United States
Environmental Protection
Agency
Office of Water
4303
EPA-821-R-96-023
October 1996
Development Document for Final Effluent
Limitations Guidelines and Standards for the
Coastal Subcategory of the Oil and Gas
Extraction Point Source Category
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TABLE OF CONTENTS
Page
LIST OF FIGURES xiii
LIST OF TABLES xiv
CHAPTER I INTRODUCTION
1.0 LEGAL AUTHORITY 1-1
1.1 Background 1-1
1.1.1 Clean Water Act 1-1
1.1.2 Section 304(m) Requirements and Litigation 1-3
1.1.3 Pollution Prevention Act 1-4
1.1.4 Prior Regulation and Litigation for the Coastal Subcategory 1-4
CHAPTER II SUMMARY OF THE FINAL REGULATIONS
1.0 INTRODUCTION II-l
1.1 BPT Limitations II-l
1.2 Summary of the Final Rule II-l
1.3 Preventing the Circumvention of Effluent Limitations Guidelines and Standards . . II-3
1.4 The EPA Region 6 Coastal Oil and Gas Production NPDES General Permits .... II-4
CHAPTER HI . INDUSTRY DEFINITION AND WASTESTREAMS
1.0 INTRODUCTION III-l
2.0 REGULATORY DEFINITION III-l
2.1 New Source Definition EtI-4
2.2 Geographical Locations of the Coastal Industry ffl-7
2.3 Wastestreams Regulated by the Coastal Guidelines III-8
2.3.1 Drilling Fluids HI-8
2.3.2 Drill Cuttings HI-8
2.3.3 Dewatering Effluent HI-8
2,3.4 Produced Water HI-9
2.3.5 Produced Sand HI-9
2.3,6 Well Treatment Fluids HI-9
2.3.7 Well Completion Fluids HI-9
2.3.8 Workover Fluids HI-9
2.3.9 Deck Drainage HI-9
2.3.10 Domestic Waste IH-10
2.3.11 Sanitary Waste ffl-10
2.4 Minor Wastes HI-10
3.0 CURRENT NPDES PERMIT STATUS ED-ll
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TABLE OF CONTENTS (Continued)
3.1 NPDES Permits ffl-11
3.2 State Requkements in-12
4.0 REFERENCES Ett-21
CHAPTER IV INDUSTRY DESCRIPTION
1.0 INTRODUCTION IV-1
2.0 DRELUNGACnvmES 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
3.0 PRODUCTION Acnvrms iv-s
3.1 Completion IV-8
3.2 Fluid Extraction IV-11
3.2.1 Enhanced Oil Recovery . . IV-11
3.3 Fluid Separation IV-12
3.4 Well Treatment IV-20
3.5 Workover IV-20
4.0 PRODUCTION AND DRILLING: CURRENT AND FUTURE IV-21
4.1 Industry Profile IV-22
4,2 Current Production Operations IV-23
4.2.1 Gulf of Mexico Current Requirements Baseline IV-23
4.2.2 Mississippi, Alabama, Florida IV-27
4.2.3 California IV-28
4.2.4 CookMet IV-28
4.2.5 North Slope IV-30
4.2.6 Alternative Requkements Baseline IV-31
4.3 Future Coastal Oil and Gas Activity IV-34
4.3.1 Drilling IV-34
4.3.2 New Production Activity IV-35
5.0 REFERENCES IV-36
CHAPTER V DATA AND INFORMATION GATHERING
1.0 INTRODUCTION V-l
2.0 INFORMATION TRANSFERRED FROM THE OFFSHORE RULE V-l
3.0 INDUSTRY SURVEY V-3
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TABLE OF CONTENTS (Continued)
4.0 INVESHGAHON OF SOLIDS CONTROL TECHNOLOGIES FOR DRILLING
FLUIDS V-5
5.0 SAMPLING VISITS TO 10 GULF OF MEXICO COASTAL
PRODUCTION FACILITIES V-8
6.0 STATE DISCHARGE FILE INFORMATION V-ll
7.0 COMMERCIAL DISPOSAL OPERATIONS . . V-13
7.1 Commercial Drilling Waste Disposal Site Visit V-13
7.2 Sampling Visits to Two Commercial Produced Water Injection Facilities V-13
8.0 NORM STUDY V-14
9.0 ALASKA OPERATIONS V-14
9.1 Region 10 Discharge Monitoring Study V-14
9.2 EPA Site Visits and Information Gathering Efforts V-16
9.2.1 Drilling Operations on the North Slope V-18
9.2.2 Production Operations on the North Slope V-18
9.2.3 Drilling Operations hi Cook Inlet V-19
9.2.4 Production Operations in Cook Inlet V-19
10.0 REGION 10 DRILLING FLUID TOXICITY DATA STUDY V-19
11.0 CALIFORNIA OPERATIONS V-20
12.0 OSW SAMPLING PROGRAM V-20
13.0 ESTIMATION OF INNER BOUNDARY OF THE TERRITORIAL SEAS V-20
14.0 OTHER INFORMATION SOURCES V-21
15.0 REFERENCES V-22
CHAPTER VI SELECTION OF POLLUTANT PARAMETERS
1.0 INTRODUCTION VI-1
2.0 DRILLING FLUIDS, DRILL CUTTINGS, AND DEWATERDSfG EFFLUENT VI-1
2.1 Diesel Oil VI-2
2.2 Free Oil VI-2
2.3 Toxicity VI-5
2.4 Cadmium and Mercury VI-7
2.5 Pollutants Not Regulated VI-8
3.0 PRODUCED WATER VI-9
3.1 Pollutants Regulated VI-10
3.2 Pollutants Not Regulated VI-10
4.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS VI-13
4.1 Pollutants Not Regulated VI-14
5.0 PRODUCED SAND VI-14
