBF>SBF(c)
SBF(c)
OBF>SBF(c)
OBF(c)
WBF+OBF>SBF(c )
New Sources:
WBF
WBF>SBF(c)
SBF(c)
OBF>SBF(c)
OBF(c)
WBF+OBF>SBF(c )
BAT OPT 3 (ZERO DISCHARGE)
BAT OPT 3 (ZERO DISCHARGE)
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
3 2
0 0
0 0
0 0
1 1
0 0
0 0
0 0
0 0
0 0
0 0
0 0
(c) Estimate represents OBF wells = I 0% [assumed to convert to SBF under zero discharge option, plus
an assumed! 0% (conversion of WBF wellstoSBF.
5 5
0
0 0
0
2 2
7
0 0
0
0 0
0
0 0
0 7
-------
Background indicates
data from L Henry
[response to CAJ
questions
AK-Deep AK-Shal
0 4
0 0
0 2
0 6
AK
AK
AK
AK
AK
AK
AK
ALASKA (COOK INLET) OPERATIONS
% Total % DW
Wells by Wells by
DF-type Wells DF-type
Total Annual 8
WBF(d)
SBF (d)
OBF(d)
No
W
DWD OWE Re
1 0
25.0% 25.0%
0% 0%
75.0% 75.0%
sw
m'g SWD SWE
770
86.8% 86.8%
0% 0%
13.2% 13.2%
Existing Sources:
WBF>SBF(a)
SBF
OBF>SBF(a)
OBF
WBF+OBF>SBF(a)
New Sources:
WBF>SBF(a)
SBF
OBF>SBF(a)
OBF
WBF+OBF>SBF(a)
BASELINE DISCHARGES
BASELINE DISCHARGES (e)
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
1 1
0 0
0 0
0 0
0 0
(a) Estimate represents OBF wells = 20% assumed to convert to SBF under the basel ne scenario, plus
an assumed 0% conversion ofWBF wellstoSBF.
(d) Currently, no SBF is used in Cook Inlet operations; estimated percentage of OBF+SBF usage for deep- and
shallow-water wells are based on available Gulf of Mex co usage data.
(e) There are no new sources projected for Cook Inlet operations.
Background indicates
well counts from EPA
NODA; counts ignored
but %s D & E applied to
industry data given only
at shallow+deep level.
4 4
0
0 0
0
2 2
6
0 0
0
0 0
0
0 6
Existing Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
New Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
BAT OPT 1 DISCHARGES
BAT OPT 1 DISCHARGES
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
3 1
0 0
0 0
1 0
0 1
1 0
0 0
0 0
0 0
0 0
0 0
0 0
(b) Estimate represents OBF wells = I 40% [assumed to convert to SBF under any discharge options, plus
an assumed! 6% (conversion of WBF wellstoSBF.
4 4
0
0 1
1
1 1
6
0 0
0
0 0
0
0 0
0 6
Existing Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
New Sources:
WBF
WBF>SBF(b)
SBF(b)
OBF>SBF(b)
OBF(b)
WBF+OBF>SBF(b)
BAT OPT 2 DISCHARGES
BAT OPT 2 DISCHARGES
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
3 1
0 0
0 0
1 0
0 1
1 0
0 0
0 0
0 0
0 0
0 0
0 0
(b) Estimate represents OBF wells = I 40% [assumed to convert to SBF under any discharge options, plus
an assumed! 6% (conversion of WBF wellstoSBF.
Existing Sources:
WBF
WBF>SBF(c)
SBF(c)
OBF>SBF(c)
OBF(c)
WBF+OBF>SBF(c )
New Sources:
WBF
WBF>SBF(c)
SBF(c)
OBF>SBF(c)
OBF(c)
WBF+OBF>SBF(c )
BAT OPT 3 (ZERO DISCHARGE)
BAT OPT 3 (ZERO DISCHARGE)
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
3 1
0 0
0 0
0 0
1 1
0 0
0 0
0 0
0 0
0 0
0 0
0 0
(c) Estimate represents OBF wells = I 0% [assumed to convert to SBF under zero discharge option, plus
an assumed! 0% (conversion of WBF wellstoSBF.
4 4
0
0 1
1
1 1
6
0 0
0
0 0
0
0 0
0 6
4 4
0
0 0
0
2 2
6
0 0
0
0 0
0
0 0
0 6
-------
WORKSHEET Q:
Gulf of Mexico Regional Annual Total SBF Pollutant Loadings (Ibs)
Existing Sources
Baseline Annual Total Pollutant Loadings Summary
Baseline
Technology
Discharge w/10.2% retention
Zero Discharge of OBF-wastes
Shallow Water (<1, 000 ft)
Development
54,039,305
0
Exploratory
67,155,986
0
Deep Water (>1, 000 ft)
Development
15,214,194
0
Exploratory
101,481,343
0
Total
237,890,828
0
Notes
Total Wells = 201 SBF wells (from worksheet Well
Count Input Data)
Total Wells = 67 OBF wells (from worksheet Well
Count Input Data)
BAT Annual Total Pollutant Loadings Summary
BAT/NSPS Technology
Option *
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
68,546,728
66,550,333
0
Exploratory
85,723,524
83,226,863
0
Deep Water (>1, 000 ft)
Development
14,221,049
13,806,867
0
Exploratory
91,137,013
88,482,686
0
Total
259,628,314
252,066,749
0
Notes
Total Wells = 201 SBF wells + 67 OBF wells (from
worksheet Well Count Input Data)
Total Wells = 201 SBF wells + 67 OBF wells (from
worksheet Well Count Input Data)
Total Wells = 201 SBF wells (from worksheet Well
Count Input Data)
* EPA assumes that operators will switch from OBF to SBF under both BAT/NSPS discharge options
Incremental Annual Total Pollutant Loadings (Reductions) Summary **
Technology Option
Discharge w/10.2% retention
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
0
14,507,423
12,511,029
(54,039,305)
Exploratory
0
18,567,538
16,070,877
(67,155,986)
Deep Water (>1, 000 ft)
Development
0
(993,145)
(1,407,327)
(15,214,194)
Exploratory
0
(10,344,330)
(12,998,657)
(101,481,343)
Total
0
21,737,486
14,175,921
(237,890,828)
Notes
No reduction between baseline and current practice
Difference between BAT Option 1 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between BAT Option 2 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between zero discharge BAT loadings
and baseline 10.20% discharge loadings from the
201 wells currently using SBF (negative
incremental loadings indicate reductions)
Incremental Loadings (Reductions) = Technology Option Loadings - Baseline Loadings.
A-124
-------
California Offshore Regional Annual Total SBF Pollutant Loadings Summary (Ibs)
Existing Sources
Baseline Annual Total Pollutant Loadings Summary
Baseline
Technology
Zero Discharge of SBF & OBF-
wastes (Current Practice)
Shallow Water (<1, 000 ft)
Development
0
Exploratory
0
Deep Water (>1, 000 ft)
Development
0
Exploratory
0
Total
0
Notes
Total Wells = 0 SBF wells (from worksheet Well
Count Input Data)
BAT Annual Total Pollutant Loadings Summary
BAT/NSPS Technology
Option *
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
0
0
0
Exploratory
0
0
0
Deep Water (>1, 000 ft)
Development
0
0
0
Exploratory
0
0
0
Total
0
0
0
Notes
Total Wells = 0 SBF wells + 2 OBF wells (from
worksheet Well Count Input Data)
Total Wells = 0 SBF wells + 2 OBF wells (from
worksheet Well Count Input Data)
Total Wells = 0 SBF wells (from worksheet Well
Count Input Data)
* EPA assumes that operators will switch from OBF to SBF under both BAT/NSPS discharge options
Incremental Annual Total Pollutant Loadings (Reductions) Summary **
Technology Option
Zero Discharge of SBF & OBF-
wastes (Current Practice)
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
0
0
0
0
Exploratory
0
0
0
0
Deep Water (>1, 000 ft)
Development
0
0
0
0
Exploratory
0
0
0
0
Total
0
0
0
0
Notes
No reduction between baseline and current practice
Difference between BAT Option 1 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between BAT Option 2 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between zero discharge BAT loadings
and baseline zero discharge loadings from the 0
wells currently using SBF (negative incremental
loadings indicate reductions)
Incremental Loadings (Reductions) = Technology Option Loadings - Baseline Loadings.
A-125
-------
Cook Inlet, Alaska, Regional Annual Total SBF Pollutant Loadings Summary (Ibs)
Existing Sources
Baseline Annual Total Pollutant Loadings Summary
Baseline
Technology
Zero Discharge of SBF & OBF-
wastes (Current Practice)
Shallow Water (<1, 000 ft)
Development
0
Exploratory
0
Deep Water (>1, 000 ft)
Development
0
Exploratory
0
Total
0
Notes
Total Well(s) = 4 SBF well(s) (from worksheet Well
Count Input Data)
BAT Annual Total Pollutant Loadings Summary
BAT/NSPS Technology
Option *
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
552,796
536,696
0
Exploratory
0
0
Deep Water (>1, 000 ft)
Development
0
0
Exploratory
0
0
Total
552,796
536,696
0
0
0
0
Notes
Total Well(s) = 4 SBF well(s) + 2 OBF well(s) (from
worksheet Well Count Input Data)
Total Well(s) = 4 SBF well(s) + 2 OBF well(s) (from
worksheet Well Count Input Data)
Total Well(s) = 4 SBF well(s) (from worksheet Well
Count Input Data)
* EPA assumes that operators will switch from OBF to SBF under both BAT/NSPS discharge options
Incremental Annual Total Pollutant Loadings (Reductions) Summary **
Technology Option
Zero Discharge of SBF & OBF-
wastes (Current Practice)
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
0
552,796
536,696
0
Exploratory
0
0
0
0
Deep Water (>1, 000 ft)
Development
0
0
0
0
Exploratory
0
0
0
0
Total
0
552,796
536,696
0
Notes
No reduction between baseline and current practice
Difference between BAT Option 1 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between BAT Option 2 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between zero discharge BAT loadings
and baseline zero discharge loadings from the 4
well(s) currently using SBF (negative incremental
loadings indicate reductions)
Incremental Loadings (Reductions) = Technology Option Loadings - Baseline Loadings.
A-126
-------
Summary Pollutant Loadings (Reductions) for Management of SBF Cuttings, Existing Sources (Ibs)
Total Annual Baseline Pollutant Loadings
Baseline Technology
Discharge w/10.2% retention
Zero Discharge of OBF-wastes
Total
Gulf of Mexico
237,890,828
0
237,890,828
Offshore
California
N/A
0
0
Cook Inlet,
Alaska
N/A
0
0
Total
237,890,828
0
237,890,828
Notes
Total Wells = 201 COM SBF wells
Total Wells = 67 COM OBF wells + 0 CA SBF
wells + 2 CA OBF wells + 4 AK SBF well(s) + 2 AK
OBF wells
Total Wells = 201 COM SBF wells + 67 COM OBF
wells + 0 CA SBF wells + 2 CA OBF wells + 4 AK
SBF well(s) + 2 AK OBF wells
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
Total Annual Compliance Pollutant Loadings
Technology Option
Current Practice
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Gulf of Mexico
237,890,828
259,628,314
252,066,749
0
Offshore
California
0
0
0
0
Cook Inlet,
Alaska
0
552,796
536,696
0
Total
237,890,828
260,181,110
252,603,445
0
Notes *
Total Wells = 201 COM SBF wells + 67 COM OBF
wells + 0 CA SBF wells + 2 CA OBF wells + 4 AK
SBF well(s) + 2 AK OBF wells
Total Wells = 201 COM SBF wells + 67 COM OBF
wells + 0 CA SBF wells + 2 CA OBF wells + 4 AK
SBF well(s) + 2 AK OBF wells
Total Wells = 201 COM SBF wells + 67 COM OBF
wells + 0 CA SBF wells + 2 CA OBF wells + 4 AK
SBF well(s) + 2 AK OBF wells
Total Wells = 201 COM SBF wells
* EPA assumes that operators will switch from OBF to SBF under both BAT/NSPS discharge options
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
Total Annual Incremental Pollutant Loadings (Reductions)
Technology Option
Current Practice
BAT/NSPS Option 1
(Discharge w/4.03% retention)
BAT/NSPS Option 2
(Discharge w/3.82% retention)
Zero Discharge of SBF-wastes
Gulf of Mexico
0
21,737,486
14,175,921
(237,890,828)
Offshore
California
0
0
0
N/A
Cook Inlet,
Alaska
0
552,796
536,696
N/A
Total
0
22,290,282
14,712,617
(237,890,828)
Notes
Total Wells = 201 COM SBF wells + 67 COM OBF
wells + 0 CA SBF wells + 2 CA OBF wells + 4 AK
SBF well(s) + 2 AK OBF wells
Total Wells = 201 COM SBF wells + 67 COM OBF
wells + 0 CA SBF wells + 2 CA OBF wells + 4 AK
SBF well(s) + 2 AK OBF wells
Total Wells = 201 COM SBF wells + 67 COM OBF
wells + 0 CA SBF wells + 2 CA OBF wells + 4 AK
SBF well(s) + 2 AK OBF wells
Total Wells = 201 COM SBF wells
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
A-127
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WORKSHEET R:
Summary Dry Drill Cuttings and SBF Pollutant Loadings (Reductions) for Management of SBF Cuttings, Existing Sources (Ibs)
Total Annual Dry Drill Cuttings and SBF Baseline Pollutant Loadings
Baseline Technology
Discharge w/1 0.2% retention
Zero Discharge of OBF-wastes
Total
Gulf of Mexico
Dry Drill
Cuttings
194,650,820
0
194,650,820
SBF
43,240,008
0
43,240,008
Offshore California
Dry Drill
Cuttings
N/A
0
0
SBF
N/A
0
0
Cook Inlet, Alaska
Dry Drill
Cuttings
N/A
0
0
SBF
N/A
0
0
Total
Dry Drill Cuttings
194,650,820
0
194,650,820
SBF
43,240,008
0
43,240,008
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
Total Annual Dry Drill Cuttings and SBF Compliance Pollutant Loadings
Technology Option
Current Practice
BAT/NSPS Option 1 (Discharge
w/4.03% retention)
BAT/NSPS Option 2 (Discharge
w/3.82% retention)
Zero Discharge of SBF-wastes
Gulf of Mexico
Dry Drill
Cuttings
194,650,820
243,181,120
237,038,491
0
SBF
43,240,008
16,447,194
15,028,258
0
Offshore California
Dry Drill
Cuttings
0
1,591,590
1,551,387
N/A
SBF
0
(1,591,590)
(1,551,387)
N/A
Cook Inlet, Alaska
Dry Drill
Cuttings
0
4,211,480
4,105,100
N/A
SBF
0
(3,658,684)
(3,568,404)
N/A
Total
Dry Drill Cuttings
194,650,820
248,984,190
242,694,978
0
SBF
43,240,008
11,196,920
9,908,467
0
* EPA assumes that operators will switch from OBF to SBF under both BAT/NSPS discharge options
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
Total Annual Dry Drill Cuttings and SBF Incremental Pollutant Loadings (Reductions)
Current Practice
Current Practice
BAT/NSPS Option 1 (Discharge
w/4.03% retention)
BAT/NSPS Option 2 (Discharge
w/3.82% retention)
Zero Discharge of SBF-wastes
Gulf of Mexico
Dry Drill
Cuttings
0
48,530,300
42,387,671
(194,650,820)
SBF
0
(26,792,814)
(28,21 1 ,749)
(43,240,008)
Offshore California
Dry Drill
Cuttings
0
1,591,590
1,551,387
N/A
SBF
0
(1,591,590)
(1,551,387)
N/A
Cook Inlet, Alaska
Dry Drill
Cuttings
0
4,211,480
4,105,100
N/A
SBF
0
(3,658,684)
(3,568,404)
N/A
Total
Dry Drill Cuttings
0
54,333,370
48,044,158
(194,650,820)
SBF
0
(32,043,088)
(33,331,541)
(43,240,008)
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
A-128
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WORKSHEET S:
Gulf of Mexico Regional Annual Total Pollutant Loadings Summary (Ibs) from New Sources
Baseline Annual Total Pollutant Loadings Summary: SBF, New Source Onsite Discharges
\
Technology
Discharge w/10.2% retention
Shallow Water (<1, 000 ft)
Development
3,141,820
Exploratory
0
Deep Water (>1, 000 ft)
Development
14,263,307
Exploratory
0
Total
17,405,127
Notes
Total Wells = 20 SBF wells (from worksheet Well
Count Input Data)
BAT Annual Total Pollutant Loadings Summary: SBF, New Source Onsite Discharges
BAT/NSPS Technology
Option *
BAT/NSPS Option 1 (Discharge
w/4.03% retention)
BAT/NSPS Option 2 (Discharge
w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
5,026,912
4,898,112
0
Exploratory
0
0
0
Deep Water (>1, 000 ft)
Development
15,214,194
14,824,376
0
Exploratory
0
0
0
Total
20,241,106
19,722,488
0
Notes
Total Wells = 20 SBF wells (from worksheet Well
Count Input Data)
Total Wells = 20 SBF wells (from worksheet Well
Count Input Data)
Total Wells = 20 SBF wells (from worksheet Well
Count Input Data)
Incremental Annual Total Pollutant Loadings (Reductions) Summary : SBF, New Sources* Onsite Discharges
Technology Option
Discharge w/10.2% retention
BAT/NSPS Option 1 (Discharge
w/4.03% retention)
BAT/NSPS Option 2 (Discharge
w/3.82% retention)
Zero Discharge of SBF-wastes
Shallow Water (<1, 000 ft)
Development
0
1 ,885,092
1 ,756,292
(3,141,820)
Exploratory
0
0
0
0
Deep Water (>1, 000 ft)
Development
0
950,887
561 ,069
(14,263,307)
Exploratory
0
0
0
0
Total
0
2,835,979
2,317,361
(17,405,127)
Notes
No reduction between baseline and current
practice
Difference between NSPS Option 1 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between NSPS Option 2 loadings and
baseline loadings (negative incremental loadings
indicate reductions)
Difference between zero discharge NSPS loadings
and baseline 10.20% discharge loadings from the
20 wells expected to use SBF (negative
incremental loadings indicate reductions)
' Incremental Loadings (Reductions) = Technology Option Loadings - Baseline Loadings.