6.0 DECK DRAINAGE VI-14
7.0 REFERENCES VI-16
iii
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TABLE OF CONTENTS (Continued)
CHAPTER VH DRILLING WASTES CHARACTERIZATION, CONTROL AND
TREATMENT TECHNOLOGIES
1.0 INTRODUCnON , VII-1
2,0 DRILLING WASTE SOURCES VH-1
2.1 Drilling Fluid Sources VH-1
2.2 Drill Cuttings Sources VII-2
2.3 Dewatering Liquid Sources VH-3
3.0 DRILLING WASTE VOLUMES VD-4
3.1 Factors Affecting Drilling Waste Volumes VII-4
3.2 Estimates of Drilling Waste Volumes VII-5
3.3 Dewatering Liquid Volumes VII-10
4.0 DRILLING WASTE CHARACTERISTICS VII-10
4.1 Drilling Fluid Characteristics VII-10
4.2 Drill Cuttings Characteristics VII-14
4.3 Dewatering Liquid Characteristics VII-15
4.4 Cook Inlet Drilling Waste Characteristics VII-15
5,0 CONTROL AND TREATMENT TECHNOLOGIES VII-17
5.1 BPTTechnology VH-17
5.2 Product Substitution - Acute Toxicity Limitations VH-17
5.3 Product Substitution - Clean Barite VII-18
5.4 Product Substitution - Mineral Oil VII-18
5.5 Enhanced Solids Control; Waste Minimization/Pollution Prevention VTI-19
5.5.1 Shale Shakers VH-20
5.5.2 Sand Traps VH-22
5.5.3 Degassers VII-22
5.5.4 Hydroclones VII-22
5.5.5 Centrifuges VH-25
5.5.6 Chemically Enhanced Centrifugation VD-27
5.5.7 Closed-Loop Solids Control System Design VII-30
5.5.8 Solids Control System Efficiency VH-33
5.6 Reserve Pits VII-38
5.6.1 Conventional Reserve Pits VII-39
5.6.2 Managed Reserve Pits VII-39
5.6.3 Pit Closure and Site Restoration VII-41
5.6.4 Reserve Pits on the North Slope VII-42
5.7 Conservation and Reuse/Recycling VII-42
5.8 Land Treatment and Disposal VII-42
5.8.1 Onsite Landfarming VII-42
5.8.2 Centralized Commercial Land Treatment and Disposal
Facilities VH-44
5.8.3 Cook Inlet Land Disposal VH-46
5.9 Subsurface Injection of Drilling Fluids VH-47
IV
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TABLE OF CONTENTS {Continued)
5.10 Grinding and Subsurface Injection of Drilling Waste Vn-47
5.10.1 Cuttings Processing System and Injection Vn-47
5.10.2 Receiving Formation Evaluation-North Slope Operations VH-50
5,10.3 Availability of Subsurface Injection VH-51
5.10.4 Cuttings Washing and Reuse on the North Slope VII-52
5.11 Synthetic-Based Drilling Fluids Vtt-53
6.0 REFERENCES VH-59
CHAPTER Vffl PRODUCED WATER-CHARACTERIZATION, CONTROL AND
TREATMENT TECHNOLOGIES
1.0 INTRODUCTION . VHI-1
2.0 PRODUCED WATER SOURCES VHI-1
3.0 PRODUCED WATER VOLUMES Vffi-1
3.1 Gulf of Mexico . V1H-2
3.2 Alaska VDI-4
3.3 Alternative Baseline Facilities VHI-4
4.0 PRODUCED WATER COMPOSITION Vffl-4
4.1 Composition of Produced Water for the Gulf of Mexico . Vffl-5
4.2 Composition of Produced Water for Cook Met Vffl-6
5.0 CONTROL AND TREATMENT TECHNOLOGIES VHI-7
5.1 BPT Technology VM-7
5.1.1 Equalization VIH-ll
5.1.2 Solids Removal VIH-11
5.1.3 Gravity Separation Vffl-12
5.1.4 Parallel Plate Coalescers vm-12
5.1.5 Gas Flotation ; . . . VHI-14
5.1.6 Chemical Treatment VIH-19
5.1.7 Subsurface Injection and Filtration . ; Vffl-20
5.2 Additional Technologies Evaluated for BAT and NSPS Control Vffl-20
5.2.1 Improved Performance of Gas Flotation Technology Vffl-20
5.2.2 Subsurface Injection vni-24
5.2.3 Filtration VHI-43
5.2.4 Activated Carbon Adsorption Vffl-53
6.0 REFERENCES . . VHI-54
CHAPTER DC MISCELLANEOUS WASTE-CHARACTERIZATION, CONTROL AND
TREATMENT TECHNOLOGIES
1.0 INTRODUCTION K-l
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TABLE OF CONTENTS (Continued)
2.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS IX-1
2.1 Well Treatment, Workover, and Completion Fluid Volumes EX-2
2.2 Well Treatment, Workover, and Completion Fluids Characteristics EX-5
2.2.1 Well Treatment Fluids IX-5
2.2.2 Workover and Completion Fluids IX-6
2.2.3 Chemical Characterization of Well Treatment, Workover, and
Completion Fluids , IX-9
2.3 Well Treatment, Completion, and Workover Fluids Control and Treatment
Technologies IX-11
2.3.1 BPT Technology IX-11
2.3.2 Additional Technologies Considered IX-13
3.0 DECKDRAINAGE IX-13
3.1 Deck Drainage Sources IX-14
3.2 Deck Drainage Volumes IX-14
3.2.1 Total Volumes IX-14
3.2.2 Gulf of Mexico-Production Operations IX-15
3.2.3 Gulf of Mexico-Drilling Operations IX-16
3.2.4 Cook Met Alaska IX-22
3.3 Deck Drainage Characteristics IX-23
3.4 Deck Drainage Control and Treatment Technologies IX-25
3.4.1 BPT Technology IX-25
3.4.2 Additional Deck Drainage Technologies IX-31
4.0 PRODUCED SAND IX-34
4.1 Produced Sand Sources DT-34
4.2 Produced Sand Volumes IX-35
4.2.1 Gulf of Mexico IX-35
4.2.2 CookMet IX-36
4.3 Produced Sand Characterization IX-37
4.4 Produced Sand Control and Treatment Technologies IX-37
4.4.1 BPT Technology . K-40
4.4.2 Additional Technologies IX-42
5.0 DOMESTIC WASTES IX-43
5.1 Domestic Waste Sources IX-43
5.2 Domestic Waste Volume and Characteristics IX-43
5.3 Domestic Waste Control and Treatment Technologies IX-43
5.3.1 Additional Technologies IX-44
6.0 SANITARY WASTES IX-45
6.1 Sanitary Waste Sources, Volumes and Characteristics K-45
6.2 Sanitary Waste Control and Treatment Technologies IX-47
7.0 MINOR DISCHARGES , IX-48
7.1 Blowout Preventer (BOP) Fluid IX-48
7.2 Desalination Unit Discharge IX-48
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TABLE OF CONTENTS (Continued)
7.3 Fire Control System Test Water IX-48
7.4 Non-Contact Cooling Water IX-48
7.5 Ballast and Storage Displacement Water IX-49
7.6 Bilge Water IX-49
7.7 Boiler Slowdown K-49
7.8 Test Fluids IX-49
7.9 Diatomaceous Earth Filter Media IX-50
7.10 Bulk Transfer Operations IX-50
7.11 Painting Operations IX-50
7.12 Uncontaminated Freshwater IX-50
7.13 Waterflooding Discharges IX-50
7.14 Laboratory Wastes IX-51
7.15 Natural Gas Glycol Dehydration Wastes IX-51
7.16 Minor Wastes Volumes and Characteristics IX-51
8.0 REFERENCES IX-53
CHAPTER X COST AND POLLUTANT REMOVAL DETERMINATION OF
DRILLING FLUIDS AND DRILL CUTTINGS
1.0 INTRODUCTION X-l
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS X-l
2.1 Current Practice X-7
3.0 OVERVIEW OF METHODOLOGY X-7
4.0 COMPLIANCE COST METHODOLOGY X-8
4.1 General Assumptions and Input Data X-ll
4.1.1 Drilling Activity X-ll
4.1.2 Model Well Characteristics and Costs X-ll
4.1.3 Transportation and Onshore Disposal Costs of Drilling Wastes X-13
4.1.4 Grinding and Injection X-14
4.2 Option 2: Zero Discharge X-15
4.2.1 Landfill Without Closed-Loop Solids Control X-16
4.2.2 Landfill With Closed-Loop Solids Control X-17
4.2.3 Subsurface Injection Through Dedicated Wells X-18
5.0 POLLUTANT REMOVALS X-19
5.1 General Assumptions and Input Data X-19
5.1.1 Drilling Ruid Characteristics X-20
5.1.2 Drill Cuttings Characteristics X-20
5.1.3 Mineral Oil Content X-20
5.1.4 Barite Characteristics X-21
5.2 Incremental Pollutant Removals X-22
6.0 BCT COMPLIANCE COSTS AND POLLUTANT REMOVALS DEVELOPMENT . . . X-26
vii
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TABLE OF CONTENTS (Continued)
6.1 BCT Methodology X-26
6.2 BPT Baseline X-27
6.3 BCT Compliance Costs, Pollutant Removals, and Cost Reasonableness Test .... X-28
7.0 REFERENCES X-33
CHAPTER XI COMPLIANCE COST AND POLLUTANT REMOVAL DETERMINATION-
PRODUCED WATER
1.0 INTRODUCTION XI-1
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS XI-1
2.1 Option 1 XI-2
2.2 Options 2 and 3 XI-2
2.3 Summary Costs and Reductions XI-3
3.0 GULF OF MEXICO BASELINE COMPLIANCE COST METHODOLOGY XI-4
3.1 Gulf of Mexico Option 1 Baseline Capital and O&M Costs (Improved Operating
Performance of Gas Flotation) XI-8
3.1.1 Development of Gulf of Mexico Option 1 Baseline Capital Costs
(Improved Operating Performance of Gas Flotation) XI-8
3.1.2 Development of Gulf of Mexico Option 1 O&M Costs (Improved
Operating Performance of Gas Flotation) XI-15
3.2 Gulf of Mexico Options 2 and 3 Baseline Capital and O&M Costs (Zero
Discharge by Subsurface Injection) XI-15
3.2.1 Design Capital Costs for Subsurface Injection XI-15
3.2.2 Model Capital Cost Equations for Subsurface Injection XI-19
3.2.3 Gulf of Mexico Baseline Options 2 and 3 O&M Cost (Zero Discharge
by Subsurface Injection) XI-30
4.0 COOK INLET COMPLIANCE COST METHODOLOGY XI-32
4.1 Cook Inlet Options 1 and 2 Compliance Costs (Improved Operation of
Gas Flotation) XI-34
4.1.1 Cook Met Options 1 and 2 Capital Cost Estimates XI-35