A-129
-------
WORKSHEET T:
Summary: New Sources
Baseline
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Wells, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Shallow Water (<1,000 ft) Deep Water (>1,000 ft)
Development Exploratory Development Exploratory Total
50 15
628,364 1,316,784 950,887
3,141,820 0 14,263,307
00 0
00 0
00 0
No. wells, DBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
Summary: New Sources
BAT 1
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Total Wells, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
20 0
628,364 1,316,784 950,887
1 ,256,728 0 0
00 0
1 ,256,728 0 0
0 20
2,114,195
0 17,405,127
0 0
0 0
0 0
0 2
2,114,195
0 1 ,256,728
0 0
0 1 ,256,728
Shallow Water (<1,000 ft) Deep Water (>1,000 ft)
Development Exploratory Development Exploratory Total
80 16
628,364 1,316,784 950,887
5,026,912 0 15,214,194
00 0
00 0
00 0
No. wells, DBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
1 0 0
628,364 1,316,784 950,887
628,364 0 0
00 0
628,364 0 0
0 24
2,114,195
0 20,241,106
0 0
0 0
0 0
0 1
2,114,195
0 628,364
0 0
0 628,364
A-130
-------
Summary: New Sources
BAT 2
No. wells, SBF
Loadings/well (Ibs)
Total Wells, Zero Discharge
Onsite Injection (0%S: 0%D)
Onshore Disposal (100%S:100%D)
Shallow Water (<1,000 ft) Deep Water (>1,000 ft)
Development Exploratory Development Exploratory Total
8
16,100
8
0
128,800
No. wells, DBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Discharge
Summary: New Sources
BAT 3
No. wells, SBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
No. wells, DBF
Loadings/well (Ibs)
Total Loadings, Zero Discharge
Onsite Injection (20%S: 0%D)
Onshore Disposal (80%S:100%D)
1
0 16 0 24
33,739 24,364 54,170
0 16 0 24
0 000
0 389,818 0 518,618
0 001
628,364 1,316,784 950,887 2,114,195
628,364
0
628,364
000 628,364
0 000
000 628,364
Shallow Water (<1,000 ft) Deep Water (>1,000 ft)
Development Exploratory Development Exploratory Total
8
612,264 1,
4,898,112
0 16 0 24
283,045 926,523 2,060,025
0 14,824,376 0 19,722,488
Shallow Water (<1,000 ft) Deep Water (>1,000 ft)
Development Exploratory Development Exploratory Total
0
0 303
628,364 1,316,784 950,887 2,114,195
0
0
0
7
0 2,852,661 0 2,852,661
0 000
0 2,852,661 0 2,852,661
0 8 0 15
1,885,092 3,950,352 2,852,661 6,342,584
4,398,548
879,710
3,518,838
0 7,607,097 0 12,005,645
000 879,710
0 7,607,097 0 11,125,935
A-131
-------
WORKSHEET No. W:
Summary Dry Drill Cuttings and SBF Pollutant Loadings (Reductions)
for Management of SBF Cuttings, New Sources (Ibs)
Total Annual Dry Drill Cuttings and SBF Baseline Pollutant Loadings
Baseline Technology
Discharge w/1 0.2% retention
Gulf of Mexico
Dry Drill Cuttings
14,241,500
SBF
3,163,627
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
Total Annual Dry Drill Cuttings and SBF Compliance Pollutant Loadings
Technology Option
Current Practice
BAT/NSPS Option 1 (Discharge
w/4.03% retention)
BAT/NSPS Option 2 (Discharge
w/3.82% retention)
Zero Discharge of SBF-wastes
Gulf of Mexico
Dry Drill Cuttings
14,241,500
14,241,500
13,881,767
0
SBF
3,163,627
5,999,606
5,840,721
0
* EPA assumes that operators will switch from OBF to SBF under both BAT/NSPS discharge options
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
Total Annual Dry Drill Cuttings and SBF Incremental Pollutant Loadings (Reductions)
Current Practice
Current Practice
BAT/NSPS Option 1 (Discharge
w/4.03% retention)
BAT/NSPS Option 2 (Discharge
w/3.82% retention)
Zero Discharge of SBF-wastes
Gulf of Mexico
Dry Drill Cuttings
0
0
(359,733)
(14,241,500)
SBF
0
2,835,979
2,677,094
(3,163,627)
N/A - Not Applicable (as these regions currently do not allow SBF discharges)
A-132
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APPENDIX IX-1
Non-Water Quality Environmental Impacts
A-133
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Worksheet No. 1 Page 1 of 5
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
Fuel-Consuming Activity
Baseline Solids Control
Equipment
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
Deep Water
Development | Exploratory
1,137.6 2,520.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment fuel usage is 6 gal-diesel/hr
TOTAL
748.8
1,569.6
1,137.6
2,520.0
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
TOTAL
8,424.0
8,424.0
17,658.0
17,658.0
12,798.0
12,798.0
28,350.0
28,350.0
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
-------
Worksheet No. 1 Page 2 of 5
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
Baseline Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.1300
0.2725
0.1975
0.4375
THC
0.0104
0.0218
0.0158
0.0350
S02
0.0086
0.0181
0.0131
0.0291
CO
0.0281
0.0590
0.0427
0.0947
TSP
0.0093
0.0195
0.0141
0.0313
Total
0.1865
0.3909
0.2833
0.6275
Baseline Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0121
0.0253
0.0183
0.0406
THC
0.0017
0.0035
0.0025
0.0056
SO2
0.0000
0.0000
0.0000
0.0001
CO
0.0077
0.0162
0.0117
0.0259
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0215
0.0450
0.0326
0.0723
Average Baseline Solids Control Air Emissions (per model well) - Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.1123
0.2354
0.1706
0.3780
THC
0.0091
0.0191
0.0138
0.0306
SO2
0.0074
0.0154
0.0112
0.0247
CO
0.0251
0.0526
0.0381
0.0844
TSP
0.0079
0.0165
0.0120
0.0266
Total
0.1617
0.3390
0.2457
0.5442
Daily Drill Rig Emissions
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1 .6954
1 .6954
1 .6954
1 .6954
S02
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Total per day 12.6280 6.7816 0.8598
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
1.8100
0.9900
-------
Worksheet No. 1 Page 3 of 5
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
& Zero Discharge from OBF Wells (also at 10.20% CRN)
Air Emissions (SBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.1123
0.2354
0.1706
0.3780
THC
0.0091
0.0191
0.0138
0.0306
SO2
0.0074
0.0154
0.0112
0.0247
CO
0.0251
0.0526
0.0381
0.0844
TSP
0.0079
0.0165
0.0120
0.0266
Total
0.1617
0.3390
0.2457
0.5442
Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
1.3055
2.3187
1 .9402
4.3481
THC
0.5276
0.9267
0.8441
1.8858
S02
0.0904
0.1591
0.1340
0.3004
CO
0.2386
0.4150
0.3395
0.7592
TSP
0.1033
0.1813
0.1537
0.3444
Total
2.2654
4.0009
3.4116
7.6379
Note: These air emissions are calculated in Worksheet No. 11
-------
Worksheet No. 1 Page 4 of 5
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore Gulf of Mexico (GOM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
& Zero Discharge from OBF Wells (also at 10.20% CRN)
Annual Air Emissions (SBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
1,421.4691
1,766.9827
401.7748
2,670.0225
THC
758.9647
943.4447
214.5195
1,425.6045
SO2
96.7623
120.2821
27.3496
181.7539
CO
204.5141
254.2250
57.8054
384.1500
TSP
111.3608
138.4290
31.4759
209.1750
Total
2,593.0710
3,223.3636
732.9253
4,870.7059
Total
6,260.2492
3,342.5334
426.1479
900.6946
490.4407
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
744.3219
918.2497
0.0000
0.0000
THC
392.4343
485.1648
0.0000
0.0000
SO2
50.7436
62.5548
0.0000
0.0000
CO
108.8490
133.6807
0.0000
0.0000
TSP
58.3910
71.9770
0.0000
0.0000
Total
1,354.7398
1,671.6271
0.0000
0.0000
Total
1,662.5716
877.5992
113.2985
242.5297
130.3680
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
16,834.9516
20,579.2901
600.6147
3,991.4269
THC
9,014.6791
11,019.6751
321.6136
2,137.3054
SO2
1,146.1398
1,401.0580
40.8904
271.7402
CO
2,417.5775
2,955.2820
86.2511
573.1875
TSP
1,319.3473
1,612.7893
47.0699
312.8063
Total
30,732.6952
37,568.0945
1,096.4397
7,286.4662
Total
42,006.2833
22,493.2732
2,859.8284 6,032.2980 3,292.0127
Note: Summary annual air emissions totals assume the following number of GOM SBF wells (existing sources) under this technology option:
86 SWD wells, 51 SWE wells, 16 DWD wells, and 48 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 42 SWD wells, 25 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM WBF wells (existing sources) under this technology option:
511 SWD wells, 298 SWE wells, 12 DWD wells, and 36 OWE wells
-------
Worksheet No. 1 Page 5 of 5
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Summary Annual Fuel Usage
Offshore Gulf of Mexico (GOM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
& Zero Discharge from OBF Wells (also at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF Wells
gallons per
model well
748.8
1,569.6
1,137.6
2,520.0
Barrels of Oil
Equivalent
(BOE) per
model well
17.8
37.4
27.1
60.0
BOE per
model well per
day
3.4
3.4
3.4
3.4
OBF Wells
gallons per
model well
6,550.7
11,546.7
9,797.9
21,907.7
Barrels of Oil Equivalent
(BOE) per model well
156.0
274.9
233.3
521.6
BOE per model well per
day
30.0
25.2
29.5
29.8
Annual Fuel Usage
Gallons
339,524.8
368,718.2
18,201.6
120,960.0
Barrels of Oil
Equivalent (BOE)
8,083.9
8,779.0
433.4
2,880.0
TOTAL
5,976.0
142.3
13.7
49,803.0
1,185.8
114.6
847,404.6
20,176.3
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
GOM Baseline Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @ 10.2%)
Total Air
Emissions
(tons)
2,593.0710
3,223.3636
732.9253
4,870.7059
Barrels of Oil
Equivalent
(BOE)
165,378.8
205,577.1
46,743.9
310,640.0
OBF (Zero Discharge)
Total Air
Emissions
(tons)
1 ,354.7398
1,671.6271
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
86,568.3
106,711.9
0.0
0.0
WBF (Discharge @ 10.2%)
Total Air Emissions
(tons)
30,815.3325
37,669.1115
1 ,099.3879
7,306.0588
Barrels of Oil Equivalent
(BOE)
1,965,315.7
2,402,430.6
70,115.9
465,960.0
WBF (Zero Discharge)
Total Air
Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent (BOE)
0.0
0.0
0.0
0.0
TOTAL 11,420.1 728,339.9 3,026.4 193,280.1 76,889.9 4,903,822.2 0.0 0.0
88,310.0 5,632,162.1
Note: Summary annual fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
86 SWD wells, 51 SWE wells, 16 DWD wells, and 48 OWE wells
Note: Summary annual fuel usage totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 42 SWD wells, 25 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual fuel usage totals assume the following number of GOM WBF wells (existing sources) under this technology option:
511 SWD wells, 298 SWE wells, 12 DWD wells, and 36 OWE wells
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 2 Page 1 of 3
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore California
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Summary Air Emissions (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.2994
0.5259
0.4042
3.6306
THC
0.1217
0.2116
0.1640
1.6696
SO2
0.0166
0.0275
0.0216
0.2321
CO
0.0817
0.1501
0.1134
0.7492
TSP
0.0191
0.0315
0.0248
0.2677
Total
0.5385
0.9466
0.7280
6.5492
Total Per Day
0.1036
0.0868
0.0922
0.3742
Note: These air emissions per model well are calculated in NWQI Worksheet No. 15
Summary Fuel Usage (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
3,428.2
6,644.4
4,930.8
23,403.1
Barrels of Oil
Equivalent
(BOE)
81.6
158.2
117.4
557.2
Barrels of Oil Equivalent
(BOE) Per Day
15.7
14.5
14.9
31.8
CO
CD
Note: These air emissions per model well are calculated in NWQI Worksheet No. 15
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 2 Page 2 of 3
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore California
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Summary Annual Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Annual Fuel Usage
Gallons
3,428.2
6,644.4
0.0
0.0
Barrels of
Oil
Equivalent
(BOE)
81.6
158.2
0.0
0.0
TOTAL
10,072.6
239.8
Daily Drill Rig Emissions
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
CA Baseline Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
OBF (Zero Discharge)
Total Air
Emissions
(tons)
30.5288
63.8108
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
1,986.8
4,151.8
0.0
0.0
WBF (Discharg
Total Air
Emissions
(tons)
180.9119
252.8128
0.0000
0.0000
e@ 10.20%)
Oil
Equivalent
(BOE)
11,538.1
16,123.7
0.0
0.0
WBF (Zero Discharge)
Total Air Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent (BOE)
0.0
0.0
0.0
0.0
TOTAL
94.3
6,138.6
433.7
27,661.8
0.0
0.0
Note: Summary annual air emissions/fuel usage totals assume the following number of SBF wells (existing sources) for baseline current practice
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions/fuel usage totals assume the following number of OBF wells (existing sources) for baseline current practice
under this technology option: 1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 DWE wells
Note: Summary annual air emissions/fuel usage totals assume the following number of WBF wells (existing sources) for baseline current practice
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 DWE wells
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 2 Page 3 of 3
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore California
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Annual Air Emissions (SBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
0.0000
0.0000
THC
0.0000
0.0000
0.0000
0.0000
S02
0.0000
0.0000
0.0000
0.0000
CO
0.0000
0.0000
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
0.0000
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
16.7158
16.9423
0.0000
0.0000
THC
9.3437
19.4066
0.0000
0.0000
S02
1 .2082
2.5022
0.0000
0.0000
CO
2.5916
5.3472
0.0000
0.0000
TSP
1 .3903
2.8791
0.0000
0.0000
Total
31 .2496
47.0774
0.0000
0.0000
Total
33.6581
28.7503
3.7104
7.9389
4.2693
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
138.1160
0.0000
0.0000
THC
52.9238
73.9576
0.0000
0.0000
S02
6.7288
9.4031
0.0000
0.0000
CO
14.1932
19.8341
0.0000
0.0000
TSP
7.7457
10.8241
0.0000
0.0000
Total
180.4268
252.1349
0.0000
0.0000
Total
236.9514
126.8813
16.1319
34.0273
18.5698
Note: Summary annual air emissions totals assume the following number of SBF wells (existing sources) for baseline current practice
underthis technology option: 0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of OBF wells (existing sources) for baseline current practice
underthis technology option: 1 SWD wells, 1 S WE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions/fuel usage totals assume the following number of WBF wells (existing sources) for baseline current practice
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 OWE wells
-------
Worksheet No. 3 Page 1 of 3
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Cook Inlet, AK
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Summary Air Emissions (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0000
0.0000
THC
0.0078
0.0164
0.0000
0.0000
SO2
0.0001
0.0002
0.0000
0.0000
CO
0.0362
0.0758
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.0000
0.0000
Total Per Day
0.0194
0.0194
0.0000
0.0000
Note: These air emissions per model well are calculated in NWQI Worksheet No. 18
Summary Fuel Usage (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
2,283.1
4,785.6
0.0
0.0
Barrels of Oil
Equivalent
(BOE)
54.4
113.9
0.0
0.0
Barrels of Oil Equivalent
(BOE) Per Day
10.5
10.5
0.0
0.0
Note: These air emissions per model well are calculated in NWQI Worksheet No. 18
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 3 Page 2 of 3
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Summary Annual Fuel Usage
Cook In let, AK
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Annual Fuel Usage
Gallons
2,283.1
4,785.6
0.0
0.0
Barrels of
Oil
Equivalent
(BOE)
54.4
113.9
0.0
0.0
TOTAL
Daily Drill Rig Emissions
7,068.7
168.3
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
AK Baseline Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
OBF (Zero Discharge)
Total Air
Emissions
(tons)
30.0911
63.0755
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
1,959.5
4,107.5
0.0
0.0
WBF (Discharg
Total Air
Emissions
(tons)
180.9119
126.4064
0.0000
0.0000
e@ 10.20%)
Barrels of
Oil
Equivalent
(BOE)
11,538.1
8,061.8
0.0
0.0
WBF (Zero Discharge)
Total Air Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent (BOE)
0.0
0.0
0.0
0.0
TOTAL
93.2
6,067.0
307.3
19,599.9
0.0
0.0
Note: Summary annual air emission/fuel usage totals assume the following number of SBF wells (existing sources) for baseline current practice
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 DWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of OBF wells (existing sources) for baseline current practice
under this technology option: 1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 DWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of WBF wells (existing sources) for baseline current practice
under this technology option: 3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 DWE wells
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 3 Page 3 of 3
BPT Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Cook Inlet, AK
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Annual Air Emissions (SBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
0.0000
0.0000
THC
0.0000
0.0000
0.0000
0.0000
SO2
0.0000
0.0000
0.0000
0.0000
CO
0.0000
0.0000
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
Total 0.0000 0.0000 0.0000
Annual Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20%CRN)
0.0000
0.0000
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
16.4731
16.5352
0.0000
0.0000
THC
8.8239
18.4963
0.0000
0.0000
SO2
1.1179
2.3432
0.0000
0.0000
CO
2.3892
5.0081
0.0000
0.0000
TSP
1 .2870
2.6978
0.0000
0.0000
Total
30.0911
45.0806
0.0000
0.0000
Total
33.0083
27.3202
3.4611
7.3973
3.9848
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
69.0580
0.0000
0.0000
THC
52.9238
36.9788
0.0000
0.0000
S02
6.7288
4.7015
0.0000
0.0000
CO
14.1932
9.9171
0.0000
0.0000
TSP
7.7457
5.4120
0.0000
0.0000
Total
180.4268
126.0674
0.0000
0.0000
Total
167.8934
89.9025
11.4303
24.1103
Note: Summary annual air emissions totals assume the following number of SBF wells (existing sources) for baseline current practice
under this technology option: 0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of OBF wells (existing sources) for baseline current practice
under this technology option: 1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of WBF wells (existing sources) for baseline current practice
under this technology option: 3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
13.1577
-------
Worksheet No. 4 Page 1 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03%CRN
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
748.8
748.8
1,569.6
1,569.6
1,137.6
1,137.6
2,520.0
2,520.0
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
TOTAL
1,497.6
3,139.2
2,275.2
5,040.0
>
en
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
8,424.0 17,658.0
14,098.7 29,553.0
12,798.0
21,419.1
28,350.0
47,447.4
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
TOTAL
22,522.7 47,211.0
34,217.1
75,797.4
-------
Worksheet No. 4 Page 2 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03%CRN
BAT Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.3476
0.7286
0.5280
1.1697
THC
0.0278
0.0583
0.0422
0.0936
SO2
0.0231
0.0484
0.0351
0.0778
CO
0.0752
0.1577
0.1143
0.2532
TSP
0.0248
0.0520
0.0377
0.0836
Total
0.4985
1.0450
0.7574
1.6778
BAT Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0323
0.0677
0.0490
0.1086
THC
0.0045
0.0094
0.0068
0.0150
SO2
0.0000
0.0001
0.0001
0.0002
CO
0.0206
0.0432
0.0313
0.0693
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0574
0.1203
0.0872
0.1932
>
CD
BAT Option 1 Solids Control Air Emissions (per model well) -Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.3003
0.6294
0.4562
1.0105
THC
0.0243
0.0509
0.0369
0.0818
SO2
0.0197
0.0412
0.0299
0.0661
CO
0.0670
0.1405
0.1018
0.2256
TSP
0.0211
0.0442
0.0321
0.0710
Total
0.4324
0.9063
0.6569
1.4551
Total Per Day
0.0831
0.0831
0.0831
0.0831
-------
Worksheet No. 4 Page 3 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03%CRN
Daily Drill Rig Emissions
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1 .6954
1 .6954
1 .6954
1 .6954
S02
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
GOM BAT1 Daily Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Dischargeยฎ 4.03%)
Total Air
Emissions
(tons)
3,772.4077
4,719.0199
785.7233
5,016.8108
Barrels of Oil
Equivalent
(BOE)
240,663.9
301 ,053.8
50,125.9
320,051 .7
OBF (Zero Discharge)
Total Air
Emissions
(tons)
806.3927
1 ,002.9762
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
51 ,528.7
64,027.1
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air Emissions
(tons)
28,885.6052
35,267.3896
1007.772
6,900.1667
Barrels of Oil
Equivalent (BOE)
1,842,243.1
2,249,255.5
64,272.9
440,073.3
TOTAL
14,294.0
88,164.3
5,623,296.0
911,895.3
1,809.4
115,555.9
72,060.9
4,595,844.8
Note: Summary annual air emission/fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
124 SWD wells, 74 SWE wells, 17 DWD wells, and 49 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM OBF wells (existing sources) will convert to using SBF:
25 SWD wells, 15 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM WBF wells (existing sources) under this technology option:
479 SWD wells, 279 SWE wells, 11 DWD wells, and 34 OWE wells
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 4 Page 4 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03%CRI\
Annual Air Emissions (SBF BAT1 Model Well - Discharging at 4.03% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
2,072.8680
1,261.3912
286.8340