4.1.2 Cook Inlet Options 1 and 2 Operating and Maintenance Costs XI-38
4.2 Cook Inlet Option 3 Compliance Costs
(Zero Discharge by Subsurface Injection) XI-38
4.2.1 Cook Met Option 3 Capital Cost Estimates (Subsurface Injection) .... XI-39
4.2.2 Cook Met Option 3 Operating and Maintenance Costs XI-45
4.3 COOK INLET MODEL NEW SOURCE COMPLIANCE COST
ANALYSIS XI-46
5.0 GULF OF MEXICO ALTERNATIVE BASELINE COMPLIANCE COST
METHODOLOGY XI-48
5.1 Gulf of Mexico Alternative Baseline Option 1 Capital Costs XI-49
5.2 Gulf of Mexico Alternative Baseline Option 1 O&M Costs XI-49
5.3 Gulf of Mexico Alternative Baseline Options 2 and 3 Capital Costs XI-54
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TABLE OF CONTENTS (Continued)
5.4 Gulf of Mexico Alternative Baseline Options 2 and 3 O&M Costs XI-54
6.0 POLLUTANT REMOVALS XI-54
7.0 BCT COST TEST XI-55
8.0 REFERENCES XI-59
CHAPTER XH COMPLIANCE COST AND POLLUTANT REMOVAL DETERMINATION-
WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
1.0 INTRODUCTION XH-1
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS XH-1
3.0 BASIS FOR ANALYSIS XH-3
4.0 COMPLIANCE COST METHODOLOGY XH-8
4.1 General Assumptions and Input Data XII-8
4.1.1 Assumptions and Input Data Derived from the Results of the 1993
Coastal Survey XII-10
4.1.2 Assumptions Adopted from the Produced Water Cost Estimate
Methodology XII-10
4.1.3 Additional Assumptions and Data XII-12
4.2 Compliance Cost Methodology XII-12
5.0 POLLUTANT LOADINGS AND REMOVALS XH-13
5.1 General Assumptions and Input Data XH-13
5.2 Methodology XH-14
6.0 BCT COST TEST XII-15
7.0 REFERENCES XH-17
CHAPTER Xffl NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND OTHER
FACTORS
1.0 INTRODUCTION XIH-1
2.0 DRILLING WASTES - COOK INLET XIH-3
2.1 Energy Requirements Xffl-4
2.1.1 Closed-Loop Solids Control and Landfill Xffl-5
2.1.2 Grinding and Injection XHI-8
2.2 Air Emissions Xffl-9
2.3 Solid Waste Generation and Management XIII-12
2.4 Consumptive Water Use Xffl-13
2.5 Other Factors Xffl-13
2.5.1 Impact of Marine Traffic on Coastal Waterways in Cook Inlet XIII-13
2.5.2 Safety Xffl-13
3.0 PRODUCED WATER Xffl-16
IX
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TABLE OF CONTENTS (Continued)
3.1 Gulf of Mexico Baseline XHI-16
3,1.1 Energy Requirements Xm-17
3.1.2 Air Emissions Xffl-25
3.1.3 Landfill Capacity for Drilling Wastes from New Produced Water
Injection Wells Xffl-28
3.2 Cook Inlet Xffl-32
3.2.1 Energy Requirements XIII-32
3.2.2 Air Emissions XIII-34
3.2.3 Landfill Capacity of Drilling Waste for Injection Wells XIII-34
3.3 Gulf of Mexico Alternative Baseline XHI-35
3.3.1 Energy Requirements XHI-36
3.3.2 Air Emissions XHI-38
3.4 Other Factors XIII-39
3.4.1 Impact of Marine Traffic on Coastal Waterways XIII-39
3.5 Underground Injection of Produced Water Xffl-40
4.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS . , XIU-41
4.1 Energy Requirements . XIII-43
4.1.1 Medium/Large Facilities XIH-43
4.1.2 Small Facilities XIII-45
4.1.3 New Sources XIII-47
4.2 Air Emissions : XIH-48
CHAPTER XIV OPTIONS SELECTION: RATIONALE AND TOTAL COSTS
1.0 INTRODUCTION XIV-1
2.0 SUMMARY OF OPTIONS SELECTED AND COSTS XIV-1
3.0 OPTION SELECTION RATIONALE XIV-6
3.1 Drilling Fluids, Drill Cuttings and Dewatering Effluent XIV-6
3.1.1 BAT and NSPS XIV-6
3.1.2 BCT ... XIV-12
3.1.3 Pretreatment Standards for Drilling Wastes XIV-12
3.2 Produced Water and Treatment, Workover and Completion
Fluids XIV-14
3.2.1 Summary of Produced Water andTWC Requirements XIV-14
3.2.2 Options Considered . XIV-15
3.2.3 Rationale for Selection of BAT for Produced Water and TWC Fluids . XTV-16
3.2.4 NSPS Rationale for Produced Water and TWC Fluids XIV-19
3.2.5 BCT for Produced Water and TWC Fluids '. XIV-21
3.2.6 Pretreatment Standards for Produced Water and TWC
Fluids XIV-21
3.3 Deck Drainage XIV-22
3.4 Produced Sand XIV-25
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TABLE OF CONTENTS (Continued)
4.0
3.5 Domestic Wastes XIV-26
3.6 Sanitary Wastes XIV-27
REFERENCES XIV-28
CHAPTER XV BEST MANAGEMENT PRACTICES XV-1
GLOSSARY AND ABBREVIATIONS G-l
APPENDIX VH-1 DRILLING FLUID COMPONENTS AND APPLICATIONS A-l
APPENDIX X-l WORKSHEETS FOR COOK INLET MODEL WELL AND FOUR
DRILLING WASTE MANAGEMENT SCENARIOS A-6
APPENDIX X-2 CALCULATION OF UNIT LANDFILL COST A-17
APPENDIX X-3 DETAILED POLLUTANT REMOVAL ANALYSIS A-21
APPENDIX XI-1 CAPITAL COSTS FOR OPTIONS 1 AND 2 GAS FLOTATION A-25
APPENDIX XI-2 CAPITAL COSTS FOR OPTION 3 ZERO DISCHARGE
VIA INJECTION A-32
APPENDIX XI-3 MODEL NEW SOURCE COOK INLET PLATFORM COMPLIANCE
COST WORKSHEETS A-43
APPENDIX Xn-1 TWC COMPLIANCE COST CALCULATIONS A-46
APPENDIX XH-2 TWC POLLUTANT REMOVALS CALCULATIONS A-55
APPENDIX XHI-1 ENERGY REQUIREMENTS AND AIR EMISSIONS DETAILED
CALCULATIONS FOR COOK INLET DRILLING WASTE ZERO
DISCHARGE SCENARIO 1: CLOSED-LOOP SOLIDS CONTROL
AND LANDFILL A-72
APPENDIX Xm-2 ENERGY REQUIREMENTS AND AIR EMISSIONS: DETAILED
CALCULATIONS FOR COOK INLET DRILLING WASTE ZERO
DISCHARGE SCENARIO 2: GRINDING AND SUBSURFACE
INJECTION A-81
xi
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TABLE OF CONTENTS (Continued)
APPENDIX Xm-3
ENERGY REQUIREMENTS AND AIR EMISSIONS: DETAILED
CALCULATIONS FOR COOK INLET PRODUCED WATER
CONTROL OPTIONS 1 AND 2: IMPROVED GAS FLOTATION
. . A-85
APPENDIX Xm-4 ENERGY REQUIREMENTS AND AIR EMISSIONS: DETAILED
CALCULATIONS FOR COOK INLET PRODUCED WATER
CONTROL OPTION 3: SUBSURFACE INJECTION A-87
APPENDIX Xm-5 ENERGY REQUIREMENTS AND AIR EMISSIONS FOR
LOUISIANA OPEN BAY DISCHARGERS AND TEXAS
DISCHARGERS SEEKING INDIVIDUAL PERMITS - OPTION 1:
IMPROVED GAS FLOTATION A-89
APPENDIX Xm-6 ENERGY REQUIREMENTS AND AIR EMISSIONS FOR
LOUISIANA OPEN BAY DISCHARGERS AND TEXAS
DISCHARGERS SEEKING INDIVIDUAL PERMITS - OPTIONS 2
AND 3: ZERO DISCHARGE VIA SUBSURFACE INJECTION A-94
APPENDIX Xm-7 CALCULATIONS FOR ENERGY REQUIREMENTS AND AIR
EMISSIONS FOR LOUISIANA OPEN BAY SMALL VOLUME
FACILITIES A-99
APPENDIX Xm-8 CALCULATIONS FOR ENERGY REQUIREMENTS AND AIR
EMISSIONS FOR TEXAS SMALL VOLUME FACILITIES . . . A-108
APPENDIX XUI-9 GULF OF MEXICO TREATMENT, WORKOVER AND
COMPLETION FLUID VOLUME CALCULATIONS FOR
' EXISTING AND NEW SOURCES . A-110
APPENDIX Xm-10 SUMMARY FUEL CONSUMPTION CALCULATIONS FOR
SMALL FACILITIES A-113
xu
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LIST OF FIGURES
IV-l Typical Drilling Fluids Circulation System IV-6
IV-2 Typical Completion Methods IV-9
IV-3 Produced Water Treatment System IV-14
IV-4 Two-Phase Separator IV-15
IV-5 Three-Phase Separator IV-16
IV-6 Vertical Heater-Treater IV-18
IV-7 Gun Barrel IV-19
V-l Sample Locations and Treatment System Sequences at the 10 Coastal Production
Facilities V-12
VII-1 Hydroclone Flow Patterns VII-23
VEI-2 Decanting Centrifuge VH-26
VII-3 Rotary Mud Separator (RMS) Centrifuge VTI-28
Vn-4 Example Closed-Loop Solids Control System (Unweighted Drilling Fluid Application) . VII-32
VII-5 GAP Energy Mud Recirculation and Solids Control System VB-34
Vn-6 ARCO Mud Recirculation and Solids Control System VB-35
VH-7 UNOCAL Mud Recirculation and Solids Control for 11,700 ft to 13,500 ft VH-36
Vn-8 Layout of a Drilling Location Utilizing a Conventional Reserve Pit VTI-40
Vn-9 Annular Injection During Drilling ¥11-48
Vm-1 Typical SkimPUe VHI-13
Vm-2 Dispersed Gas Flotation Unit Vffl-17
VTfl-3 Typical Subsurface Injection Well VHI-29
Vffl-4 Cartridge Filter . , , VHJi-44
Vm-5 Multi-Media Granular Filter Vffl-47
Vm-6 Flow Dynamics of a Crossflow Filter VHI-50
K-l Deck Drataage Sump IX-27
IX-2 Deck Drainage Treatment System '. IX-30
IX-3 Closed Hole Perforated Completion (With Gravel Pack) TK-41
XI-1 Produced Water Cost Determination Flow Chart For Gulf of Mexico XI-7
xm
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LIST OF TABLES
Page
1-1 COASTAL SUBCATEGORY BPT EFFLUENT LIMITATIONS 1-5
m-1 NPDES PERMIT REQUIREMENTS IH-17
IV-1 PROFILE OF COASTAL OIL AND GAS INDUSTRY IV-24
IV-2 GULF OF MEXICO DISCHARGERS OF OFFSHORE PRODUCED WATER TO
MISSISSIPPI RIVER PASSES IV-26
IV-3 OIL AND GAS PRODUCTION FACILITIES IN COOK INLET REGION AS OF
MARCH 1996 .\ . IV-29
IV-4 OIL AND GAS PRODUCTION FACILITIES ON THE NORTH SLOPE IV-31
IV-5 TEXAS DISCHARGERS SEEKING INDIVIDUAL PERMITS AND LOUISIANA
OPEN BAY DISCHARGERS IV-33
V-l TOTAL WELL COUNT SURVEYED FOR COASTAL OIL & GAS WELLS BY