853.9205
THC
1 ,096.2078
656.1600
150.5011
435.9959
SO2
141.0433
85.7652
19.5101
58.0128
CO
300.0839
184.5197
41 .7322
126.3508
TSP
162.2047
98.5113
22.4240
66.5429
Total
3,772.4077
2,286.3475
521.0014
1 ,540.8229
Total
4,475.0137
2,338.8648
304.3314
652.6866
349.6830
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
443.0487
550.9498
0.0000
0.0000
THC
233.5919
291 .0989
0.0000
0.0000
S02
30.2045
37.5329
0.0000
0.0000
CO
64.791 1
80.2084
0.0000
0.0000
TSP
34.7565
43.1862
0.0000
0.0000
Total
806.3927
1 ,002.9762
0.0000
0.0000
Total
993.9986
524.6908
67.7374
144.9995
77.9427
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
15,780.7080
19,267.1877
550.5635
3,769.6809
THC
8,450.1591
10,317.0784
294.8124
2,018.5662
S02
1 ,074.3659
1 ,31 1 .7288
37.4829
256.6435
CO
2,266.1832
2,766.8579
79.0635
541 .3438
TSP
1 ,236.7267
1 ,509.9605
43.1474
295.4281
Total
28,808.1429
35,172.8133
1 ,005.0697
6,881 .6625
Total
39,368.1402
21,080.6161
2,680.2211
5,653.4484 3,085.2627
Note: Summary annual air emissions totals assume the following number of GOM SBF wells (existing sources) under this technology option:
124 SWD wells, 74 SWE wells, 17 DWD wells, and 49 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM OBF wells (existing sources) will convert to using SBF:
25 SWD wells, 15 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM WBF wells (existing sources) under this technology option:
479 SWD wells, 279 SWE wells, 11 DWD wells, and 34 OWE wells
-------
Worksheet No. 5 Page 1 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore California
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) 4.03%CRN
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless
otherwise noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
748.8
748.8
1,569.6
1,569.6
1,137.6
1,137.6
2,520.0
2,520.0
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
TOTAL
1,497.6
3,139.2
2,275.2
5,040.0
>
CD
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless
otherwise noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
TOTAL
8,424.0
14,098.7
22,522.7
17,658.0
29,553.0
47,211.0
12,798.0
21,419.1
34,217.1
28,350.0
47,447.4
75,797.4
Baseline equipment include: 4 x 5 hp primary shale shakers, 4x5
hp secondary shale shakers, and 1 x 27.5 hp fines removal unit
(avg of 5 hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
-------
Worksheet No. 5 Page 2 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore California
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) 4.03%CRN
BAT Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.3476
0.7286
0.5280
1.1697
THC
0.0278
0.0583
0.0422
0.0936
S02
0.0231
0.0484
0.0351
0.0778
CO
0.0752
0.1577
0.1143
0.2532
TSP
0.0248
0.0520
0.0377
0.0836
Total
0.4985
1.0450
0.7574
1.6778
BAT Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0323
0.0677
0.0490
0.1086
THC
0.0045
0.0094
0.0068
0.0150
SO2
0.0000
0.0001
0.0001
0.0002
CO
0.0206
0.0432
0.0313
0.0693
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0574
0.1203
0.0872
0.1932
Ol
o
BAT Option 1 Solids Control Air Emissions (per model well) - Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (0%/100%)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0323
0.0677
0.0490
0.1086
THC
0.0045
0.0094
0.0068
0.0150
S02
0.0000
0.0001
0.0001
0.0002
CO
0.0206
0.0432
0.0313
0.0693
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0574
0.1203
0.0872
0.1932
Total Per Day
0.0110
0.0110
0.0110
0.0110
-------
Worksheet No. 5 Page 3 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore California
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) 4.03%CRN
Daily Drill Rig Emissions
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1 .6954
1 .6954
1 .6954
1 .6954
S02
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
CA BAT1 Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
DBF (Zero Discharge)
Total Air
Emissions
(tons)
30.5288
63.8108
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
1,986.8
4,151.8
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air
Emissions
(tons)
180.9119
252.8128
0.000
0.0000
Barrels of Oil
Equivalent
(BOE)
11,538.1
16,123.7
0.0
0.0
WBF (Zero Discharge)
Total Air Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil Equivalent
(BOE)
0.0
0.0
0.0
0.0
TOTAL
6,138.6
433.7
27,661.8
94.3
528.1
33,800.3
Note: Summary annual fuel usage totals assume the following number of SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual fuel usage totals assume the following number of DBF wells (existing sources) will convert to using SBF:
1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions/fuel usage totals assume the following number of WBF wells (existing sources) for baseline current practice
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
0.0
0.0
-------
Worksheet No. 5 Page 4 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Offshore California
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Ur
Annual Air Emissions (SBF BAT1 Model Well - Discharging at 4.03% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
0.0000
0.0000
THC
0.0000
0.0000
0.0000
0.0000
S02
0.0000
0.0000
0.0000
0.0000
CO
0.0000
0.0000
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total 0.0000 0.0000 0.0000
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20%CRN)
0.0000
0.0000
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
16.7158
16.9423
0.0000
0.0000
THC
8.9378
18.6914
0.0000
0.0000
SO2
1.1344
2.3705
0.0000
0.0000
CO
2.4347
5.0824
0.0000
0.0000
TSP
1 .3061
2.7293
0.0000
0.0000
>
01
Total
33.6581
27.6292
3.5050
7.5171
4.0353
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
138.1160
0.0000
0.0000
THC
52.9238
73.9576
0.0000
0.0000
SO2
6.7288
9.4031
0.0000
0.0000
CO
14.1932
19.8341
0.0000
0.0000
TSP
7.7457
10.8241
0.0000
0.0000
Total
236.9514
126.8813
16.1319
34.0273
18.5698
Note: Summary annual air emissions totals assume the following number of SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of OBF wells (existing sources) will convert to using SBF:
1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of WBF wells (existing sources) for baseline current practice
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 OWE wells
-------
>
en
Worksheet No. 6 Page 1 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Cook Inlet, AK
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
748.8
748.8
1,569.6
1,569.6
1,137.6
1,137.6
2,520.0
2,520.0
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
TOTAL
1,497.6
3,139.2
2,275.2
5,040.0
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
8,424.0 17,658.0
14,098.7 29,553.0
12,798.0
21,419.1
28,350.0
47,447.4
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
TOTAL
22,522.7 47,211.0
34,217.1
75,797.4
-------
Worksheet No. 6 Page 2 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Cook Inlet, AK
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
BAT Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.3476
0.7286
0.5280
1.1697
THC
0.0278
0.0583
0.0422
0.0936
SO2
0.0231
0.0484
0.0351
0.0778
CO
0.0752
0.1577
0.1143
0.2532
TSP
0.0248
0.0520
0.0377
0.0836
Total
0.4985
1.0450
0.7574
1.6778
BAT Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0323
0.0677
0.0490
0.1086
THC
0.0045
0.0094
0.0068
0.0150
SO2
0.0000
0.0001
0.0001
0.0002
CO
0.0206
0.0432
0.0313
0.0693
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0574
0.1203
0.0872
0.1932
>
en
BAT Option 1 Solids Control Air Emissions (per model well) -Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (0%/100%)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0323
0.0677
0.0490
0.1086
THC
0.0045
0.0094
0.0068
0.0150
SO2
0.0000
0.0001
0.0001
0.0002
CO
0.0206
0.0432
0.0313
0.0693
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0574
0.1203
0.0872
0.1932
Total Per Day
0.0110
0.0110
0.0110
0.0110
-------
Worksheet No. 6 Page 3 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Daily Drill Rig Emissions
Cook Inlet, AK
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1 .6954
1 .6954
1 .6954
1 .6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
a
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL 61,552.0
AK BAT1 Daily Emissions/Fuel Usage
1,465.5
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @4.03%)
Total Air
Emissions
(tons)
30.0477
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
1 ,940.8
0.0
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air
Emissions
(tons)
180.9119
126.4064
0.000
0.0000
Barrels of Oil
Equivalent
(BOE)
11,538.1
8,061.8
0.0
0.0
OBF (Zero Discharge)
Total Air Emissions (tons)
0.0000
63.0755
0.0000
0.0000
Barrels of Oil Equivalent
(BOE)
0.0
4,107.5
0.0
0.0
TOTAL
307.3
19,599.9
30.0 1,940.8
400.4
25,648.2
Note: Summary annual fuel usage totals assume the following number of SBF wells (existing sources) under this technology option:
1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual fuel usage totals assume the following number of OBF wells (existing sources) under this technology option:
0 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of WBF wells (existing sources) under this technology option:
3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
63.1
4,107.5
-------
Worksheet No. 6 Page 4 of 4
BAT Non-Water Quality Environmental Impacts: BAT Option 1
Region:
Technology:
Cook Inlet, AK
SBF Discharges from BAT Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
Annual Air Emissions (SBF BAT1 Model Well - Discharging at 4.03% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
16.4487
0.0000
0.0000
0.0000
THC
8.8205
0.0000
0.0000
0.0000
SO2
1.1178
0.0000
0.0000
0.0000
CO
2.3736
0.0000
0.0000
0.0000
TSP
1 .2870
0.0000
0.0000
0.0000
Total
30.0477
0.0000
0.0000
0.0000
Total 16.4487 8.8205 1.1178
Annual Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20% CRN)
2.3736
1.2870
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
0.0000
16.5352
0.0000
0.0000
THC
0.0000
8.8325
0.0000
0.0000
SO2
0.0000
1.1180
0.0000
0.0000
CO
0.0000
2.4288
0.0000
0.0000
TSP
0.0000
1 .2870
0.0000
0.0000
Total
0.0000
30.2015
0.0000
0.0000
Total
16.5352
8.8325
1.1180
2.4288
1.2870
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
69.0580
0.0000
0.0000
THC
52.9238
36.9788
0.0000
0.0000
SO2
6.7288
4.7015
0.0000
0.0000
CO
14.1932
9.9171
0.0000
0.0000
TSP
7.7457
5.4120
0.0000
0.0000
Total
180.4268
126.0674
0.0000
0.0000
Total 167.8934 89.9025 11.4303 24.1103
Note: Summary annual air emissions totals assume the following number of SBF wells (existing sources) under this technology option:
1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of OBF wells (existing sources) under this technology option:
0 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of WBF wells (existing sources) under this technology option:
3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
13.1577
-------
Worksheet No. 7 Page 1 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Fuel-Consuming Activity
Cuttings Dryer Discharge
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
748.8 1,569.6
870.4 870.4
0.0 0.0
870.4 870.4
1.7 3.3
25.3 25.3
0.0 0.0
45.5 50.6
144.0 144.0
3.3 6.7
1.7 3.3
5.0 5.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
1,137.6 2,520.0
870.4 870.4
0.0 0.0
870.4 870.4
3.3 6.7
25.3 25.3
0.0 0.0
50.6 60.7
144.0 144.0
6.7 13.3
3.3 6.7
5.0 5.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
EPA assumes that the volume of fines waste can be managed via
regular supply boats
EPA assumes that the volume of fines waste can be managed via
regular supply boats
>
en
Subtotal
2,594.5
4,247.9
3,383.9
6,172.1
-------
Worksheet No. 7 Page 2 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Fuel-Consuming Activity
Zero Discharge of Fines (cont.)
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojnj:sJhj3reJ^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.1 0.2
0.1 0.2
0.1 0.2
0.3 0.7
9.4 9.7
Deep Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.2 0.4
0.2 0.4
0.2 0.4
0.5 1.2
9.5 10.1
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (20%/80%) of offshore wastes sent on-shore
en
oo
TOTAL Diesel Per Well (Gal)
2,603.9
4,257.6
3,393.4
6,182.2
-------
Worksheet No. 7 Page 3 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Energy-Consuming Activity
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
14,098.7 29,553.0
1,440.0 1,440.0
54.4 108.8
27.2 54.4
1.9 4.0
2.3 4.8
23.4 49.0
Deep Water
Development | Exploratory
12,798.0 28,350.0
21,419.1 47,447.4
1,440.0 1,440.0
108.8 217.6
54.4 108.8
2.9 6.4
3.5 7.7
35.4 78.6
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
en
CD
Total Power Requirements (per
model well) for Seven Selected
Energy-Consuming Activities
(hp):
These seven energy-consuming activities were selected for inclusion
24,071.8 48,871.9 35,862.0 77,656.5 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 7 Page 4 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.3476
0.0323
0.3003
0.1705
0.0053
0.0096
0.0222
0.0008
0.0003
0.0004
0.0002
0.0006
0.0008
0.0000
0.0000
0.0004
0.0006
THC
0.0278
0.0045
0.0243
0.0731
0.0029
0.0051
0.0018
0.0001
0.0001
0.0000
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0231
0.0000
0.0197
0.0124
0.0004
0.0006
0.0015
0.0001
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0000
CO
0.0752
0.0206
0.0670
0.0341
0.0008
0.0014
0.0048
0.0002
0.0001
0.0001
0.0002
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0248
0.0000
0.0211
0.0144
0.0004
0.0008
0.0016
0.0001
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0000
Total
0.4985
0.0574
0.4324
0.3044
0.0097
0.0175
0.0319
0.0012
0.0006
0.0006
0.0005
0.0026
0.0013
0.0000
0.0001
0.0005
0.0013
>
o
Total Per Well
0.5103
0.1076
0.0347
0.1090
0.0384
0.8000
Note: On-shore Injection air emissions assume that diesel engines are used for electricity generation
-------
Worksheet No. 7 Page 5 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.7286
0.0677
0.6294
0.1705
0.0053
0.0106
0.0222
0.0017
0.0007
0.0008
0.0002
0.0006
0.0008
0.0001
0.0001
0.0008
0.0010
THC
0.0583
0.0094
0.0509
0.0731
0.0029
0.0057
0.0018
0.0001
0.0003
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
SO2
0.0484
0.0001
0.0412
0.0124
0.0004
0.0007
0.0015
0.0001
0.0000
0.0001
0.0000
0.0000
0.0001
0.0000
0.0000
0.0001
0.0001
CO
0.1577
0.0432
0.1405
0.0341
0.0008
0.0015
0.0048
0.0004
0.0001
0.0002
0.0002
0.0018
0.0002
0.0000
0.0000
0.0002
0.0006
TSP
0.0520
0.0000
0.0442
0.0144
0.0004
0.0008
0.0016
0.0001
0.0001
0.0001
0.0000
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
Total
1.0450
0.1203
0.9063
0.3044
0.0097
0.0194
0.0319
0.0024
0.0012
0.0012
0.0005
0.0026
0.0013
0.0001
0.0001
0.0011
0.0018
Total Per Well
0.8425
0.1351
0.0564
0.1831
0.0617
1.2788
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 7 Page 6 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.5280
0.0490
0.4562
0.1705
0.0053
0.0106
0.0222
0.0017
0.0007
0.0008
0.0002
0.0006
0.0008
0.0000
0.0001
0.0005
0.0008
THC
0.0422
0.0068
0.0369
0.0731
0.0029
0.0057
0.0018
0.0001
0.0003
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0351
0.0001
0.0299
0.0124
0.0004
0.0007
0.0015
0.0001
0.0000
0.0001
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0001
CO
0.1143
0.0313
0.1018
0.0341
0.0008
0.0015
0.0048
0.0004
0.0001
0.0002
0.0002
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0377
0.0000
0.0321
0.0144
0.0004
0.0008
0.0016
0.0001
0.0001
0.0001
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
Total
0.7574
0.0872
0.6569
0.3044
0.0097
0.0194
0.0319
0.0024
0.0012
0.0012
0.0005
0.0026
0.0013
0.0001
0.0001
0.0008
0.0015
>
ro
Total Per Well
0.6690
0.1210
0.0451
0.1444
0.0496
1.0291
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 7 Page 7 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
1.1697
0.1086
1.0105
0.1705
0.0053
0.0127
0.0222
0.0034
0.0013
0.0017
0.0002
0.0006
0.0008
0.0001
0.0001
0.0012
0.0014
THC
0.0936
0.0150
0.0818
0.0731
0.0029
0.0069
0.0018
0.0003
0.0006
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
SO2
0.0778
0.0002
0.0661
0.0124
0.0004
0.0009
0.0015
0.0002
0.0001
0.0001
0.0000
0.0000
0.0001
0.0000
0.0000
0.0001
0.0001
CO
0.2532
0.0693
0.2256
0.0341
0.0008
0.0018
0.0048
0.0007
0.0003
0.0004
0.0002
0.0018
0.0002
0.0000
0.0000
0.0003
0.0006
TSP
0.0836
0.0000
0.0710
0.0144
0.0004
0.0010
0.0016
0.0002
0.0001
0.0001
0.0000
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
Total
1.6778
0.1932
1.4551
0.3044
0.0097
0.0233
0.0319
0.0048
0.0023
0.0024
0.0005
0.0026
0.0013
0.0001
0.0002
0.0017
0.0024
Total Per Well
1.2293
0.1676
0.0818
0.2692
0.0890
1.8368
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 7 Page 8 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (GOM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Summary Air Emissions (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.5103
0.8425
0.6690
1.2293
THC
0.1076
0.1351
0.1210
0.1676
S02
0.0347
0.0564
0.0451
0.0818
CO
0.1090
0.1831
0.1444
0.2692
TSP
0.0384
0.0617
0.0496
0.0890
Total
0.8000
1.2788
1.0291
1.8368
Total Per Day
0.1538
0.1173
0.1303
0.1050
Summary Fuel Usage (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
2,603.9
4,257.6
3,393.4
6,182.2
Barrels of Oil
Equivalent
(BOE)
62.0
101.4
80.8
147.2
Barrels of Oil Equivalent
(BOE) per day
11.9
9.3
10.2
8.4
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 7 Page 9 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Daily Drill Rig Emissions
Offshore Gulf of Mexico (GOM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
CD
cn
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
GOM BAT2 Daily Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @ 3.82%)
Total Air
Emissions
(tons)
3,817.9914
4,746.5830
792.0505
5,035.5166
Barrels of Oil
Equivalent
(BOE)
243,930.3
303,024.3
50,578.5
321,384.2
OBF (Zero Discharge)
Total Air
Emissions
(tons)
806.3927
1,002.9762
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
51,528.7
64,027.1
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air Emissions (tons)
28,885.6052
35,267.3896
1,007.7722
6,900.1667
Barrels of Oil Equivalent
(BOE)
1,842,243.1
2,249,255.5
64,272.9
440,073.3
TOTAL
1,809.4 115,555.9
14,392.1 918,917.3
88,262.4
5,630,318.0
Note: Summary annual air emission/fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
124 SWD wells, 74 SWE wells, 17 DWD wells, and 49 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM OBF wells (existing sources) under this technology option:
25 SWD wells, 15 SWE wells, 0 DWD wells, and 0 OWE wells
479 SWD wells, 279 SWE wells, 11 DWD wells, and 34 OWE wells
Note: 1 BOE = 42 gallons of diesel
72,060.9
4,595,844.8
-------
Worksheet No. 7 Page 10 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore Gulf of Mexico (GOM)
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Annual Air Emissions (SBF BAT2 Model Well - Discharging at 3.82% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
2,098.9111
1,277.1565
290.4524
864.6403
THC
1,106.5321
662.3836
151.9306
440.1983
SO2
142.9077
86.8930
19.7689
58.7786
CO
305.2924
187.6701
42.4552
128.4894
TSP
164.3481
99.8073
22.7215
67.4222
Total
3,817.9914
2,313.9106
527.3287
1,559.5288
Total 4,531.1603 2,361.0446 308.3483
Annual Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20%CRN)
663.9071
354.2991
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
443.0487
550.9498
0.0000
0.0000
THC
233.5919
291.0989
0.0000
0.0000
S02
30.2045
37.5329
0.0000
0.0000
CO
64.7911
80.2084
0.0000
0.0000
TSP
34.7565
43.1862
0.0000
0.0000
Total
806.3927
1,002.9762
0.0000
0.0000
Total
993.9986
524.6908
67.7374
144.9995
77.9427
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
15,780.7080
19,267.1877
550.5635
3,769.6809
THC
8,450.1591
10,317.0784
294.8124
2,018.5662
SO2
1,074.3659
1,311.7288
37.4829
256.6435
CO
2,266.1832
2,766.8579
79.0635
541.3438
TSP
1,236.7267
1,509.9605
43.1474
295.4281
Total
28,808.1429
35,172.8133
1,005.0697
6,881.6625
Total
39,368.1402
21,080.6161
2,680.2211
5,653.4484 3,085.2627
Note: Summary annual air emissions totals assume the following number of GOM SBF wells (existing sources) under this technology option:
124 SWD wells, 74 SWE wells, 17 DWD wells, and 49 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM OBF wells (existing sources) under this technology option:
25 SWD wells, 15 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM WBF wells (existing sources) under this technology option:
479 SWD wells, 279 SWE wells, 11 DWD wells, and 34 OWE wells
-------
Worksheet No. 8 Page 1 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Fuel-Consuming Activity
Cuttings Dryer Discharge
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
748.8 1,569.6
0.0 0.0
0.0 0.0
0.0 0.0
0.0 0.0
25.3 25.3
0.0 0.0
45.5 50.6
144.0 144.0
3.3 6.7
0.0 0.0
75.0 75.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
1,137.6 2,520.0
0.0 0.0
0.0 0.0
0.0 0.0
0.0 0.0
25.3 25.3
0.0 0.0
50.6 60.7
144.0 144.0
6.7 13.3
0.0 0.0
75.0 150.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
EPA assumes that the volume of fines waste can be managed via
regular supply boats
EPA assumes that the volume of fines waste can be managed via
regular supply boats
Subtotal
1,790.8
3,440.8
2,576.8
5,433.3
-------
Worksheet No. 8 Page 2 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Fuel-Consuming Activity
Zero Discharge of Fines (cont.)