CATEGORY , V-5
V-2 TECHNICAL DATA FOR THE THREE WELL DRILLING OPERATIONS
VISITED V-7
V-3 PRODUCTION FACILITIES SAMPLED V-9
V-4 SUMMARY STATISTICS OF RADIUM-226 (pCi/1) FROM COASTAL OIL AND
GAS SITES V-15
V-5 SUMMARY STATISTICS OF RADIUM-228 (pCi/1) FROM COASTAL OIL AND
GAS SITES V-16
V-6 SUMMARY STATISTICS OF LEAD-210 (pCi/1) FROM COASTAL OIL AND
GAS SITES V-17
VI-1 ORGANIC CONSTITUENTS OF DIESEL AND MINERAL OILS VI-3
VI-2 POLLUTANT ANALYSIS OF GENERIC DRILLING FLUIDS VI-4
VI-3 ORGANIC POLLUTANTS DETECTED IN GENERIC DRILLING FLUIDS VI-6
VI-4 ANALYSIS OF TRACE METALS IN BARITE SAMPLES VI-8
VI-5 METALS CONCENTRATION IN BARITE VI-9
VI-6 POLLUTANT LOADING CHARACTERIZATION-PRODUCED WATER VI-11
xiv
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LIST OF TABLES (Continued)
VH-l PERCENT WASHOUT FACTORS VH-6
Vn-2 WASTE DRILL CUTTINGS AND DRILLING FLUID VOLUMES VH-7
VH-3 COOK INLET DRILLING WASTE VOLUMES VE-9
VH-4 COOK INLET DRILLING WASTE CHARACTERISTICS VH-13
VH-5 COMPARISON OF ANALYTICAL CHARACTERISTICS OF CENTRIFUGE
WATER EFFLUENT FROM THE GAP ENERGY AND ARCO DRILLING
SAMPLING EPISODES TO THE EPA REGION VI GENERAL PERMIT
POLLUTANT LIMITATIONS FOR DRILLING OPERATIONS VH-16
VH-6 SOLIDS SEPARATION EQUIPMENT APPLICATIONS VH-31
VH-7 CLOSED-LOOP SOLIDS CONTROL SYSTEM EFFICIENCIES VH-37
Vm-1 CHARACTERISTICS OF THE 10 PRODUCTION FACILITIES SAMPLED
BY EPA Vm-3
Vffl-2 PRODUCED WATER VOLUMES FOR OIL AND GAS PRODUCTION
FACILITIES IN COOK INLET REGION VHI-5
VIH-3 PERCENT OCCURRENCE OF ORGANICS FOR BPT LEVEL TREATMENT
EFFLUENT SAMPLES FROM THE 1992 EPA 10 PRODUCTION FACILITY
STUDY Vm-7
Vm-4 SUMMARY POLLUTANT CONCENTRATIONS FOR BPT LEVEL EFFLUENT
FROM THE 1992 EPA 10 PRODUCTION FACILITY STUDY Vffl-8
Vffl-5 PRODUCED WATER POLLUTANT CHARACTERIZATION FOR COOK INLET,
ALASKA Vm-9
Vffl-6 COOK INLET PRODUCED WATER RADIOACTIVITY DATA VIH-10
Vffl-7 PRODUCED WATER EFFLUENT CONCENTRATION FOR THE GULF OF
MEXICO VIII-21
Vm-8 INFLUENT AND EFFLUENT POLLUTANT CONCENTRATION MEANS
FROM CARTRIDGE FILTRATION VHI-46
Vm-9 GRANULAR MEDIA FILTRATION PERFORMANCE VIEWS
xv
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LIST OF TABLES (Continued)
Vm-10 MEMBRANE FILTRATION PERFORMANCE DATA FROM THE MEMBRANE
FILTRATION STUDY VIH-52
K-l DATA USED IN TWC FLUID COMPLIANCE COST ANALYSIS IX-2
DC-2 TYPICAL VOLUMES FROM WELL TREATMENT, WORKOVER, AND
COMPLETION OPERATIONS IX-3
IX-3 VOLUMES DISCHARGED PER JOB DURING WORKOVER, COMPLETION
AND WELL TREATMENT OPERATIONS FROM THE COOK INLET
DISCHARGE MONITORING STUDY K-4
K-4 WELL TREATMENT CHEMICALS K-6
IX-5 COMMON BRINE SOLUTIONS USED IN WORKOVER AND COMPLETION
OPERATIONS IX-8
K-6 ADDITIVES TO COMPLETION AND WORKOVER FLUIDS IX-9
IX-7 POLLUTANT CONCENTRATIONS IN TREATMENT, WORKOVER, AND
COMPLETION FLUIDS IX-10
K-8 ANALYTICAL RESULTS FROM THE COOK INLET DISCHARGE
MONITORING STUDY IX-12
IX-9 ANNUAL VOLUME OF DECK DRAINAGE DISPOSED IX-15
IX-10 ANNUAL DECK DRAINAGE VOLUMES CURRENTLY DISCHARGED
FROM WATER-BASED DRILLING OPERATIONS IN THE COASTAL GULF
OF MEXICO REGION IX-17
K-l 1 LAND-BASED DRILLING OPERATIONS DECK DRAINAGE PER WELL
VOLUMES IX-17
IX-12 LAND-BASED DRILLING OPERATIONS DECK DRAINAGE ALL WELLS IX-17
K-13 PROPORTION OF LAND-BASED VERSUS BARGE-BASED OPERATIONS
REPORTED IN THE COSTAL SURVEY IX-18
IX-14 ESTIMATED NUMBER OF WELLS DRILLED IN 1992 IN COSTAL GULF OF
MEXICO AND DURATION OF DRILLING IX-19
IX-15 NUMBER OF WELLS BY LOCATION AND WELL TYPE CATEGORIES IX-19
xvi
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LIST OF TABLES (Continued)
IX-16 SUMMARY OF DECK DRAINAGE INFORMATION FROM THE THREE
COASTAL DRILLING SAMPLING SITE VISITS IN LOUISIANA IX-21
IX-17 ANNUAL DECK DRAINAGE VOLUMES DISPOSED IN COOK INLET,
ALASKA IX-23
IX-18 CHARACTERISTICS OF DECK DRAINAGE FROM OFFSHORE GULF OF
MEXICO PLATFORMS IX-25
IX-19 POLLUTANT CONCENTRATIONS IN UNTREATED DECK DRAINAGE IX-26
IX-20 PRODUCED SAND VOLUMES GENERATED IX-36
IX-21 RANGE OF POLLUTANT CONCENTRATIONS IN PRODUCED SAND FROM
THE 1992 COASTAL PRODUCTION SAMPLING PROGRAM IX-38
K-22 TYPICAL UNTREATMENT COMBINED SANITARY AND DOMESTIC
WASTES FROM OFFSHORE FACILITIES IX-44