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojnj:sJhj3reJ^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.1 0.2
0.1 0.2
0.1 0.2
0.3 0.7
9.4 9.7
Deep Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.2 0.4
0.2 0.4
0.2 0.4
0.5 1.2
9.5 10.1
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (20%/80%) of offshore wastes sent on-shore
>
oo
TOTAL Diesel Per Well (Gal)
1,800.2
3,450.5
2,586.3 5,443.4
-------
Worksheet No. 8 Page 3 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
>
CD
Energy-Consuming Activity
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
14,098.7 29,553.0
1,440.0 1,440.0
54.4 108.8
0.0 0.0
1.9 4.0
2.3 4.8
23.4 49.0
Deep Water
Development | Exploratory
12,798.0 28,350.0
21,419.1 47,447.4
1,440.0 1,440.0
108.8 217.6
0.0 0.0
2.9 6.4
3.5 7.7
35.4 78.6
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
Total Power Requirements (per
model well) for Seven Selected
Energy-Consuming Activities
(hp):
These seven energy-consuming activities were selected for inclusion
24,044.6 48,817.5 35,807.6 77,547.7 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 8 Page 4 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.3476
0.0323
0.0323
0.0000
0.0053
0.0096
0.0222
0.0008
0.0000
0.0000
0.0037
0.0006
0.0008
0.0000
0.0000
0.0004
0.0006
THC
0.0278
0.0045
0.0045
0.0000
0.0029
0.0051
0.0018
0.0001
0.0000
0.0000
0.0008
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0231
0.0000
0.0000
0.0000
0.0004
0.0006
0.0015
0.0001
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0000
CO
0.0752
0.0206
0.0206
0.0000
0.0008
0.0014
0.0048
0.0002
0.0000
0.0000
0.0028
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0248
0.0000
0.0000
0.0000
0.0004
0.0008
0.0016
0.0001
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0000
Total
0.4985
0.0574
0.0574
0.0000
0.0097
0.0175
0.0319
0.0012
0.0000
0.0000
0.0074
0.0026
0.0013
0.0000
0.0001
0.0005
0.0013
>
o
Total Per Well
0.0745
0.0152
0.0026
0.0310
0.0029
0.1263
Note: On-shore Injection air emissions assume that diesel engines are used for electricity generation
-------
Worksheet No. 8 Page 5 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.7286
0.0677
0.0677
0.0000
0.0053
0.0106
0.0222
0.0017
0.0000
0.0000
0.0037
0.0006
0.0008
0.0001
0.0001
0.0008
0.0010
THC
0.0583
0.0094
0.0094
0.0000
0.0029
0.0057
0.0018
0.0001
0.0000
0.0000
0.0008
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
SO2
0.0484
0.0001
0.0001
0.0000
0.0004
0.0007
0.0015
0.0001
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0001
0.0001
CO
0.1577
0.0432
0.0432
0.0000
0.0008
0.0015
0.0048
0.0004
0.0000
0.0000
0.0028
0.0018
0.0002
0.0000
0.0000
0.0002
0.0006
TSP
0.0520
0.0000
0.0000
0.0000
0.0004
0.0008
0.0016
0.0001
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
Total
1.0450
0.1203
0.1203
0.0000
0.0097
0.0194
0.0319
0.0024
0.0000
0.0000
0.0074
0.0026
0.0013
0.0001
0.0001
0.0011
0.0018
Total Per Well
0.1122
0.0208
0.0028
0.0540
0.0030
0.1929
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 8 Page 6 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.5280
0.0490
0.0490
0.0000
0.0053
0.0106
0.0222
0.0017
0.0000
0.0000
0.0037
0.0006
0.0008
0.0000
0.0001
0.0005
0.0008
THC
0.0422
0.0068
0.0068
0.0000
0.0029
0.0057
0.0018
0.0001
0.0000
0.0000
0.0008
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0351
0.0001
0.0001
0.0000
0.0004
0.0007
0.0015
0.0001
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0001
CO
0.1143
0.0313
0.0313
0.0000
0.0008
0.0015
0.0048
0.0004
0.0000
0.0000
0.0028
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0377
0.0000
0.0000
0.0000
0.0004
0.0008
0.0016
0.0001
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
Total
0.7574
0.0872
0.0872
0.0000
0.0097
0.0194
0.0319
0.0024
0.0000
0.0000
0.0074
0.0026
0.0013
0.0001
0.0001
0.0008
0.0015
>
ro
Total Per Well
0.0934
0.0182
0.0028
0.0421
0.0030
0.1595
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 8 Page 7 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
1.1697
0.1086
0.1086
0.0000
0.0053
0.0127
0.0222
0.0034
0.0000
0.0000
0.0074
0.0006
0.0008
0.0001
0.0001
0.0012
0.0014
THC
0.0936
0.0150
0.0150
0.0000
0.0029
0.0069
0.0018
0.0003
0.0000
0.0000
0.0016
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
SO2
0.0778
0.0002
0.0002
0.0000
0.0004
0.0009
0.0015
0.0002
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0001
0.0001
CO
0.2532
0.0693
0.0693
0.0000
0.0008
0.0018
0.0048
0.0007
0.0000
0.0000
0.0056
0.0018
0.0002
0.0000
0.0000
0.0003
0.0006
TSP
0.0836
0.0000
0.0000
0.0000
0.0004
0.0010
0.0016
0.0002
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0001
0.0001
Total
1.6778
0.1932
0.1932
0.0000
0.0097
0.0233
0.0319
0.0048
0.0000
0.0000
0.0147
0.0026
0.0013
0.0001
0.0002
0.0017
0.0024
Total Per Well
0.1611
0.0286
0.0032
0.0837
0.0034
0.2800
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 8 Page 8 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Summary Air Emissions (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0745
0.1122
0.0934
0.1611
THC
0.0152
0.0208
0.0182
0.0286
SO2
0.0026
0.0028
0.0028
0.0032
CO
0.0310
0.0540
0.0421
0.0837
TSP
0.0029
0.0030
0.0030
0.0034
Total
0.1263
0.1929
0.1595
0.2800
Total Per Day
0.0243
0.0177
0.0202
0.0160
Summary Fuel Usage (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
1,800.2
3,450.5
2,586.3
5,443.4
Barrels of Oil
Equivalent
(BOE)
42.9
82.2
61.6
129.6
Barrels of Oil Equivalent
(BOE) per day
8.2
7.5
7.8
7.4
>
--J
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 8 Page 9 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Daily Drill Rig Emissions
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
>
en
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
CA BAT2 Daily Emissions/Fuel Usage
61,552.0
1,465.5
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @ 3.82%)
Total Air
Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
0.0
0.0
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air
Emissions
(tons)
180.9119
252.8128
0.000
0.0000
Barrels of Oil
Equivalent
(BOE)
11,538.1
16,123.7
0.0
0.0
OBF (Zero Discharge)
Total Air Emissions (tons)
30.5288
63.8108
0.0000
0.0000
Barrels of Oil Equivalent
(BOE)
1,986.8
4,151.8
0.0
0.0
TOTAL
0.0
0.0
433.7 27,661.8
528.1
33,800.3
Note: Summary annual air emission/fuel usage totals assume the following number of SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of OBF wells (existing sources) under this technology option:
1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note:!
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
94.3
6,138.6
-------
Worksheet No. 8 Page 10 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Offshore California
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Annual Air Emissions (SBF BAT2 Model Well - Discharging at 3.82% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
0.0000
0.0000
THC
0.0000
0.0000
0.0000
0.0000
SO2
0.0000
0.0000
0.0000
0.0000
CO
0.0000
0.0000
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
0.0000
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
16.7158
16.9423
0.0000
0.0000
THC
8.9378
18.6914
0.0000
0.0000
SO2
1.1344
2.3705
0.0000
0.0000
CO
2.4347
5.0824
0.0000
0.0000
TSP
1.3061
2.7293
0.0000
0.0000
Total
30.5288
45.8159
0.0000
0.0000
Total
33.6581
27.6292
3.5050
7.5171
4.0353
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
138.1160
0.0000
0.0000
THC
52.9238
73.9576
0.0000
0.0000
SO2
6.7288
9.4031
0.0000
0.0000
CO
14.1932
19.8341
0.0000
0.0000
TSP
7.7457
10.8241
0.0000
0.0000
Total
180.4268
252.1349
0.0000
0.0000
Total 236.9514 126.8813 16.1319 34.0273
Note: Summary annual air emissions totals assume the following number of SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of OBF wells (existing sources) under this technology option:
1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of WBF wells (existing sources) for baseline current practice
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 OWE wells
18.5698
-------
Worksheet No. 9 Page 1 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Fuel-Consuming Activity
Cuttings Dryer Discharge
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
748.8 1,569.6
0.0 0.0
0.0 0.0
0.0 0.0
0.0 0.0
25.3 25.3
0.0 0.0
55.7 75.9
144.0 144.0
10.0 23.3
0.0 0.0
550.0 550.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
1,137.6 2,520.0
0.0 0.0
0.0 0.0
0.0 0.0
0.0 0.0
25.3 25.3
0.0 0.0
65.8 96.1
144.0 144.0
16.7 36.7
0.0 0.0
550.0 1,100.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
EPA assumes that the volume of fines waste can be managed via
regular supply boats
EPA assumes that the volume of fines waste can be managed via
regular supply boats
Subtotal
2,282.6
3,957.7
3,076.9
6,442.1
-------
Worksheet No. 9 Page 2 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Fuel-Consuming Activity
Zero Discharge of Fines (cont.)
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojnj:sJhj3reJ^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.1 0.2
0.1 0.2
0.1 0.2
0.3 0.7
0.0 0.0
Deep Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.2 0.4
0.2 0.4
0.2 0.4
0.5 1.2
0.0 0.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (0%/0%) of offshore wastes sent on-shore
>
oo
TOTAL Diesel Per Well (Gal)
2,282.6
3,957.7
3,076.9
6,442.1
-------
Worksheet No. 9 Page 3 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Energy-Consuming Activity
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
14,098.7 29,553.0
1,440.0 1,440.0
163.2 380.8
0.0 0.0
1.9 4.0
2.3 4.8
23.4 49.0
Deep Water
Development | Exploratory
12,798.0 28,350.0
21,419.1 47,447.4
1,440.0 1,440.0
272.0 598.4
0.0 0.0
2.9 6.4
3.5 7.7
35.4 78.6
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
>
CD
Total Power Requirements (per
model well) for Seven Selected
Energy-Consuming Activities
(hp):
These seven energy-consuming activities were selected for inclusion
24,153.4 49,089.5 35,970.8 77,928.5 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 9 Page 4 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.3476
0.0323
0.0323
0.0000
0.0053
0.0117
0.0222
0.0025
0.0000
0.0000
0.0272
0.0006
0.0008
0.0000
0.0000
0.0004
0.0000
THC
0.0278
0.0045
0.0045
0.0000
0.0029
0.0063
0.0018
0.0002
0.0000
0.0000
0.0060
0.0001
0.0001
0.0000
0.0000
0.0000
0.0000
SO2
0.0231
0.0000
0.0000
0.0000
0.0004
0.0008
0.0015
0.0002
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0000
CO
0.0752
0.0206
0.0206
0.0000
0.0008
0.0017
0.0048
0.0005
0.0000
0.0000
0.0207
0.0018
0.0002
0.0000
0.0000
0.0001
0.0000
TSP
0.0248
0.0000
0.0000
0.0000
0.0004
0.0009
0.0016
0.0002
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0000
Total
0.4985
0.0574
0.0574
0.0000
0.0097
0.0213
0.0319
0.0036
0.0000
0.0000
0.0540
0.0026
0.0013
0.0000
0.0001
0.0005
0.0000
oo
o
Total Per Well
0.1012
0.0216
0.0028
0.0491
0.0031
0.1779
Note: On-shore Injection air emissions assume that diesel engines are used for electricity generation
-------
Worksheet No. 9 Page 5 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.7286
0.0677
0.0677
0.0000
0.0053
0.0159
0.0222
0.0059
0.0000
0.0000
0.0272
0.0006
0.0008
0.0001
0.0001
0.0008
0.0000
THC
0.0583
0.0094
0.0094
0.0000
0.0029
0.0086
0.0018
0.0005
0.0000
0.0000
0.0060
0.0001
0.0001
0.0000
0.0000
0.0001
0.0000
SO2
0.0484
0.0001
0.0001
0.0000
0.0004
0.0011
0.0015
0.0004
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0001
0.0000
CO
0.1577
0.0432
0.0432
0.0000
0.0008
0.0023
0.0048
0.0013
0.0000
0.0000
0.0207
0.0018
0.0002
0.0000
0.0000
0.0002
0.0000
TSP
0.0520
0.0000
0.0000
0.0000
0.0004
0.0013
0.0016
0.0004
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0001
0.0000
Total
1.0450
0.1203
0.1203
0.0000
0.0097
0.0291
0.0319
0.0084
0.0000
0.0000
0.0540
0.0026
0.0013
0.0001
0.0001
0.0011
0.0000
oo
Total Per Well
0.1442
0.0291
0.0034
0.0730
0.0037
0.2534
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 9 Page 6 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.5280
0.0490
0.0490
0.0000
0.0053
0.0138
0.0222
0.0042
0.0000
0.0000
0.0272
0.0006
0.0008
0.0000
0.0001
0.0005
0.0000
THC
0.0422
0.0068
0.0068
0.0000
0.0029
0.0074
0.0018
0.0003
0.0000
0.0000
0.0060
0.0001
0.0001
0.0000
0.0000
0.0000
0.0000
SO2
0.0351
0.0001
0.0001
0.0000
0.0004
0.0009
0.0015
0.0003
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0000
CO
0.1143
0.0313
0.0313
0.0000
0.0008
0.0020
0.0048
0.0009
0.0000
0.0000
0.0207
0.0018
0.0002
0.0000
0.0000
0.0001
0.0000
TSP
0.0377
0.0000
0.0000
0.0000
0.0004
0.0011
0.0016
0.0003
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0000
Total
0.7574
0.0872
0.0872
0.0000
0.0097
0.0252
0.0319
0.0060
0.0000
0.0000
0.0540
0.0026
0.0013
0.0001
0.0001
0.0008
0.0000
oo
ro
Total Per Well
0.1218
0.0252
0.0031
0.0604
0.0034
0.2140
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 9 Page 7 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarmin
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
1.1697
0.1086
0.1086
0.0000
0.0053
0.0202
0.0222
0.0092
0.0000
0.0000
0.0545
3)
0.0006
0.0008
0.0001
0.0001
0.0012
0.0000
THC
0.0936
0.0150
0.0150
0.0000
0.0029
0.0109
0.0018
0.0007
0.0000
0.0000
0.0121
0.0001
0.0001
0.0000
0.0000
0.0001
0.0000
S02
0.0778
0.0002
0.0002
0.0000
0.0004
0.0014
0.0015
0.0006
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0001
0.0000
CO
0.2532
0.0693
0.0693
0.0000
0.0008
0.0029
0.0048
0.0020
0.0000
0.0000
0.0414
0.0018
0.0002
0.0000
0.0000
0.0003
0.0000
TSP
0.0836
0.0000
0.0000
0.0000
0.0004
0.0016
0.0016
0.0007
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0001
0.0000
Total
1.6778
0.1932
0.1932
0.0000
0.0097
0.0369
0.0319
0.0132
0.0000
0.0000
0.1079
0.0026
0.0013
0.0001
0.0002
0.0017
0.0000
>
oo
Total Per Well
0.2200
0.0434
0.0040
0.1212
0.0043
0.3928
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 9 Page 8 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Summary Air Emissions (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.1012
0.1442
0.1218
0.2200
THC
0.0216
0.0291
0.0252
0.0434
S02
0.0028
0.0034
0.0031
0.0040
CO
0.0491
0.0730
0.0604
0.1212
TSP
0.0031
0.0037
0.0034
0.0043
Total
0.1779
0.2534
0.2140
0.3928
Total Per Day
0.0342
0.0232
0.0271
0.0224
Summary Fuel Usage (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
2,282.6
3,957.7
3,076.9
6,442.1
Barrels of Oil
Equivalent
(BOE)
54.3
94.2
73.3
153.4
Barrels of Oil Equivalent
(BOE) per day
10.5
8.6
9.3
8.8
ยฃ
00
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 9 Page 9 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Daily Drill Rig Emissions
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
oo
en
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
AK BAT2 Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @ 3.82%)
Total Air
Emissions
(tons)
30.1682
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
1,959.5
0.0
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air
Emissions
(tons)
180.9119
126.4064
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
11,538.1
8,061.8
0.0
0.0
OBF (Zero Discharge)
Total Air Emissions (tons)
0.0000
63.0755
0.0000
0.0000
Barrels of Oil Equivalent
(BOE)
0.0
4,107.5
0.0
0.0
TOTAL
1,959.5
307.3
19,599.9
30.2
400.6
25,666.9
Note: Summary annual air emission/fuel usage totals assume the following number of SBF wells (existing sources) under this technology option:
1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of OBF wells (existing sources) under this technology option:
0 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of WBF wells (existing sources) under this technology option:
3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
63.1
4,107.5
-------
Worksheet No. 9 Page 10 of 10
BAT Non-Water Quality Environmental Impacts: BAT Option 2
Region:
Technology:
Cook Inlet, AK
SBF Discharge from BAT Solids Control System (e.g., Cuttings Dryer only at 3.82%CRN) & ZD of fines
Annual Air Emissions (SBF BAT1 Model Well - Discharging at 3.82% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
16.5176
0.0000
0.0000
0.0000
THC
8.8377
0.0000
0.0000
0.0000
SO2
1.1206
0.0000
0.0000
0.0000
CO
2.4021
0.0000
0.0000
0.0000
TSP
1.2901
0.0000
0.0000
0.0000
Total
30.1682
0.0000
0.0000
0.0000
Total
16.5176
8.8377
1.1206
2.4021
1.2901
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
0.0000
16.5352
0.0000
0.0000
THC
0.0000
8.8325
0.0000
0.0000
SO2
0.0000
1.1180
0.0000
0.0000
CO
0.0000
2.4288
0.0000
0.0000
TSP
0.0000
1.2870
0.0000
0.0000
Total
0.0000
30.2015
0.0000
0.0000
Total
16.5352
8.8325
1.1180
2.4288
1.2870
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
69.0580
0.0000
0.0000
THC
52.9238
36.9788
0.0000
0.0000
SO2
6.7288
4.7015
0.0000
0.0000
CO
14.1932
9.9171
0.0000
0.0000
TSP
7.7457
5.4120
0.0000
0.0000
Total
180.4268
126.0674
0.0000
0.0000
Total 167.8934 89.9025 11.4303 24.1103
Note: Summary annual air emissions totals assume the following number of SBF wells (existing sources) under this technology option:
1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of OBF wells (existing sources) under this technology option:
0 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of WBF wells (existing sources) under this technology option:
3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
13.1577
-------
Worksheet No. 10 Page 1 of 7
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
Baseline Solids Control
Equipment
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
0.0 870.4
3,131.3 3,131.3
3,131.3 4,001.7
61.7 128.3
25.3 50.6
3,197.9 6,532.5
0.0 101.2
144.0 288.0
123.3 256.6
61.6 128.3
40.0 85.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
0.0 870.4
3,131.3 6,262.6
3,131.3 7,133.0
93.3 206.7
25.3 75.9
4,837.4 10,580.5
0.0 101.2
144.0 432.0
186.6 413.2
93.3 206.6
60.0 130.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
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.
ยฃ
oo
Subtotal
7,533.9
13,141.8
9,708.8
21,799.0
-------
Worksheet No. 10 Page 2 of 7
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojijshio^^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
4.4 9.2
4.4 9.2
4.4 9.2
13.2 27.7
83.6 95.2
Deep Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
6.7 14.8
6.7 14.8
6.7 14.8
20.0 44.5
89.1 108.7
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (20%/80%) of offshore wastes sent on-shore
oo
oo
TOTAL Diesel Per Well (Gal)
7,617.6
13,237.0
9,797.9 21,907.7
-------
Worksheet No. 10 Page 3 of 7
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Energy-Consuming Activity
Baseline Solids Control
Equipment
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
1,440.0 2,880.0
2,012.8 4,188.8
1,006.4 2,094.4
73.5 153.9
88.1 184.7
899.9 1,885.7
Deep Water
Development | Exploratory
12,798.0 28,350.0
1,440.0 4,320.0
3,046.4 6,745.6
1,523.2 3,372.8
111.2 247.2
133.4 296.6
1,361.7 3,027.7
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
oo
CD
Total Power Requirements
(per model well) for Seven
Selected Energy-Consuming
Activities (hp):
These seven energy-consuming activities were selected for inclusion
13,944.7 29,045.6 20,413.9 46,359.8 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 10 Page 4 of 7
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1300
0.0121
0.1123
0.6133
0.0053
0.6709
0.0222
0.0311
0.0121
0.0155
0.0020
0.0051
0.0066
0.0011
0.0014
0.0139
0.0154
THC
0.0104
0.0017
0.0091
0.2630
0.0029
0.3614
0.0018
0.0025
0.0052
0.0012
0.0004
0.0008
0.0008
0.0001
0.0001
0.0011
0.0014
S02
0.0086
0.0000
0.0074
0.0446
0.0004
0.0455
0.0015
0.0021
0.0009
0.0010
0.0000
0.0004
0.0006
0.0001
0.0001
0.0009
0.0011
CO
0.0281
0.0077
0.0251
0.1226
0.0008
0.0956
0.0048
0.0067
0.0024
0.0034
0.0015
0.0144
0.0016
0.0002
0.0003
0.0030
0.0060
TSP
0.0093
0.0000
0.0079
0.0517
0.0004
0.0528
0.0016
0.0022
0.0010
0.0011
0.0000
0.0005
0.0005
0.0001
0.0001
0.0010
0.0011
Total
0.1865
0.0215
0.1617
1.0951
0.0097
1 .2262
0.0319
0.0446
0.0216
0.0223
0.0039
0.0211
0.0101
0.0016
0.0020
0.0199
0.0250
CD
O
Total Per Well
1.5001
0.6488
0.1044
0.2689
0.1198
2.6420
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 10 Page 5 of 7
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.2725
0.0253
0.2354
0.7837
0.0106
1.3917
0.0444
0.0646
0.0251
0.0323
0.0042
0.0051
0.0066
0.0024
0.0029
0.0291
0.0298
THC
0.0218
0.0035
0.0191
0.3361
0.0057
0.7496
0.0036
0.0052
0.0108
0.0026
0.0009
0.0008
0.0008
0.0002
0.0002
0.0023
0.0025
S02
0.0181
0.0000
0.0154
0.0570
0.0007
0.0945
0.0030
0.0043
0.0018
0.0021
0.0000
0.0004
0.0006
0.0002
0.0002
0.0019
0.0020
CO
0.0590
0.0162
0.0526
0.1567
0.0015
0.1983
0.0096
0.0140
0.0050
0.0070
0.0032
0.0144
0.0016
0.0005
0.0006
0.0063
0.0091
TSP
0.0195
0.0000
0.0165
0.0660
0.0008
0.1095
0.0032
0.0046
0.0021
0.0023
0.0000
0.0005
0.0005
0.0002
0.0002
0.0021
0.0022
Total
0.3909
0.0450
0.3390
1.3996
0.0194
2.5436
0.0637
0.0927
0.0449
0.0464
0.0083
0.0211
0.0101
0.0034
0.0041
0.0417
0.0456
>
CD
Total Per Well
2.6221
1.1361
0.1808
0.4570
0.2072
4.6032
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 10 Page 6 of 7
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1975
0.0183
0.1706
0.6133
0.0053
1.0149
0.0222
0.0470
0.0183
0.0235
0.0030
0.0051
0.0066
0.0017
0.0021
0.0210
0.0222
THC
0.0158
0.0025
0.0138
0.2630
0.0029
0.5466
0.0018
0.0038
0.0078
0.0019
0.0007
0.0008
0.0008
0.0001
0.0002
0.0017
0.0019
S02
0.0131
0.0000
0.0112
0.0446
0.0004
0.0689
0.0015
0.0031
0.0013
0.0016
0.0000
0.0004
0.0006
0.0001
0.0001
0.0014
0.0015
CO
0.0427
0.0117
0.0381
0.1226
0.0008
0.1446
0.0048
0.0102
0.0037
0.0051
0.0023
0.0144
0.0016
0.0004
0.0004
0.0045
0.0075
TSP
0.0141
0.0000
0.0120
0.0517
0.0004
0.0798
0.0016
0.0034
0.0015
0.0017
0.0000
0.0005
0.0005
0.0001
0.0001
0.0015
0.0016
Total
0.2833
0.0326
0.2457
1.0951
0.0097
1.8548
0.0319
0.0674
0.0326
0.0337
0.0059
0.0211
0.0101
0.0025
0.0030
0.0301
0.0347
CD
ro
Total Per Well
1.9402
0.8441
0.1340
0.3395
0.1537
3.4116
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 10 Page 7 of 7
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtot
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarmir
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.4375
0.0406
0.3780
1.3970
0.0159
2.2410
0.0667
0.1041
0.0405
0.0520
0.0064
g)
0.0051
0.0066
0.0038
0.0046
0.0467
0.0464
THC
0.0350
0.0056
0.0306
0.5992
0.0086
1.2070
0.0053
0.0083
0.0174
0.0042
0.0014
0.0008
0.0008
0.0003
0.0004
0.0037
0.0038
SO2
0.0291
0.0001
0.0247
0.1016
0.0011
0.1521
0.0044
0.0069
0.0029
0.0035
0.0000
0.0004
0.0006
0.0003
0.0003
0.0031
0.0031
CO
0.0947
0.0259
0.0844
0.2793
0.0023
0.3194
0.0144
0.0225
0.0081
0.0113
0.0049
0.0144
0.0016
0.0008
0.0010
0.0101
0.0127
TSP
0.0313
0.0000
0.0266
0.1177
0.0013
0.1762
0.0048
0.0074
0.0034
0.0037
0.0000
0.0005
0.0005
0.0003
0.0003
0.0033
0.0034
Total
0.6275
0.0723
0.5442
2.4947
0.0291
4.0958
0.0956
0.1493
0.0723
0.0747
0.0128
0.0211
0.0101
0.0055
0.0066
0.0670
0.0695
>
CD
Total Per Well
4.3481
1.8858
0.3004
0.7592
0.3444
7.6379
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 11 Page 1 of 2
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Offshore/On-Site Cuttings Injection
10.20% CRN
On-site Injection Diesel Fuel Requirements (per model well)
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
>
CD
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
748.8
748.8
748.8
36.7
1,569.6
1,569.6
1,569.6
76.8
1,137.6
1,137.6
1,137.6
55.5
2,520.0
2,520.0
2,520.0
123.4
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Hours of operation equals the drilling length in days (x 24 hr/day). The
transfer equipment utilizes one (1) 100 hp vacuum pump.
Hours of operation equals the drilling length in days (x 24 hr/day). Total
power utilized by the grinding and processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).Total power utilized by the grinding and
processing equipment is 600 hp.
TOTAL Diesel Per Well (Gal)
2,283.1
4,785.6
3,468.3
7,683.4
On-site Injection Energy Requirements (per model well)
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Pump Injection
8,424.0
12,480.0
14,976.0
3,667.0
17,658.0
26,160.0
31,392.0
7,684.5
12,798.0
18,960.0
22,752.0
5,549.2
28,350.0
42,000.0
50,400.0
12,338.1
Total Power Requirements
(per model well) for Four
Activities (hp):
39,547.0
82,894.5
60,059.2 133,088.1
These four energy-consuming activities were selected for inclusion in
this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 11 Page 2 of 2
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Offshore/On-Site Cuttings Injection @ 10.20% CRN
On-site Injection Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.6103
1.2792
0.9268
2.0538
THC
0.0488
0.1023
0.0741
0.1643
SO2
0.0406
0.0851
0.0616
0.1366
CO
0.1321
0.2769
0.2006
0.4445
TSP
0.0436
0.0914
0.0662
0.1467
Total
0.8754
1.8349
1.3294
2.9459
On-site Injection Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0861
0.1907
THC
0.0078
0.0164
0.0119
0.0264
SO2
0.0001
0.0002
0.0001
0.0003
CO
0.0362
0.0758
0.0549
0.1218
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.1531
0.3392
CD
cn
Average On-site Injection Air Emissions (per model well) -Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%) for Electricity Generation
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.5273
1.1052
0.8007
1.7744
THC
0.0427
0.0895
0.0648
0.1436
SO2
0.0345
0.0723
0.0524
0.1161
CO
0.1177
0.2467
0.1787
0.3961
TSP
0.0371
0.0777
0.0563
0.1247
Total
0.7592
1.5913
1.1530
2.5549
-------
Worksheet No. 12 Page 1 of 3
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Summary Air Emissions (per model well) - Weighted by Land Disposal/On-site Injection Percentage Split
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
1.3055
2.3187
1.9402
4.3481
THC
0.5276
0.9267
0.8441
1.8858
SO2
0.0904
0.1591
0.1340
0.3004
CO
0.2386
0.4150
0.3395
0.7592
TSP
0.1033
0.1813
0.1537
0.3444
Total
2.2654
4.0009
3.4116
7.6379
Total Per Day
0.4357
0.3671
0.4318
0.4365
Note: Weighted summary air emissions totals assume the land disposal/on-site injection percentage splits are (80%/20%), (80%/20%), (100%/0%), and (100%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
Summary Fuel Usage (per model well) -Weighted by Land Disposal/On-site Injection Percentage Split
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
6,550.7
11,546.7
9,797.9
21,907.7
Barrels of Oil
Equivalent
(BOE)
156.0
274.9
233.3
521.6
Barrels of Oil Equivalent
(BOE) per day
30.0
25.2
29.5
29.8
CD
CD
Note: Weighted summary fuel usage totals assume the land disposal/on-site injection percentage splits are (80%/20%), (80%/20%), (100%/0%), and (100%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 12 Page 2 of 3
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Daily Drill Rig Emissions
Offshore Gulf of Mexico (GOM)
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) i
: 10.20% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
GOM ZD Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Zero Discharge)
Total Air
Emissions
(tons)
0.0000
0.0000
146.9212
868.5339
Barrels of Oil
Equivalent
(BOE)
0.0
0.0
9,383.1
55,466.2
OBF (Zero Discharge)
Total Air
Emissions
(tons)
4,128.7307
5,081.7463
391.7899
2,714.1684
Barrels of Oil
Equivalent
(BOE)
263,827.1
324,404.1
25,021.5
173,332.0
WBF (Discharge @ 10.20%)
Total Air Emissions (tons)
30,815.3325
37,669.1115
1,557.4662
10,350.2500
Barrels of Oil Equivalent
(BOE)
1,965,315.7
2,402,430.6
99,330.8
660,110.0
TOTAL
12,316.4 786,584.7
1,015.5 64,849.3
93,724.1
5,978,621.1
Note: Summary annual air emission/fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 3 DWD wells, and 8 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 128 SWD wells, 76 SWE wells, 8 DWD wells, and 25 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM WBF wells (existing sources) under this technology option:
511 SWD wells, 298 SWE wells, 17 DWD wells, and 51 OWE wells
Note: 1 BOE = 42 gallons of diesel
80,392.2
5,127,187.2
-------
Worksheet No. 12 Page 3 of 3
BAT Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Annual Air Emissions (SBF BAT3 Model Well - Zero Discharge at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
55.0699
166.1158
THC
0.0000
0.0000
28.9806
85.6152
SO2
0.0000
0.0000
3.7554
11.3454
CO
0.0000
0.0000
8.0776
24.8978
TSP
0.0000
0.0000
4.3220
13.0515
Total
0.0000
0.0000
100.2056
301.0257
Total
221.1857
114.5958
15.1008
32.9754
17.3735
Annual Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
2,268.4095
2,791.4792
215.0443
1,489.8892
THC
1,195.9904
1,474.9011
113.9023
788.8830
S02
154.6472
190.1667
14.6576
101.5547
CO
331.7302
406.3893
31.3143
216.9494
TSP
177.9534
218.8100
16.8714
116.8921
Total
4,128.7307
5,081.7463
391.7899
2,714.1684
CD
00
Total
6,764.8222
3,573.6768
461.0261
986.3832
530.5269
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
16,834.9516
20,579.2901
850.8708
5,654.5214
THC
9,014.6791
11,019.6751
455.6192
3,027.8493
SO2
1,146.1398
1,401.0580
57.9281
384.9653
CO
2,417.5775
2,955.2820
122.1890
812.0156
TSP
1,319.3473
1,612.7893
66.6823
443.1422
Total
30,732.6952
37,568.0945
1,553.2895
10,322.4938
Total
43,919.6339
23,517.8227
2,990.0912
6,307.0641 3,441.9611
Note: Summary annual air emissions totals assume the following number of GOM SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 3 DWD wells, and 8 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 128 SWD wells, 76 SWE wells, 8 DWD wells, and 25 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM WBF wells (existing sources) under this technology option:
511 SWD wells, 298 SWE wells, 17 DWD wells, and 51 OWE wells
-------
Worksheet No. 13 Page 1 of 7
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
Baseline Solids Control
Equipment
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
0.0 0.0
2,260.9 2,260.9
2,260.9 2,260.9
0.0 0.0
25.3 50.6
3,197.9 6,532.5
0.0 101.2
144.0 288.0
123.3 256.6
0.0 0.0
1,425.0 2,925.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
0.0 0.0
2,260.9 4,521.7
2,260.9 4,521.7
0.0 0.0
25.3 75.9
4,837.4 10,580.5
0.0 101.2
144.0 432.0
186.6 413.2
0.0 0.0
2,100.0 4,650.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
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.
CD
CD
Subtotal
7,925.2
13,984.3
10,691.7
23,294.5
-------
Worksheet No. 13 Page 2 of 7
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojijshio^^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
4.4 9.2
4.4 9.2
4.4 9.2
13.2 27.7
83.6 95.2
Deep Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
6.7 14.8
6.7 14.8
6.7 14.8
20.0 44.5
89.1 108.7
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (20%/80%) of offshore wastes sent on-shore
ro
o
o
TOTAL Diesel Per Well (Gal)
8,008.8 14,079.5 10,780.8 23,403.1
-------
Worksheet No. 13 Page 3 of 7
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Energy-Consuming Activity
Baseline Solids Control
Equipment
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
1,440.0 2,880.0
2,012.8 4,188.8
0.0 0.0
73.5 153.9
88.1 184.7
899.9 1,885.7
Deep Water
Development | Exploratory
12,798.0 28,350.0
1,440.0 4,320.0
3,046.4 6,745.6
0.0 0.0
111.2 247.2
133.4 296.6
1,361.7 3,027.7
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
IV)
o
Total Power Requirements
(per model well) for Seven
Selected Energy-Consuming
Activities (hp):
These seven energy-consuming activities were selected for inclusion
12,938.3 26,951.2 18,890.7 42,987.0 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 13 Page 4 of 7
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Disposal
10.20% CRN
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1300
0.0121
0.0121
0.4428
0.0053
0.6709
0.0222
0.0311
0.0000
0.0000
0.0706
0.0051
0.0066
0.0011
0.0014
0.0139
0.0154
THC
0.0104
0.0017
0.0017
0.1899
0.0029
0.3614
0.0018
0.0025
0.0000
0.0000
0.0156
0.0008
0.0008
0.0001
0.0001
0.0011
0.0014
S02
0.0086
0.0000
0.0000
0.0322
0.0004
0.0455
0.0015
0.0021
0.0000
0.0000
0.0000
0.0004
0.0006
0.0001
0.0001
0.0009
0.0011
CO
0.0281
0.0077
0.0077
0.0885
0.0008
0.0956
0.0048
0.0067
0.0000
0.0000
0.0536
0.0144
0.0016
0.0002
0.0003
0.0030
0.0060
TSP
0.0093
0.0000
0.0000
0.0373
0.0004
0.0528
0.0016
0.0022
0.0000
0.0000
0.0000
0.0005
0.0005
0.0001
0.0001
0.0010
0.0011
Total
0.1865
0.0215
0.0215
0.7907
0.0097
1 .2262
0.0319
0.0446
0.0000
0.0000
0.1398
0.0211
0.0101
0.0016
0.0020
0.0199
0.0250
IV)
o
ro
Total Per Well
1.2704
0.5771
0.0827
0.2638
0.0954
2.2894
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 13 Page 5 of 7
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Disposal
10.20% CRN
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.2725
0.0253
0.0253
0.4428
0.0106
1.3917
0.0444
0.0646
0.0000
0.0000
0.1448
0.0051
0.0066
0.0024
0.0029
0.0291
0.0298
THC
0.0218
0.0035
0.0035
0.1899
0.0057
0.7496
0.0036
0.0052
0.0000
0.0000
0.0321
0.0008
0.0008
0.0002
0.0002
0.0023
0.0025
S02
0.0181
0.0000
0.0000
0.0322
0.0007
0.0945
0.0030
0.0043
0.0000
0.0000
0.0000
0.0004
0.0006
0.0002
0.0002
0.0019
0.0020
CO
0.0590
0.0162
0.0162
0.0885
0.0015
0.1983
0.0096
0.0140
0.0000
0.0000
0.1100
0.0144
0.0016
0.0005
0.0006
0.0063
0.0091
TSP
0.0195
0.0000
0.0000
0.0373
0.0008
0.1095
0.0032
0.0046
0.0000
0.0000
0.0000
0.0005
0.0005
0.0002
0.0002
0.0021
0.0022
Total
0.3909
0.0450
0.0450
0.7907
0.0194
2.5436
0.0637
0.0927
0.0000
0.0000
0.2870
0.0211
0.0101
0.0034
0.0041
0.0417
0.0456
IV)
o
Total Per Well
2.1542
0.9921
0.1367
0.4473
0.1575
3.8878
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 13 Page 6 of 7
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Disposal
10.20% CRN
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1975
0.0183
0.0183
0.4428
0.0053
1.0149
0.0222
0.0470
0.0000
0.0000
0.1040
0.0051
0.0066
0.0017
0.0021
0.0210
0.0222
THC
0.0158
0.0025
0.0025
0.1899
0.0029
0.5466
0.0018
0.0038
0.0000
0.0000
0.0231
0.0008
0.0008
0.0001
0.0002
0.0017
0.0019
S02
0.0131
0.0000
0.0000
0.0322
0.0004
0.0689
0.0015
0.0031
0.0000
0.0000
0.0000
0.0004
0.0006
0.0001
0.0001
0.0014
0.0015
CO
0.0427
0.0117
0.0117
0.0885
0.0008
0.1446
0.0048
0.0102
0.0000
0.0000
0.0790
0.0144
0.0016
0.0004
0.0004
0.0045
0.0075
TSP
0.0141
0.0000
0.0000
0.0373
0.0004
0.0798
0.0016
0.0034
0.0000
0.0000
0.0000
0.0005
0.0005
0.0001
0.0001
0.0015
0.0016
Total
0.2833
0.0326
0.0326
0.7907
0.0097
1.8548
0.0319
0.0674
0.0000
0.0000
0.2060
0.0211
0.0101
0.0025
0.0030
0.0301
0.0347
IV)
o
Total Per Well
1.6767
0.7724
0.1076
0.3471
0.1241
3.0279
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 13 Page 7 of 7
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Haul and Land Disposal
10.20% CRN
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.4375
0.0406
0.0406
0.8856
0.0159
2.2410
0.0667
0.1041
0.0000
0.0000
0.2302
0.0051
0.0066
0.0038
0.0046
0.0467
0.0464
THC
0.0350
0.0056
0.0056
0.3798
0.0086
1.2070
0.0053
0.0083
0.0000
0.0000
0.0511
0.0008
0.0008
0.0003
0.0004
0.0037
0.0038
S02
0.0291
0.0001
0.0001
0.0644
0.0011
0.1521
0.0044
0.0069
0.0000
0.0000
0.0000
0.0004
0.0006
0.0003
0.0003
0.0031
0.0031
CO
0.0947
0.0259
0.0259
0.1770
0.0023
0.3194
0.0144
0.0225
0.0000
0.0000
0.1749
0.0144
0.0016
0.0008
0.0010
0.0101
0.0127
TSP
0.0313
0.0000
0.0000
0.0746
0.0013
0.1762
0.0048
0.0074
0.0000
0.0000
0.0000
0.0005
0.0005
0.0003
0.0003
0.0033
0.0034
Total
0.6275
0.0723
0.0723
1.5814
0.0291
4.0958
0.0956
0.1493
0.0000
0.0000
0.4562
0.0211
0.0101
0.0055
0.0066
0.0670
0.0695
IV)
o
en
Total Per Well
3.6306
1.6696
0.2321
0.7492
0.2677
6.5492
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 14 Page 1 of 2
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Offshore/On-Site Cuttings Injection @ 10.20% CRN
On-site Injection Diesel Fuel Requirements (per model well)
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
IV)
o
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
748.8
748.8
748.8
36.7
1,569.6
1,569.6
1,569.6
76.8
1,137.6
1,137.6
1,137.6
55.5
2,520.0
2,520.0
2,520.0
123.4
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Hours of operation equals the drilling length in days (x 24 hr/day). The
transfer equipment utilizes one (1) 100 hp vacuum pump.