IX-23 TYPICAL OFFSHORE SANITARY AND DOMESTIC WASTE
CHARACTERISTICS IX-44
IX-24 GARBAGE DISCHARGE RESTRICTIONS IX-46
IX-25 MINOR WASTE DISCHARGE VOLUMES IX-52
X-l INCREMENTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS FOR
DRILLING FLUIDS AND DRILL CUTTINGS BAT OPTIONS X-6
X-2 DRILLING WASTE COMPLIANCE COSTS FOR FOUR ZERO DISCHARGE
SCENARIOS X-10
X-3 SCHEDULE OF DRILLING ACTIVITY BY OPERATOR IN COOK INLET,
ALASKA FOR SEVEN YEARS AFTER PROMULGATION X-ll
X-4 ORGANIC CONSTITUENTS IN MINERAL OIL X-21
X-5 METALS CONCENTRATION IN BARITE X-22
X-6 COOK INLET DRILLING WASTE POLLUTANT LOADINGS AND REMOVALS
BASED ON ZERO DISCHARGE X-23
xvii
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LIST OF TABLES (Continued)
Page
X-7 COOK INLET BPT DRILLING WASTE DISPOSAL COST AND
CONVENTIONAL POLLUTANT REMOVAL CALCULATIONS X-27
X-8 COOKINLET DRILLING WASTE UNIT BPT COSTS X-27
X-9 CONVENTIONAL POLLUTANT REMOVALS X-28
X-10 BCT COST TEST RESULTS FOR DRILLING FLUIDS AND DRILL CUTTINGS
BASED ON DISPOSAL COSTS FOR CLOSED-LOOP SOLIDS CONTROL AND
LANDFILL X-30
X-l 1 BCT COST TEST RESULTS FOR DRILLING FLUIDS AND DRILL CUTTINGS
BASED ON DISPOSAL COSTS FOR SUBSURFACE INJECTION X-30
XI-1 TOTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS FOR
PRODUCED WATER BAT OPTIONS (BASELINE) XI-4
XI-2 TOTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS FOR
PRODUCED WATER BAT OPTIONS (ALTERNATIVE BASELINE) XI-5
XI-3 DESIGN CAPITAL COSTS (1995 DOLLARS) FOR IMPROVED GAS
FLOTATION AT MEDIUM/LARGE FACILITIES XI-10
XI-4 CAPITAL AND O&M STEP COSTS AND COST EQUATIONS FOR IMPROVED
GAS FLOTATION XI-12
XI-5 GULF OF MEXICO FACILITIES CAPITAL AND O&M COSTS PRODUCED
WATER TREATMENT VIA IMPROVED GAS FLOTATION (1995 DOLLARS) . . XI-14
XI-6 DESIGN O&M COSTS FOR IMPROVED GAS FLOTATION AT
MEDIUM/LARGE FACILITIES XI-16
XI-7 CAPITAL AND O&M COST EQUATIONS FOR INJECTION OF PRODUCED
WATER AT MEDIUM/LARGE FACILITIES XI-20
XI-8 DESIGN CAPITAL COSTS (1995 DOLLARS) FOR PRODUCED WATER
INJECTION AT GULF OF MEXICO PRODUCTION FACILITIES XI-21
XI-9 GULF OF MEXICO FACILITIES CAPITAL AND O&M COSTS PRODUCED
WATER ZERO DISCHARGE VIA INJECTION (1995 DOLLARS) XI-23
XI-10 FLORES & RUCKS OIL/WATER/GAS PROCESSING LOCATIONS XI-25
xvm
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LIST OF TABLES (Continued)
Page
XI-11 FLORES & RUCKS PRODUCED WATER COMPLIANCE COST SCENARIOS
(1995 DOLLARS) XI-28
XI-12 FLORES & RUCKS PRODUCED WATER COMPLIANCE COST SCENARIOS
(1995 DOLLARS) XI-29
XI-13 DESIGN O&M COSTS (1995 DOLLARS PER YEAR) FOR PRODUCED WATER
INJECTION AT GULF OF MEXICO PRODUCTION FACILITIES XI-31
XI-14 SUMMARY CAPITAL AND O&M COSTS FOR COOK INLET PRODUCED
WATER BAT OPTIONS XI-33
XI-15 EXISTING EQUIPMENT AT SELECTED COOK INLET TREATMENT
FACILITIES AND PLATFORMS XI-35
XI-16 CAPITAL AND O&M COSTS FOR GAS FLOTATION (OPTIONS 1 AND 2)
PER COOK INLET FACILITY/PLATFORM XI-37
XI-17 SUMMARY OF EQUIPMENT AND MODIFICATIONS ASSUMED NECESSARY
FOR COMPLIANCE WITH OPTION 3: ZERO DISCHARGE VIA INJECTION . . . XI-40
XI-18 CAPITAL AND O&M COSTS FOR OPTION 3 PER COOK INLET
FACILITY/PLATFORM XI-41
XI-19 COOK INLET FILTRATION O&M COSTS (1995 $/YR) XI-47
XI-20 LOUISIANA OPEN BAY DISCHARGERS COSTS XI-50
XI-21 TEXAS DISCHARGERS SEEKING INDIVIDUAL PERMITS COSTS XI-51
XI-22 TOTAL CAPITAL AND O&M COSTS FOR PRODUCED WATER BAT OPTIONS
ALTERNATIVE BASELINE XI-53
XI-23 ANNUAL BAT POLLUTANT REMOVALS FOR PRODUCED WATER IN THE
GULF OF MEXICO AND COOK INLET XI-56
XI-24 ANNUAL BAT POLLUTANT REMOVALS FOR PRODUCED WATER IN THE
GULF OF MEXICO AND COOK INLET XI-57
XI-25 PRODUCED WATER BCT COST TEST ANALYSIS XI-58
xix
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LIST OF TABLES (Continued)
XH-l TOTAL ANNUAL COMPLIANCE COST ESTIMATES FOR TREATMENT,
WORKOVER, AND COMPLETION FLUIDS (1995 $) XH-3
XII-2 SUMMARY OF ANNUAL TWC JOBS AT EXISTING GULF OF MEXICO
SOURCES XH-7
XH-3 NUMBER OF WELLS LOCATED IN FRESH VERSUS SALINE WATERS IN
THE COASTAL GULF OF MEXICO REGION XII-8
XH-4 SUMMARY OF ANNUAL TWC JOBS AT NEW GULF OF MEXICO SOURCES . XH-9
XH-5 TOTAL TWC VOLUMES XH-14
XH-6 TOTAL ANNUAL POLLUTANT REMOVALS FOR TREATMENT,