Hours of operation equals the drilling length in days (x 24 hr/day). Total
power utilized by the grinding and processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).Total power utilized by the grinding and
processing equipment is 600 hp.
TOTAL Diesel Per Well (Gal)
2,283.1
4,785.6
3,468.3
7,683.4
On-site Injection Energy Requirements (per model well)
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Pump Injection
8,424.0
12,480.0
14,976.0
3,667.0
17,658.0
26,160.0
31,392.0
7,684.5
12,798.0
18,960.0
22,752.0
5,549.2
28,350.0
42,000.0
50,400.0
12,338.1
Total Power Requirements
(per model well) for Four
Activities (hp):
39,547.0
82,894.5
60,059.2 133,088.1
These four energy-consuming activities were selected for inclusion in
this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 14 Page 2 of 2
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge via Offshore/On-Site Cuttings Injection
10.20% CRN
On-site Injection Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.6103
1.2792
0.9268
2.0538
THC
0.0488
0.1023
0.0741
0.1643
SO2
0.0406
0.0851
0.0616
0.1366
CO
0.1321
0.2769
0.2006
0.4445
TSP
0.0436
0.0914
0.0662
0.1467
Total
0.8754
1.8349
1.3294
2.9459
On-site Injection Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0861
0.1907
THC
0.0078
0.0164
0.0119
0.0264
SO2
0.0001
0.0002
0.0001
0.0003
CO
0.0362
0.0758
0.0549
0.1218
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.1531
0.3392
O
--J
Average On-site Injection Air Emissions (per model well) -Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%) for Electricity Generation
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0861
0.1907
THC
0.0078
0.0164
0.0119
0.0264
SO2
0.0001
0.0002
0.0001
0.0003
CO
0.0362
0.0758
0.0549
0.1218
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.1531
0.3392
-------
Worksheet No. 15 Page 1 of 3
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Summary Air Emissions (per model well) - Weighted by Land Disposal/On-site Injection Percentage Split
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.2994
0.5259
0.4042
3.6306
THC
0.1217
0.2116
0.1640
1.6696
SO2
0.0166
0.0275
0.0216
0.2321
CO
0.0817
0.1501
0.1134
0.7492
TSP
0.0191
0.0315
0.0248
0.2677
Total
0.5385
0.9466
0.7280
6.5492
Total Per Day
0.1036
0.0868
0.0922
0.3742
Note: Weighted summary air emissions totals assume the land disposal/on-site injection percentage splits are (20%/80%), (20%/80%), (20%/80%), and (100%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
Summary Fuel Usage (per model well) -Weighted by Land Disposal/On-site Injection Percentage Split
>
ro
o
oo
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
3,428.2
6,644.4
4,930.8
23,403.1
Barrels of Oil
Equivalent
(BOE)
81.6
158.2
117.4
557.2
Barrels of Oil Equivalent
(BOE) per day
15.7
14.5
14.9
31.8
Note: Weighted summary fuel usage totals assume the land disposal/on-site injection percentage splits are (20%/80%), (20%/80%), (20%/80%), and (100%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 15 Page 2 of 3
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Daily Drill Rig Emissions
Offshore California
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
o
CD
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
CAZD Daily Emissions/Fuel Usage
61,552.0
1,465.5
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Zero Discharge)
Total Air
Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
0.0
0.0
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air
Emissions
(tons)
180.9119
252.8128
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
11,538.1
16,123.7
0.0
0.0
OBF (Zero Discharge)
Total Air Emissions (tons)
30.5288
63.8108
0.0000
0.0000
Barrels of Oil Equivalent
(BOE)
1,986.8
4,151.8
0.0
0.0
TOTAL
0.0
0.0
433.7 27,661.8
528.1
33,800.3
Note: Summary annual air emission/fuel usage totals assume the following number of SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of OBF wells (existing sources) under this technology option:
1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note:!
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
94.3
6,138.6
-------
Worksheet No. 15 Page 3 of 3
BAT Non-Water Quality Environmental Impacts: Offshore California Zero Discharge
Region:
Technology:
Offshore California
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Annual Air Emissions (SBF BAT3 Model Well -Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
0.0000
0.0000
THC
0.0000
0.0000
0.0000
0.0000
SO2
0.0000
0.0000
0.0000
0.0000
CO
0.0000
0.0000
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
0.0000
Annual Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
16.7158
16.9423
0.0000
0.0000
THC
8.9378
18.6914
0.0000
0.0000
S02
1.1344
2.3705
0.0000
0.0000
CO
2.4347
5.0824
0.0000
0.0000
TSP
1.3061
2.7293
0.0000
0.0000
Total
30.5288
45.8159
0.0000
0.0000
Total
33.6581
27.6292
3.5050
7.5171
4.0353
Annual Air Emissions (WBF Baseline Model Well - Discharging 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
138.1160
0.0000
0.0000
THC
52.9238
73.9576
0.0000
0.0000
SO2
6.7288
9.4031
0.0000
0.0000
CO
14.1932
19.8341
0.0000
0.0000
TSP
7.7457
10.8241
0.0000
0.0000
Total
180.4268
252.1349
0.0000
0.0000
Total 236.9514 126.8813 16.1319 34.0273
Note: Summary annual air emission totals assume the following number of SBF wells (existing sources) under this technology option:
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of OBF wells (existing sources) under this technology option:
1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of WBF wells (existing sources) for baseline current practice
3 SWD wells, 2 SWE wells, 0 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
18.5698
-------
Worksheet No. 16 Page 1 of 7
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
Baseline Solids Control
Equipment
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
0.0 0.0
565.2 1,130.4
565.2 1,130.4
0.0 0.0
25.3 50.6
3,197.9 6,699.4
0.0 0.0
144.0 288.0
383.2 803.0
0.0 0.0
8,250.0 17,050.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
0.0 0.0
1,130.4 2,260.9
1,130.4 2,260.9
0.0 0.0
50.6 101.2
4,877.8 10,787.9
0.0 0.0
288.0 576.0
579.8 1,286.2
0.0 0.0
12,100.0 26,950.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
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.
Subtotal
13,314.4
27,591.1
20,164.2
44,482.1
-------
Worksheet No. 16 Page 2 of 7
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojijshio^^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
4.4 9.2
4.4 9.2
4.4 9.2
13.2 27.7
0.0 0.0
Deep Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
6.7 14.8
6.7 14.8
6.7 14.8
20.0 44.5
0.0 0.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (0%/0%) of offshore wastes sent on-shore
ro
IV)
TOTAL Diesel Per Well (Gal)
13,314.4
27,591.1
20,164.2 44,482.1
-------
Worksheet No. 16 Page 3 of 7
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
ro
w
Energy-Consuming Activity
Baseline Solids Control
Equipment
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
1,440.0 2,880.0
6,256.0 13,110.4
0.0 0.0
73.5 153.9
88.1 184.7
899.9 1,885.7
Deep Water
Development | Exploratory
12,798.0 28,350.0
2,880.0 5,760.0
9,465.6 20,998.4
0.0 0.0
111.2 247.2
133.4 296.6
1,361.7 3,027.7
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
Total Power Requirements
(per model well) for Seven
Selected Energy-Consuming
Activities (hp):
17,181.5 35,872.8
These seven energy-consuming activities were selected for inclusion
26,749.9 58,679.8 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 16 Page 4 of 7
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1300
0.0121
0.0121
0.1107
0.0053
0.6709
0.0222
0.0965
0.0000
0.0000
0.4085
0.0051
0.0066
0.0011
0.0014
0.0139
0.0000
THC
0.0104
0.0017
0.0017
0.0475
0.0029
0.3614
0.0018
0.0077
0.0000
0.0000
0.0906
0.0008
0.0008
0.0001
0.0001
0.0011
0.0000
SO2
0.0086
0.0000
0.0000
0.0080
0.0004
0.0455
0.0015
0.0064
0.0000
0.0000
0.0000
0.0004
0.0006
0.0001
0.0001
0.0009
0.0000
CO
0.0281
0.0077
0.0077
0.0221
0.0008
0.0956
0.0048
0.0209
0.0000
0.0000
0.3103
0.0144
0.0016
0.0002
0.0003
0.0030
0.0000
TSP
0.0093
0.0000
0.0000
0.0093
0.0004
0.0528
0.0016
0.0069
0.0000
0.0000
0.0000
0.0005
0.0005
0.0001
0.0001
0.0010
0.0000
Total
0.1865
0.0215
0.0215
0.1977
0.0097
1 .2262
0.0319
0.1385
0.0000
0.0000
0.8094
0.0211
0.0101
0.0016
0.0020
0.0199
0.0000
IV)
Total Per Well
1.3263
0.5135
0.0619
0.4622
0.0710
2.4348
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 16 Page 5 of 7
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.2725
0.0253
0.0253
0.2214
0.0106
1.4055
0.0444
0.2023
0.0000
0.0000
0.8442
0.0051
0.0066
0.0024
0.0029
0.0291
0.0000
THC
0.0218
0.0035
0.0035
0.0950
0.0057
0.7570
0.0036
0.0162
0.0000
0.0000
0.1872
0.0008
0.0008
0.0002
0.0002
0.0023
0.0000
SO2
0.0181
0.0000
0.0000
0.0161
0.0007
0.0954
0.0030
0.0135
0.0000
0.0000
0.0000
0.0004
0.0006
0.0002
0.0002
0.0019
0.0000
CO
0.0590
0.0162
0.0162
0.0443
0.0015
0.2003
0.0096
0.0438
0.0000
0.0000
0.6413
0.0144
0.0016
0.0005
0.0006
0.0063
0.0000
TSP
0.0195
0.0000
0.0000
0.0187
0.0008
0.1105
0.0032
0.0145
0.0000
0.0000
0.0000
0.0005
0.0005
0.0002
0.0002
0.0021
0.0000
Total
0.3909
0.0450
0.0450
0.3954
0.0194
2.5688
0.0637
0.2902
0.0000
0.0000
1 .6727
0.0211
0.0101
0.0034
0.0041
0.0417
0.0000
IV)
en
Total Per Well
2.7539
1.0681
0.1287
0.9569
0.1477
5.0552
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 16 Page 6 of 7
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1975
0.0183
0.0183
0.2214
0.0106
1 .0234
0.0444
0.1461
0.0000
0.0000
0.5991
0.0051
0.0066
0.0017
0.0021
0.0210
0.0000
THC
0.0158
0.0025
0.0025
0.0950
0.0057
0.5512
0.0036
0.0117
0.0000
0.0000
0.1328
0.0008
0.0008
0.0001
0.0002
0.0017
0.0000
SO2
0.0131
0.0000
0.0000
0.0161
0.0007
0.0695
0.0030
0.0097
0.0000
0.0000
0.0000
0.0004
0.0006
0.0001
0.0001
0.0014
0.0000
CO
0.0427
0.0117
0.0117
0.0443
0.0015
0.1458
0.0096
0.0316
0.0000
0.0000
0.4551
0.0144
0.0016
0.0004
0.0004
0.0045
0.0000
TSP
0.0141
0.0000
0.0000
0.0187
0.0008
0.0805
0.0032
0.0104
0.0000
0.0000
0.0000
0.0005
0.0005
0.0001
0.0001
0.0015
0.0000
Total
0.2833
0.0326
0.0326
0.3954
0.0194
1.8704
0.0637
0.2095
0.0000
0.0000
1.1871
0.0211
0.0101
0.0025
0.0030
0.0301
0.0000
IV)
o
Total Per Well
2.0634
0.8025
0.0990
0.6996
0.1136
3.7781
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 16 Page 7 of 7
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.4375
0.0406
0.0406
0.4428
0.0212
2.2633
0.0889
0.3240
0.0000
0.0000
1 .3344
0.0051
0.0066
0.0038
0.0046
0.0467
0.0000
THC
0.0350
0.0056
0.0056
0.1899
0.0114
1.2190
0.0071
0.0259
0.0000
0.0000
0.2959
0.0008
0.0008
0.0003
0.0004
0.0037
0.0000
SO2
0.0291
0.0001
0.0001
0.0322
0.0014
0.1536
0.0059
0.0215
0.0000
0.0000
0.0000
0.0004
0.0006
0.0003
0.0003
0.0031
0.0000
CO
0.0947
0.0259
0.0259
0.0885
0.0030
0.3226
0.0192
0.0701
0.0000
0.0000
1.0136
0.0144
0.0016
0.0008
0.0010
0.0101
0.0000
TSP
0.0313
0.0000
0.0000
0.0373
0.0017
0.1780
0.0063
0.0231
0.0000
0.0000
0.0000
0.0005
0.0005
0.0003
0.0003
0.0033
0.0000
Total
0.6275
0.0723
0.0723
0.7907
0.0388
4.1365
0.1275
0.4648
0.0000
0.0000
2.6439
0.0211
0.0101
0.0055
0.0066
0.0670
0.0000
IV)
Total Per Well
4.5153
1.7549
0.2148
1.5430
0.2465
8.2745
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 17 Page 1 of 2
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Offshore/On-Site Cuttings Injection @ 10.20% CRN
On-site Injection Diesel Fuel Requirements (per model well)
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
748.8
748.8
748.8
36.7
1,569.6
1,569.6
1,569.6
76.8
1,137.6
1,137.6
1,137.6
55.5
2,520.0
2,520.0
2,520.0
123.4
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Hours of operation equals the drilling length in days (x 24 hr/day). The
transfer equipment utilizes one (1) 100 hp vacuum pump.
Hours of operation equals the drilling length in days (x 24 hr/day). Total
power utilized by the grinding and processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).Total power utilized by the grinding and
processing equipment is 600 hp.
oo TOTAL Diesel Per Well (Gal)
2,283.1
4,785.6
3,468.3
7,683.4
On-site Injection Energy Requirements (per model well)
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Pump Injection
8,424.0
12,480.0
14,976.0
3,667.0
17,658.0
26,160.0
31,392.0
7,684.5
12,798.0
18,960.0
22,752.0
5,549.2
28,350.0
42,000.0
50,400.0
12,338.1
Total Power Requirements
(per model well) for Four
Activities (hp):
39,547.0
82,894.5
60,059.2 133,088.1
These four energy-consuming activities were selected for inclusion in
this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 17 Page 2 of 2
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge via Offshore/On-Site Cuttings Injection @ 10.20% CRN
On-site Injection Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.6103
1.2792
0.9268
2.0538
THC
0.0488
0.1023
0.0741
0.1643
SO2
0.0406
0.0851
0.0616
0.1366
CO
0.1321
0.2769
0.2006
0.4445
TSP
0.0436
0.0914
0.0662
0.1467
Total
0.8754
1.8349
1.3294
2.9459
On-site Injection Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0861
0.1907
THC
0.0078
0.0164
0.0119
0.0264
SO2
0.0001
0.0002
0.0001
0.0003
CO
0.0362
0.0758
0.0549
0.1218
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.1531
0.3392
ro
CD
Average On-site Injection Air Emissions (per model well) -Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%) for Electricity Generation
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0861
0.1907
THC
0.0078
0.0164
0.0119
0.0264
SO2
0.0001
0.0002
0.0001
0.0003
CO
0.0362
0.0758
0.0549
0.1218
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.1531
0.3392
-------
Worksheet No. 18 Page 1 of 3
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Summary Air Emissions (per model well) - Weighted by Land Disposal/On-site Injection Percentage Split
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0000
0.0000
THC
0.0078
0.0164
0.0000
0.0000
SO2
0.0001
0.0002
0.0000
0.0000
CO
0.0362
0.0758
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.0000
0.0000
Total Per Day
0.0194
0.0194
0.0000
0.0000
Note: Weighted summary air emissions totals assume the land disposal/on-site injection percentage splits are (0%/100%), (0%/100%), (0%/0%), and (0%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
Summary Fuel Usage (per model well) -Weighted by Land Disposal/On-site Injection Percentage Split
>
ro
M
o
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
2,283.1
4,785.6
0.0
0.0
Barrels of Oil
Equivalent
(BOE)
54.4
113.9
0.0
0.0
Barrels of Oil Equivalent
(BOE) per day
10.5
10.5
0.0
0.0
Note: Weighted summary fuel usage totals assume the land disposal/on-site injection percentage splits are (0%/100%), (0%/100%), (0%/0%), and (0%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 18 Page 2 of 3
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Daily Drill Rig Emissions
Cook Inlet, AK
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
AKZD Daily Emissions/Fuel Usage
61,552.0
1,465.5
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Zero Discharge)
Total Air
Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
0.0
0.0
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air
Emissions
(tons)
180.9119
126.4064
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
11,538.1
8,061.8
0.0
0.0
OBF (Zero Discharge)
Total Air Emissions (tons)
30.0911
63.0755
0.0000
0.0000
Barrels of Oil Equivalent
(BOE)
1,959.5
4,107.5
0.0
0.0
TOTAL
0.0
0.0
307.3 19,599.9
400.5
25,666.9
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
under this technology option: 1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of WBF wells (existing sources) under the zero discharge opttion:
under this technology option: 3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
93.2
6,067.0
-------
Worksheet No. 18 Page 3 of 3
BAT Non-Water Quality Environmental Impacts: Cook Inlet, AK, Zero Discharge
Region:
Technology:
Cook Inlet, AK
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Annual Air Emissions (SBF BAT3 Model Well -Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
0.0000
0.0000
THC
0.0000
0.0000
0.0000
0.0000
SO2
0.0000
0.0000
0.0000
0.0000
CO
0.0000
0.0000
0.0000
0.0000
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
Total
0.0000
0.0000
0.0000
0.0000
0.0000
Annual Air Emissions (OBF BAT3 Model Well -Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
16.4731
16.5352
0.0000
0.0000
THC
8.8239
8.8325
0.0000
0.0000
SO2
1.1179
1.1180
0.0000
0.0000
CO
2.3892
2.4288
0.0000
0.0000
TSP
1.2870
1.2870
0.0000
0.0000
Total
30.0911
30.2015
0.0000
0.0000
Total
33.0083
17.6565
2.2359
4.8180
2.5740
Annual Air Emissions (WBF BATS Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
98.8353
69.0580
0.0000
0.0000
THC
52.9238
36.9788
0.0000
0.0000
SO2
6.7288
4.7015
0.0000
0.0000
CO
14.1932
9.9171
0.0000
0.0000
TSP
7.7457
5.4120
0.0000
0.0000
Total
180.4268
126.0674
0.0000
0.0000
Total 167.8934 89.9025 11.4303 24.1103
Note: Summary annual air emission totals assume the following number of SBF wells (existing sources) under the zero discharge option:
0 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of OBF wells (existing sources) under the zero discharge option:
under this technology option: 1 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of WBF wells (existing sources) under the zero discharge option:
under this technology option: 3 SWD wells, 1 SWE wells, 0 DWD wells, and 0 OWE wells
13.1577
-------
Worksheet No. 20 Page 1 of 4
NSPS Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
Fuel-Consuming Activity
Baseline Solids Control
Equipment
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
Deep Water
Development | Exploratory
1,137.6 2,520.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment fuel usage is 6 gal-diesel/hr
TOTAL Per Model Well
748.8
1,569.6
1,137.6
2,520.0
IV)
ro
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
8,424.0
17,658.0
12,798.0
28,350.0
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
TOTAL Per Model Well
8,424.0
17,658.0
12,798.0
28,350.0
-------
Worksheet No. 20 Page 2 of 4
NSPS Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
Baseline Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.1300
0.2725
0.1975
0.4375
THC
0.0104
0.0218
0.0158
0.0350
SO2
0.0086
0.0181
0.0131
0.0291
CO
0.0281
0.0590
0.0427
0.0947
TSP
0.0093
0.0195
0.0141
0.0313
Total
0.1865
0.3909
0.2833
0.6275
Baseline Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0121
0.0253
0.0183
0.0406
THC
0.0017
0.0035
0.0025
0.0056
SO2
0.0000
0.0000
0.0000
0.0001
CO
0.0077
0.0162
0.0117
0.0259
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0215
0.0450
0.0326
0.0723
Average Baseline Solids Control Air Emissions (per model well) - Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.1123
0.2354
0.1706
0.3780
THC
0.0091
0.0191
0.0138
0.0306
SO2
0.0074
0.0154
0.0112
0.0247
CO
0.0251
0.0526
0.0381
0.0844
TSP
0.0079
0.0165
0.0120
0.0266
Total
0.1617
0.3390
0.2457
0.5442
Total Per Day
0.0311
0.0311
0.0311
0.0311
Total per day
0.0864
0.0070
0.0057
0.0193
0.0061
Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
1 .3055
2.3187
1 .9402
4.3481
THC
0.5276
0.9267
0.8441
1 .8858
SO2
0.0904
0.1591
0.1340
0.3004
CO
0.2386
0.4150
0.3395
0.7592
TSP
0.1033
0.1813
0.1537
0.3444
Total
2.2654
4.0009
3.4116
7.6379
Total Per Day
0.4357
0.3671
0.4318
0.4365
Total per day
Daily Drill Rig Emissions
0.9579
0.4011
0.0661
0.1703
0.0756
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1 .6954
1 .6954
1 .6954
1 .6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Total per day
12.6280
6.7816
0.8598
1.8100
0.9900
-------
Worksheet No. 20 Page 3 of 4
NSPS Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Daily Drill Rig Fuel Usage
Offshore Gulf of Mexico (COM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
GOM Baseline Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @ 10.20%)
Total Air
Emissions
(tons)
150.7599
0.0000
452.2798
0.0000
Barrels of Oil
Equivalent
(BOE)
9,615.0
0.0
43,822.4
0.0
DBF (Zero Discharge)
Total Air
Emissions
(tons)
64.5114
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
4,122.3
0.0
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air Emissions
(tons)
1 ,628.2074
0.0000
1 ,007.7722
0.0000
Barrels of Oil Equivalent
(BOE)
103,842.5
0.0
64,272.9
0.0
WBF (Zero Discharge)
Total Air
Emissions
(tons)
0.0000
0.0000
0.0000
0.0000
Barrels of Oil Equivalent (BOE)
0.0
0.0
0.0
0.0
TOTAL
64.5
4,122.3
603.0 53,437.5
3,239.0
221,552.9
Note: Summary annual fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
5 SWD wells, 0 SWE wells, 15 DWD wells, and 0 OWE wells
Note: Summary annual fuel usage totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 2 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual fuel usage totals assume the following number of GOM WBF wells (existing sources) under this technology option:
27 SWD wells, 0 SWE wells, 11 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
2,636.0
168,115.4
0.0
0.0
-------
Worksheet No. 20 Page 4 of 4
NSPS Non-Water Quality Environmental Impacts: Baseline Current Practice
Region:
Technology:
Offshore Gulf of Mexico (GOM)
SBF Discharges from Baseline Solids Control System (e.g., Shale Shakers & Fines Removal Unit) at 10.20% CRN
Annual Air Emissions (SBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
82.6436
0.0000
376.6639
0.0000
THC
44.1259
0.0000
201.1121
0.0000
SO2
5.6257
0.0000
25.6403
0.0000
CO
11.8904
0.0000
54.1926
0.0000
TSP
6.4745
0.0000
29.5086
0.0000
Total
150.7599
0.0000
687.1174
0.0000
Total
459.3074
245.2379
31.2660
66.0829
35.9831
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
35.4439
0.0000
0.0000
0.0000
THC
18.6873
0.0000
0.0000
0.0000
SO2
2.4164
0.0000
0.0000
0.0000
CO
5.1833
0.0000
0.0000
0.0000
TSP
2.7805
0.0000
0.0000
0.0000
Total
64.5114
0.0000
0.0000
0.0000
Total
35.4439
18.6873
2.4164
5.1833
2.7805
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
446.2752
0.0000
276.2202
0.0000
THC
238.2796
0.0000
147.4822
0.0000
SO2
30.3789
0.0000
18.8029
0.0000
CO
64.2079
0.0000
39.7412
0.0000
TSP
34.9621
0.0000
21.6397
0.0000
Total
814.1037
0.0000
503.8861
0.0000
Total 722.4954 385.7618 49.1817 103.9492 56.6018
Note: Summary annual air emission totals assume the following number of GOM SBF wells (existing sources) under this technology option:
5 SWD wells, 0 SWE wells, 15 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 2 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emissions totals assume the following number of GOM WBF wells (existing sources) under this technology option:
27 SWD wells, 0 SWE wells, 11 DWD wells, and 0 OWE wells
-------
IV)
ro
Worksheet No. 21 Page 1 of 4
NSPS Non-Water Quality Environmental Impacts: NSPS Option 1
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharges from NSPS Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
748.8
748.8
1,569.6
1,569.6
1,137.6
1,137.6
2,520.0
2,520.0
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
TOTAL Per Model Well
1,497.6
3,139.2
2,275.2
5,040.0
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
8,424.0 17,658.0
14,098.7 29,553.0
12,798.0
21,419.1
28,350.0
47,447.4
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
TOTAL Per Model Well
22,522.7 47,211.0
34,217.1
75,797.4
-------
Worksheet No. 21 Page 2 of 4
NSPS Non-Water Quality Environmental Impacts: NSPS Option 1
Region:
Technology:
Offshore Gulf of Mexico (GOM)
SBF Discharges from NSPS Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
NSPS Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.3476
0.7286
0.5280
1.1697
THC
0.0278
0.0583
0.0422
0.0936
S02
0.0231
0.0484
0.0351
0.0778
CO
0.0752
0.1577
0.1143
0.2532
TSP
0.0248
0.0520
0.0377
0.0836
Total
0.4985
1.0450
0.7574
1.6778
NSPS Option 1 Solids Control Air Emissions (per model well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0323
0.0677
0.0490
0.1086
THC
0.0045
0.0094
0.0068
0.0150
SO2
0.0000
0.0001
0.0001
0.0002
CO
0.0206
0.0432
0.0313
0.0693
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.0574
0.1203
0.0872
0.1932
M
M
00
NSPS Option 1 Solids Control Air Emissions (per model well) -Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.3003
0.6294
0.4562
1.0105
THC
0.0243
0.0509
0.0369
0.0818
S02
0.0197
0.0412
0.0299
0.0661
CO
0.0670
0.1405
0.1018
0.2256
TSP
0.0211
0.0442
0.0321
0.0710
Total
0.4324
0.9063
0.6569
1.4551
Total Per Day
0.0831
0.0831
0.0831
0.0831
-------
Worksheet No. 21 Page 3 of 4
NSPS Non-Water Quality Environmental Impacts: NSPS Option 1
Region:
Technology:
Daily Drill Rig Emissions
Offshore Gulf of Mexico (GOM)
SBF Discharges from NSPS Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1 .6954
1 .6954
1 .6954
1 .6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
NSPS Option 1 Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @ 4.03%)
Total Air
Emissions
(tons)
243.381 1
0.0000
739.5042
0.0000
Barrels of Oil
Equivalent
(BOE)
15,526.7
0.0
47,177.3
0.0
OBF (Zero Discharge)
Total Air
Emissions
(tons)
32.2557
0.0000
0.0000
0.0000
Barrels of Oil
Equivalent
(BOE)
2,061.1
0.0
0.0
0.0
WBF (Discharge @ 10.20%)
Total Air Emissions (tons)
1 ,507.5994
0.0000
916.1566
0.0000
Barrels of Oil Equivalent
(BOE)
96,150.5
0.0
58,429.9
0.0
TOTAL
32.3
2,061.1
982.9 62,704.0
3,438.9
219,345.5
Note: Summary annual air emission/fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
8 SWD wells, 0 SWE wells, 16 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM WBF wells (existing sources) under this technology option:
25 SWD wells, 0 SWE wells, 10 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
2,423.8
154,580.4
-------
Worksheet No. 21 Page 4 of 4
NSPS Non-Water Quality Environmental Impacts: NSPS Option 1
Region:
Technology:
Offshore Gulf of Mexico (GOM)
SBF Discharges from NSPS Solids Control System (e.g., Cuttings Dryer & Fines Removal Unit) at 4.03% CRN
Annual Air Emissions (SBF NSPS Option 1 Model Well - Discharging at 4.03% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
133.7334
0.0000
203.1719
0.0000
THC
70.7231
0.0000
107.4447
0.0000
SO2
9.0996
0.0000
13.8243
0.0000
CO
19.3603
0.0000
29.4127
0.0000
TSP
10.4648
0.0000
15.8985
0.0000
Total
243.381 1
0.0000
369.7521
0.0000
Total 336.9053 178.1678 22.9239
Annual Air Emissions (OBF Baseline Model Well -Zero Discharging at 10.20% CRN)
48.7729
26.3633
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
17.7219
0.0000
0.0000
0.0000
THC
9.3437
0.0000
0.0000
0.0000
SO2
1 .2082
0.0000
0.0000
0.0000
CO
2.5916
0.0000
0.0000
0.0000
TSP
1 .3903
0.0000
0.0000
0.0000
Total
32.2557
0.0000
0.0000
0.0000
Total
17.7219
9.3437
1.2082
2.5916
1.3903
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
823.6278
0.0000
500.5123
0.0000
THC
441.0313
0.0000
268.0113
0.0000
SO2
56.0734
0.0000
34.0754
0.0000
CO
118.2768
0.0000
71 .8759
0.0000
TSP
64.5473
0.0000
39.2249
0.0000
Total
1 ,503.5565
0.0000
913.6997
0.0000
Total 1,324.1400 709.0426 90.1487 190.1527
Note: Summary annual air emission totals assume the following number of GOM SBF wells (existing sources) under this technology option:
8 SWD wells, 0 SWE wells, 16 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of GOM WBF wells (existing sources) under this technology option:
25 SWD wells, 0 SWE wells, 10 DWD wells, and 0 OWE wells
103.7722
-------
Worksheet No. 22 Page 1 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Fuel-Consuming Activity
Cuttings Dryer Discharge
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
748.8 1,569.6
870.4 870.4
0.0 0.0
870.4 870.4
1.7 3.3
25.3 25.3
0.0 0.0
45.5 50.6
144.0 144.0
3.3 6.7
1.7 3.3
5.0 5.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
1,137.6 2,520.0
870.4 870.4
0.0 0.0
870.4 870.4
3.3 6.7
25.3 25.3
0.0 0.0
50.6 60.7
144.0 144.0
6.7 13.3
3.3 6.7
5.0 5.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment fuel usage is 6 gal-diesel/hr
Cuttings dryer equipment fuel usage is 6 gal-diesel/hr
EPA assumes that the volume of fines waste can be managed via
regular supply boats
EPA assumes that the volume of fines waste can be managed via
regular supply boats
>
IV)
Subtotal
2,594.5
4,247.9
3,383.9
6,172.1
-------
Worksheet No. 22 Page 2 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Fuel-Consuming Activity
Zero Discharge of Fines (cont.)
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojnjjshjjr^^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.1 0.2
0.1 0.2
0.1 0.2
0.3 0.7
9.4 9.7
Deep Water
Development | Exploratory
1.7 1.7
44.0 44.0
45.7 45.7
0.2 0.4
0.2 0.4
0.2 0.4
0.5 1.2
9.5 10.1
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (20%/80%) of offshore wastes sent on-shore
>
iv)
IV)
TOTAL Diesel Per Well (Gal)
2,603.9
4,257.6
3,393.4 6,182.2
-------
Worksheet No. 22 Page 3 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Energy-Consuming Activity
Baseline Solids Control
Equipment
Improved Solids Control
Equipment (e.g., Cuttings Dryer)
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
14,098.7 29,553.0
1,440.0 1,440.0
54.4 108.8
27.2 54.4
1.9 4.0
2.3 2.3
23.4 23.4
Deep Water
Development | Exploratory
12,798.0 28,350.0
21,419.1 47,447.4
1,440.0 1,440.0
108.8 217.6
54.4 108.8
2.9 6.4
2.3 2.3
23.4 23.4
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Average of MUD-10 (38.22 hp) and vertical centrifuge (187.72 hp)
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
>
IV)
Total Power Requirements (per
well) for Seven Selected
Energy-Consuming Activities
(hp):
These seven energy-consuming activities were selected for inclusion
24,071.8 48,843.8 35,848.8 77,595.9 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 22 Page 4 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.3476
0.0323
0.3003
0.1705
0.0053
0.0096
0.0222
0.0008
0.0003
0.0004
0.0002
0.0006
0.0008
0.0000
0.0000
0.0004
0.0006
THC
0.0278
0.0045
0.0243
0.0731
0.0029
0.0051
0.0018
0.0001
0.0001
0.0000
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0231
0.0000
0.0197
0.0124
0.0004
0.0006
0.0015
0.0001
0.0000
0.0000
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0000
CO
0.0752
0.0206
0.0670
0.0341
0.0008
0.0014
0.0048
0.0002
0.0001
0.0001
0.0002
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0248
0.0000
0.0211
0.0144
0.0004
0.0008
0.0016
0.0001
0.0000
0.0000
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0000
Total
0.4985
0.0574
0.4324
0.3044
0.0097
0.0175
0.0319
0.0012
0.0006
0.0006
0.0005
0.0026
0.0013
0.0000
0.0001
0.0005
0.0013
>
IV)
Total Per Well
0.5103
0.1076
0.0347
0.1090
0.0384
0.8000
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 22 Page 5 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.7286
0.0677
0.6294
0.1705
0.0053
0.0106
0.0222
0.0017
0.0007
0.0008
0.0002
0.0006
0.0008
0.0001
0.0000
0.0004
0.0007
THC
0.0583
0.0094
0.0509
0.0731
0.0029
0.0057
0.0018
0.0001
0.0003
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0484
0.0001
0.0412
0.0124
0.0004
0.0007
0.0015
0.0001
0.0000
0.0001
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0000
CO
0.1577
0.0432
0.1405
0.0341
0.0008
0.0015
0.0048
0.0004
0.0001
0.0002
0.0002
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0520
0.0000
0.0442
0.0144
0.0004
0.0008
0.0016
0.0001
0.0001
0.0001
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
Total
1.0450
0.1203
0.9063
0.3044
0.0097
0.0194
0.0319
0.0024
0.0012
0.0012
0.0005
0.0026
0.0013
0.0001
0.0001
0.0005
0.0013
>
ro
Total Per Well
0.8421
0.1350
0.0564
0.1830
0.0617
1.2783
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 22 Page 6 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.5280
0.0490
0.4562
0.1705
0.0053
0.0106
0.0222
0.0017
0.0007
0.0008
0.0002
0.0006
0.0008
0.0000
0.0000
0.0004
0.0006
THC
0.0422
0.0068
0.0369
0.0731
0.0029
0.0057
0.0018
0.0001
0.0003
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0351
0.0001
0.0299
0.0124
0.0004
0.0007
0.0015
0.0001
0.0000
0.0001
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0000
CO
0.1143
0.0313
0.1018
0.0341
0.0008
0.0015
0.0048
0.0004
0.0001
0.0002
0.0002
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0377
0.0000
0.0321
0.0144
0.0004
0.0008
0.0016
0.0001
0.0001
0.0001
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
Total
0.7574
0.0872
0.6569
0.3044
0.0097
0.0194
0.0319
0.0024
0.0012
0.0012
0.0005
0.0026
0.0013
0.0001
0.0001
0.0005
0.0013
>
IV)
Total Per Well
0.6689
0.1210
0.0451
0.1443
0.0495
1.0288
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 22 Page 7 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline and Cuttings Dryer
Solids Control Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
1.1697
0.1086
1.0105
0.1705
0.0053
0.0127
0.0222
0.0034
0.0013
0.0017
0.0002
0.0006
0.0008
0.0001
0.0000
0.0004
0.0007
THC
0.0936
0.0150
0.0818
0.0731
0.0029
0.0069
0.0018
0.0003
0.0006
0.0001
0.0001
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
SO2
0.0778
0.0002
0.0661
0.0124
0.0004
0.0009
0.0015
0.0002
0.0001
0.0001
0.0000
0.0000
0.0001
0.0000
0.0000
0.0000
0.0001
CO
0.2532
0.0693
0.2256
0.0341
0.0008
0.0018
0.0048
0.0007
0.0003
0.0004
0.0002
0.0018
0.0002
0.0000
0.0000
0.0001
0.0005
TSP
0.0836
0.0000
0.0710
0.0144
0.0004
0.0010
0.0016
0.0002
0.0001
0.0001
0.0000
0.0001
0.0001
0.0000
0.0000
0.0000
0.0001
Total
1.6778
0.1932
1.4551
0.3044
0.0097
0.0233
0.0319
0.0048
0.0023
0.0024
0.0005
0.0026
0.0013
0.0001
0.0001
0.0005
0.0013
>
ro
Total Per Well
1.2286
0.1675
0.0817
0.2691
0.0889
1.8358
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 22 Page 8 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (COM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Summary Air Emissions (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.5103
0.8421
0.6689
1.2286
THC
0.1076
0.1350
0.1210
0.1675
SO2
0.0347
0.0564
0.0451
0.0817
CO
0.1090
0.1830
0.1443
0.2691
TSP
0.0384
0.0617
0.0495
0.0889
Total
0.8000
1.2783
1.0288
1.8358
Total Per Day
0.1538
0.1173
0.1302
0.1049
Summary Fuel Usage (per model well)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
2,603.9
4,257.6
3,393.4
6,182.2
Barrels of Oil
Equivalent
(BOE)
62.0
101.4
80.8
147.2
CO
00
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 22 Page 9 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Daily Drill Rig Emissions
Offshore Gulf of Mexico (GOM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
CO
CD
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
NSPS Option 2 Annual Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF (Discharge @ 3.82%)
Total Air
Emissions
(tons)
246.3220
0.0000
745.4555
0.0000
Barrels of Oil
Equivalent
(BOE)
15,737.4
0.0
47,603.3
0.0
TOTAL 991.8 63,340.7
OBF (Zero Discharge)
Total Air
Emissions
(tons)
32.2557
0.0000
0.0000
0.0000
32.3
Barrels of Oil
Equivalent
(BOE)
2,061.1
0.0
0.0
0.0
2,061.1
WBF (Discharge @ 10.20%)
Total Air Emissions (tons)
1,507.5994
0.0000
916.1566
0.0000
2,423.8
Barrels of Oil Equivalent
(BOE)
96,150.5
0.0
58,429.9
0.0
154,580.4
3,447.8
219,982.2
Note: Summary annual air emission/fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
8 SWD wells, 0 SWE wells, 16 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM WBF wells (existing sources) under this technology option:
25 SWD wells, 0 SWE wells, 10 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
-------
Worksheet No. 22 Page 10 of 10
NSPS Non-Water Quality Environmental Impacts: NSPS Option 2
Region:
Technology:
Offshore Gulf of Mexico (GOM)
SBF Discharge from NSPS Solids Control System (e.g., Cuttings Dryer only at 3.82% CRN) & ZD of fines
Annual Air Emissions (SBF NSPS Option 2 Model Well - Discharging at 3.82% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
135.4136
0.0000
409.7468
0.0000
THC
71.3892
0.0000
216.2345
0.0000
SO2
9.2199
0.0000
27.8921
0.0000
CO
19.6963
0.0000
59.5053
0.0000
TSP
10.6031
0.0000
32.0767
0.0000
Total
246.3220
0.0000
745.4555
0.0000
Total
545.1604
287.6237
37.1120
79.2016
42.6799
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20%CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
17.7219
0.0000
0.0000
0.0000
THC
9.3437
0.0000
0.0000
0.0000
SO2
1.2082
0.0000
0.0000
0.0000
CO
2.5916
0.0000
0.0000
0.0000
TSP
1.3903
0.0000
0.0000
0.0000
Total
32.2557
0.0000
0.0000
0.0000
Total
17.7219
9.3437
1.2082
2.5916
1.3903
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
823.6278
0.0000
500.5123
0.0000
THC
441.0313
0.0000
268.0113
0.0000
SO2
56.0734
0.0000
34.0754
0.0000
CO
118.2768
0.0000
71.8759
0.0000
TSP
64.5473
0.0000
39.2249
0.0000
Total
1,503.5565
0.0000
913.6997
0.0000
Total 1,324.1400 709.0426 90.1487 190.1527
Note: Summary annual air emission totals assume the following number of GOM SBF wells (existing sources) under this technology option:
8 SWD wells, 0 SWE wells, 16 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of GOM WBF wells (existing sources) under this technology option:
25 SWD wells, 0 SWE wells, 10 DWD wells, and 0 OWE wells
103.7722
-------
Worksheet No. 23 Page 1 of 7
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
Baseline Solids Control
Equipment
Regular Supply Boat Transit
Dedicated Supply Boat Transit
Total Supply Boat Transit
Barge Transit
Supply Boat Maneuvering
Dedicated Supply Boat Loading
Regular Supply Boat Loading
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
Trucks
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
748.8 1,569.6
0.0 870.4
3,131.3 3,131.3
3,131.3 4,001.7
61.7 128.3
25.3 50.6
3,197.9 6,532.5
0.0 101.2
144.0 288.0
123.3 256.6
61.6 128.3
40.0 85.0
Deep Water
Development | Exploratory
1,137.6 2,520.0
0.0 870.4
3,131.3 6,262.6
3,131.3 7,133.0
93.3 206.7
25.3 75.9
4,837.4 10,580.5
0.0 101.2
144.0 432.0
186.6 413.2
93.3 206.6
60.0 130.0
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
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.
>
ro
Subtotal
7,533.9
13,141.8
9,708.8
21,799.0
-------
Worksheet No. 23 Page 2 of 7
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Fuel-Consuming Activity
On-shore Disposal
(Landfarming)
Wheel Tractor for Grading at
Landfarm
Dozer/Loader for Spreading
Waste at Landfarm
On-shore Landfarming
Subtotal:
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Processing
Cuttings Injection
Ojijshio^^
On-shore Disposal Subtotal:
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
4.4 9.2
4.4 9.2
4.4 9.2
13.2 27.7
83.6 95.2
Deep Water
Development | Exploratory
13.4 13.4
352.0 352.0
365.4 365.4
6.7 14.8
6.7 14.8
6.7 14.8
20.0 44.5
89.1 108.7
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). The transfer equipment utilizes one (1)
1 00 hp vacuum pump.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr). Total power utilized by the grinding and
processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).
Weighted average using landfarming/on-shore injection percentage
split (20%/80%) of offshore wastes sent on-shore
>
iv)
IV)
TOTAL Diesel Per Well (Gal)
7,617.6 13,237.0
9,797.9 21,907.7
-------
Worksheet No. 23 Page 3 of 7
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
ro
-C*.
w
Energy-Consuming Activity
Baseline Solids Control
Equipment
Supply Boat Auxiliary Generator
(in Port Demurrage)
Supply Boat Cranes
Barge Cranes
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
8,424.0 17,658.0
1,440.0 2,880.0
2,012.8 4,188.8
1,006.4 2,094.4
73.5 153.9
88.1 184.7
899.9 1,885.7
Deep Water
Development | Exploratory
12,798.0 28,350.0
1,440.0 4,320.0
3,046.4 6,745.6
1,523.2 3,372.8
111.2 247.2
133.4 296.6
1,361.7 3,027.7
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
EPA assumes that all onshore cuttings injection facility equipment use
diesel(Fall 1999 Field Trip)
Total Power Requirements
(per well) for Seven Selected
Energy-Consuming Activities
(hp):
These seven energy-consuming activities were selected for inclusion
13,944.7 29,045.6 20,413.9 46,359.8 in this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 23 Page 4 of 7
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Shallow Water Development (SWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1300
0.0121
0.1123
0.6133
0.0053
0.6709
0.0222
0.0311
0.0121
0.0155
0.0020
0.0051
0.0066
0.0011
0.0014
0.0139
0.0154
THC
0.0104
0.0017
0.0091
0.2630
0.0029
0.3614
0.0018
0.0025
0.0052
0.0012
0.0004
0.0008
0.0008
0.0001
0.0001
0.0011
0.0014
S02
0.0086
0.0000
0.0074
0.0446
0.0004
0.0455
0.0015
0.0021
0.0009
0.0010
0.0000
0.0004
0.0006
0.0001
0.0001
0.0009
0.0011
CO
0.0281
0.0077
0.0251
0.1226
0.0008
0.0956
0.0048
0.0067
0.0024
0.0034
0.0015
0.0144
0.0016
0.0002
0.0003
0.0030
0.0060
TSP
0.0093
0.0000
0.0079
0.0517
0.0004
0.0528
0.0016
0.0022
0.0010
0.0011
0.0000
0.0005
0.0005
0.0001
0.0001
0.0010
0.0011
Total
0.1865
0.0215
0.1617
1.0951
0.0097
1 .2262
0.0319
0.0446
0.0216
0.0223
0.0039
0.0211
0.0101
0.0016
0.0020
0.0199
0.0250
>
IV)
Total Per Well
1.5001
0.6488
0.1044
0.2689
0.1198
2.6420
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 23 Page 5 of 7
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Shallow Water Exploratory (SWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.2725
0.0253
0.2354
0.7837
0.0106
1.3917
0.0444
0.0646
0.0251
0.0323
0.0042
0.0051
0.0066
0.0024
0.0029
0.0291
0.0298
THC
0.0218
0.0035
0.0191
0.3361
0.0057
0.7496
0.0036
0.0052
0.0108
0.0026
0.0009
0.0008
0.0008
0.0002
0.0002
0.0023
0.0025
S02
0.0181
0.0000
0.0154
0.0570
0.0007
0.0945
0.0030
0.0043
0.0018
0.0021
0.0000
0.0004
0.0006
0.0002
0.0002
0.0019
0.0020
CO
0.0590
0.0162
0.0526
0.1567
0.0015
0.1983
0.0096
0.0140
0.0050
0.0070
0.0032
0.0144
0.0016
0.0005
0.0006
0.0063
0.0091
TSP
0.0195
0.0000
0.0165
0.0660
0.0008
0.1095
0.0032
0.0046
0.0021
0.0023
0.0000
0.0005
0.0005
0.0002
0.0002
0.0021
0.0022
Total
0.3909
0.0450
0.3390
1.3996
0.0194
2.5436
0.0637
0.0927
0.0449
0.0464
0.0083
0.0211
0.0101
0.0034
0.0041
0.0417
0.0456
>
IV)
en
Total Per Well
2.6221
1.1361
0.1808
0.4570
0.2072
4.6032
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 23 Page 6 of 7
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Deep Water Development (DWD) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.1975
0.0183
0.1706
0.6133
0.0053
1.0149
0.0222
0.0470
0.0183
0.0235
0.0030
0.0051
0.0066
0.0017
0.0021
0.0210
0.0222
THC
0.0158
0.0025
0.0138
0.2630
0.0029
0.5466
0.0018
0.0038
0.0078
0.0019
0.0007
0.0008
0.0008
0.0001
0.0002
0.0017
0.0019
S02
0.0131
0.0000
0.0112
0.0446
0.0004
0.0689
0.0015
0.0031
0.0013
0.0016
0.0000
0.0004
0.0006
0.0001
0.0001
0.0014
0.0015
CO
0.0427
0.0117
0.0381
0.1226
0.0008
0.1446
0.0048
0.0102
0.0037
0.0051
0.0023
0.0144
0.0016
0.0004
0.0004
0.0045
0.0075
TSP
0.0141
0.0000
0.0120
0.0517
0.0004
0.0798
0.0016
0.0034
0.0015
0.0017
0.0000
0.0005
0.0005
0.0001
0.0001
0.0015
0.0016
Total
0.2833
0.0326
0.2457
1.0951
0.0097
1.8548
0.0319
0.0674
0.0326
0.0337
0.0059
0.0211
0.0101
0.0025
0.0030
0.0301
0.0347
>
IV)
Total Per Well
1.9402
0.8441
0.1340
0.3395
0.1537
3.4116
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 23 Page 7 of 7
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Haul and Land Disposal @ 10.20% CRN
Deep Water Exploratory (DWE) Well Air Emissions
Air Emission Activity
Baseline Solids Control
Equipment
Diesel Fuel Source
Natural Gas Fuel Source
Baseline Solids Control Subtotal
Supply Boats
Transit
Maneuvering
Loading
Demurrage
Cranes
Barge
Transit
Cranes
Trucks
On-shore Disposal (Landfarming)
Wheel Tractor
Dozer/Loader
On-shore Disposal (Injection)
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
Onshore Diposal Subtotal
Air Emissions (short tons/model well)
NOX
0.4375
0.0406
0.3780
1.3970
0.0159
2.2410
0.0667
0.1041
0.0405
0.0520
0.0064
0.0051
0.0066
0.0038
0.0046
0.0467
0.0464
THC
0.0350
0.0056
0.0306
0.5992
0.0086
1.2070
0.0053
0.0083
0.0174
0.0042
0.0014
0.0008
0.0008
0.0003
0.0004
0.0037
0.0038
S02
0.0291
0.0001
0.0247
0.1016
0.0011
0.1521
0.0044
0.0069
0.0029
0.0035
0.0000
0.0004
0.0006
0.0003
0.0003
0.0031
0.0031
CO
0.0947
0.0259
0.0844
0.2793
0.0023
0.3194
0.0144
0.0225
0.0081
0.0113
0.0049
0.0144
0.0016
0.0008
0.0010
0.0101
0.0127
TSP
0.0313
0.0000
0.0266
0.1177
0.0013
0.1762
0.0048
0.0074
0.0034
0.0037
0.0000
0.0005
0.0005
0.0003
0.0003
0.0033
0.0034
Total
0.6275
0.0723
0.5442
2.4947
0.0291
4.0958
0.0956
0.1493
0.0723
0.0747
0.0128
0.0211
0.0101
0.0055
0.0066
0.0670
0.0695
>
IV)
Total Per Well
4.3481
1.8858
0.3004
0.7592
0.3444
7.6379
Note: On-shore Injection air emissions assume that diesel engines are use for electricity generation
-------
Worksheet No. 24 Page 1 of 2
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Offshore/On-Site Cuttings Injection
10.20% CRN
On-site Injection Diesel Fuel Requirements
Fuel-Consuming Activity
Diesel Fuel Consumed (gal/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
>
IV)
oo
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Injection
748.8
748.8
748.8
36.7
1,569.6
1,569.6
1,569.6
76.8
1,137.6
1,137.6
1,137.6
55.5
2,520.0
2,520.0
2,520.0
123.4
Baseline equipment include: 4x 5 hp primary shale shakers, 4x 5 hp
secondary shale shakers, and 1 x 27.5 hp fines removal unit (avg of 5
hp mud cleaner and 50 hp decanting centrifuge).
Hours of operation equals the drilling length in days (x 24 hr/day). The
transfer equipment utilizes one (1) 100 hp vacuum pump.
Hours of operation equals the drilling length in days (x 24 hr/day). Total
power utilized by the grinding and processing equipment is 120 hp.
Hours of operation equals the cuttings waste volume divided by
cuttings injection rate (bbl/hr).Total power utilized by the grinding and
processing equipment is 600 hp.
TOTAL Diesel Per Well (Gal)
2,283.1
4,785.6
3,468.3
7,683.4
On-site Injection Energy Requirements
Energy-Consuming Activity
Energy Requirements (hp-hr/model well)
Shallow Water
Development | Exploratory
Deep Water
Development | Exploratory
Note
(All information below is detailed in EPA, 2000 unless otherwise
noted.)
Baseline Solids Control
Equipment
Offshore Injection Disposal
Cuttings Transfer
Cuttings Grinding/Proc.
Cuttings Pump Injection
8,424.0
12,480.0
14,976.0
3,667.0
17,658.0
26,160.0
31,392.0
7,684.5
12,798.0
18,960.0
22,752.0
5,549.2
28,350.0
42,000.0
50,400.0
12,338.1
Total Power Requirements
(per well) for Four Activities
(hp):
39,547.0
82,894.5
60,059.2 133,088.1
These four energy-consuming activities were selected for inclusion in
this table as their air emission factors are given in terms of
mass/power-time (g/bhp-hr).
-------
Worksheet No. 24 Page 2 of 2
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge via Offshore/On-Site Cuttings Injection @ 10.20% CRN
On-site Injection Air Emissions (per well) - Rig Fuel Type for Electricity Generation (Diesel)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.6103
1.2792
0.9268
2.0538
THC
0.0488
0.1023
0.0741
0.1643
SO2
0.0406
0.0851
0.0616
0.1366
CO
0.1321
0.2769
0.2006
0.4445
TSP
0.0436
0.0914
0.0662
0.1467
Total
0.8754
1.8349
1.3294
2.9459
On-site Injection Air Emissions (per well) - Rig Fuel Type for Electricity Generation (Natural Gas)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0567
0.1188
0.0861
0.1907
THC
0.0078
0.0164
0.0119
0.0264
SO2
0.0001
0.0002
0.0001
0.0003
CO
0.0362
0.0758
0.0549
0.1218
TSP
0.0000
0.0000
0.0000
0.0000
Total
0.1008
0.2113
0.1531
0.3392
Average On-site Injection Air Emissions (perwell) -Weighted by Rig Diesel/Natural Gas Percentage Fuel Split (85%/15%) for Electricity Generation
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.5273
1.1052
0.8007
1.7744
THC
0.0427
0.0895
0.0648
0.1436
SO2
0.0345
0.0723
0.0524
0.1161
CO
0.1177
0.2467
0.1787
0.3961
TSP
0.0371
0.0777
0.0563
0.1247
Total
0.7592
1.5913
1.1530
2.5549
-------
Worksheet No. 25 Page 1 of 3
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Summary Air Emissions (per well) -Weighted by Land Disposal/On-site Injection Percentage Split
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
1.3055
2.3187
1.9402
4.3481
THC
0.5276
0.9267
0.8441
1.8858
SO2
0.0904
0.1591
0.1340
0.3004
CO
0.2386
0.4150
0.3395
0.7592
TSP
0.1033
0.1813
0.1537
0.3444
Total
2.2654
4.0009
3.4116
7.6379
Total Per Day
0.4357
0.3671
0.4318
0.4365
Note: Weighted summary air emissions totals assume the land disposal/on-site injection percentage splits are (80%/20%), (80%/20%), (100%/0%), and (100%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
en
o
Summary Fuel Usage (per well) -Weighted by Land Disposal/On-site Injection Percentage Split
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Fuel Usage Per Model Well
Gallons
6,550.7
11,546.7
9,797.9
21,907.7
Barrels of Oil
Equivalent
(BOE)
156.0
274.9
233.3
521.6
Note: Weighted summary fuel usage totals assume the land disposal/on-site injection percentage splits are (80%/20%), (80%/20%), (100%/0%), and (100%/0%)
for SWD, SWE, DWD, and OWE model wells respectively.
Note: 1 BOE = 42 gallons of diesel
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Worksheet No. 25 Page 2 of 3
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Daily Drill Rig Emissions
Offshore Gulf of Mexico (GOM)
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) i
: 10.20% CRN
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
3.1570
3.1570
3.1570
3.1570
THC
1.6954
1.6954
1.6954
1.6954
SO2
0.2150
0.2150
0.2150
0.2150
CO
0.4525
0.4525
0.4525
0.4525
TSP
0.2475
0.2475
0.2475
0.2475
Total
5.7674
5.7674
5.7674
5.7674
>
en
Note: Drill rig emissions include impacts from all rig daily operations and one helicopter trip to and from the rig.
Daily Drill Rig Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
gallons per
model well
15,388.0
15,388.0
15,388.0
15,388.0
Barrels of Oil
Equivalent
(BOE) per
model well
366.4
366.4
366.4
366.4
TOTAL
61,552.0
1,465.5
NSPS ZD Annual Air Emissions/Fuel Usage
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
SBF(ZD@ 10.20%)
Total Air
Emissions
(tons)
0.0000
0.0000
146.9212
0.0000
Barrels of Oil
Equivalent
(BOE)
0.0
0.0
19,180.9
0.0
OBF (Zero Discharge)
Total Air
Emissions
(tons)
225.7900
0.0000
391.7899
0.0000
Barrels of Oil
Equivalent
(BOE)
14,428.0
0.0
25,021.5
0.0
WBF (Discharge @ 10.20%)
Total Air Emissions (tons)
1,628.2074
0.0000
1,374.2349
0.0000
Barrels of Oil Equivalent
(BOE)
103,842.5
0.0
87,644.9
0.0
TOTAL
617.6
39,449.6
146.9 19,180.9
3,766.9
250,117.9
Note: Summary annual air emission/fuel usage totals assume the following number of GOM SBF wells (existing sources) under this technology option:
8 SWD wells, 0 SWE wells, 16 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission/fuel usage totals assume the following number of GOM WBF wells (existing sources) under this technology option:
25 SWD wells, 0 SWE wells, 10 DWD wells, and 0 OWE wells
Note: 1 BOE = 42 gallons of diesel
3,002.4
191,487.4
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Worksheet No. 25 Page 3 of 3
NSPS Non-Water Quality Environmental Impacts: GOM Zero Discharge
Region:
Technology:
Offshore Gulf of Mexico (GOM)
Zero Discharge (via Haul and Land Disposal & Offshore/On-Site Cuttings Injection) @ 10.20% CRN
Annual Air Emissions (SBF Model Well -Zero Discharge)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
0.0000
0.0000
80.6416
0.0000
THC
0.0000
0.0000
42.7134
0.0000
SO2
0.0000
0.0000
5.4966
0.0000
CO
0.0000
0.0000
11.7429
0.0000
TSP
0.0000
0.0000
6.3268
0.0000
Total
0.0000
0.0000
146.9212
0.0000
Total
80.6416
42.7134
5.4966
11.7429
6.3268
Annual Air Emissions (OBF Baseline Model Well - Zero Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOx
124.0536
0.0000
215.0443
0.0000
THC
65.4057
0.0000
113.9023
0.0000
SO2
8.4573
0.0000
14.6576
0.0000
CO
18.1415
0.0000
31.3143
0.0000
TSP
9.7318
0.0000
16.8714
0.0000
Total
225.7900
0.0000
391.7899
0.0000
>
en
Total
339.0979
179.3081
23.1148
49.4558
26.6032
Annual Air Emissions (WBF Baseline Model Well - Discharging at 10.20% CRN)
Model Well
Shallow Water Development
Shallow Water Exploratory
Deep Water Development
Deep Water Exploratory
Air Emissions (short tons/model well)
NOX
889.5180
0.0000
750.7684
0.0000
THC
476.3138
0.0000
402.0170
0.0000
SO2
60.5592
0.0000
51.1130
0.0000
CO
127.7389
0.0000
107.8138
0.0000
TSP
69.7111
0.0000
58.8374
0.0000
Total
1,623.8410
0.0000
1,370.5496
0.0000
Total 1,640.2864 878.3307 111.6723 235.5528
Note: Summary annual air emission totals assume the following number of GOM SBF wells (existing sources) under this technology option:
8 SWD wells, 0 SWE wells, 16 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of GOM OBF wells (existing sources) will be subject to zero discharge
under this technology option: 1 SWD wells, 0 SWE wells, 0 DWD wells, and 0 OWE wells
Note: Summary annual air emission totals assume the following number of GOM WBF wells (existing sources) under this technology option:
25 SWD wells, 0 SWE wells, 10 DWD wells, and 0 OWE wells
128.5485
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