WORKOVER, AND COMPLETION FLUIDS (POUNDS/YEAR) XH-15
XH-7 BCT COST TEST FOR TREATMENT, WORKOVER, AND COMPLETION
FLUIDS XH-16
Xm-1 ANNUAL ENERGY REQUIREMENTS AND AIR EMISSIONS FOR THE
REGULATORY OPTIONS BY WASTESTREAM Xffl-2
XJJI-2 AIR EMISSIONS AND ENERGY REQUIREMENTS FOR PRODUCED WATER
OPTIONS (ALTERNATIVE BASELINE) XIH-S
Xm-3 POWER AND FUEL REQUIREMENTS FOR DRILLING WASTE ZERO
DISCHARGE OPTION SCENARIOS XUI-6
Xm-4 UNCONTROLLED EMISSION FACTORS FOR DRILLING WASTE
MANAGEMENT ACTIVITIES Xffl-10
Xm-5 AIR EMISSIONS ASSOCIATED WITH ZERO DISCHARGE SCENARIOS FOR
EXISTING SOURCES OF DRILLING WASTES IN COOK INLET Xffl-11
Xffl-6 PRIMARY CAUSES AND CLASSIFICATION OF ACCIDENTS ON MODUs
AND OSVs Xffl-15
XJH-7 GULF OF MEXICO AER. EMISSIONS AND ENERGY REQUIREMENTS FOR
PRODUCED WATER OPTIONS (CURRENT REQUIREMENTS BASELINE) . . . Xffl-17
Xm-8 FUEL REQUIREMENTS FOR GAS FLOTATION UNITS Xffl-19
XIH-9 IMPROVED GAS FLOTATION ENERGY REQUIREMENT CALCULATIONS . . Xffl-20
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LIST OF TABLES (Continued)
Page
Xm-10 POWER AND FUEL REQUIREMENTS FOR PRODUCED WATER GAS
FLOTATION IN THE GULF OF MEXICO XIU-21
Xm-11 DESIGN POWER AND FUEL REQUIREMENTS FOR PRODUCED WATER
INJECTION Xm-24
XIH-12 MATHEMATICAL MODELS FOR POWER REQUIREMENTS XHI-25
Xm-13 ENERGY AND FUEL REQUIREMENTS FOR PRODUCED WATER
INJECTION IN GULF OF MEXICO FACILITIES XIU-26
Xffl-14 UNCONTROLLED AND CONTROLLED EMISSION FACTORS XHI-28
Xin-15 UNCONTROLLED AIR EMISSIONS FOR PRODUCED WATER IMPROVED
GAS FLOTATION IN COASTAL GULF OF MEXICO XHI-29
Xm-16 CONTROLLED AIR EMISSIONS FOR PRODUCED WATER IMPROVED
GAS FLOTATION IN COASTAL GULF OF MEXICO XIU-29
XIH-17 UNCONTROLLED AIR EMISSIONS FOR PRODUCED WATER INJECTION
IN GULF OF MEXICO COASTAL FACILITIES XEI-30
Xm-18 CONTROLLED AIR EMISSIONS FOR PRODUCED WATER INJECTION IN
GULF OF MEXICO COASTAL FACILITIES XHI-31
Xm-19 COOK INLET POWER AND FUEL REQUIREMENTS FOR PRODUCED
WATER CONTROL OPTIONS XIH-33
XHI-20 AIR EMISSIONS ASSOCIATED WITH CONTROL OPTIONS FOR EXISTING
SOURCES OF PRODUCED WATER IN COOK INLET Xffl-35
XIH-21 SUMMARY POWER REQUIREMENTS AND AIR EMISSION FOR PRODUCED
WATER CONTROL OPTIONS FOR GULF OF MEXICO FACILITIES XIU-37
Xm-22 UNCONTROLLED AIR EMISSIONS AND ENERGY REQUIREMENTS FOR
GULF OF MEXICO TWC FLUIDS BAT AND NSPS OPTIONS Xffl-42
XDI-23 TWC FLUID ENERGY REQUIREMENTS FOR MAJOR PASS DISCHARGERS
AND GENERAL PERMIT FACILITIES (EXISTING SOURCES) XHI-46
XUI-24 EXISTING FACILITY TWC FLUIDS NON-WATER QUALITY IMPACTS FOR
ALL REGULATORY OPTIONS XIU-47
xxi
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LIST OF TABLES (Continued)
XM-25 TWC FLUID ENERGY REQUIREMENTS FOR MAJOR PASS DISCHARGERS
AND GENERAL PERMIT FACILITIES (NEW SOURCES) XHI-49
Xm-26 SMALL FACILITY ENERGY REQUIREMENTS FOR NEW SOURCES OF
TWC FLUIDS Xin-50
XH-27 FUEL CONSUMPTION AND AIR EMISSIONS FOR EXISTING SOURCES Xffl-51
Xm-28 FUEL CONSUMPTION AND AIR EMISSIONS FOR NEW SOURCES XIH-52
XJV-4 BPT EFFLUENT LIMITATIONS PROMULGATED BY THIS RULE XTV-2
XW-2 BATEFFLUENT LIMITATIONS XTV-3
XIV-3 BCT EFFLUENT LIMITATIONS . XIV^
XIV-4 NSPS EFFLUENT LIMITATIONS XTV-5
XIV-5 PSNS AND PSES EFFLUENT LIMITATIONS XIV-6
XXII
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CHAPTER I
INTRODUCTION
1.0 LEGAL AUTHORITY
The Environmental Protection Agency (EPA) is establishing these final Effluent Limitations Guide-
lines, New Source Performance and Pretreatment Standards for the Coastal Subcategory of the Oil and Gas
Extraction Point Source Category (coastal guidelines) under the authority of Sections 301, 304, 306, 307,
308, and 501 of the Clean Water Act (CWA) (the Federal Water Pollution Control Act Amendments of
1972, as amended by the Clean Water Act of 1977 and the Water Quality Act of 1987); 33 U.S.C. 1311,
1314, 1315, 1317, and 1361. The requirements of the final regulation and supporting technical information
are presented in the proceeding sections of this document. This chapter describes EPA's legal authority for
issuing the coastal guidelines, as well as background information on prior regulations and litigation leading
up to this regulation.
1.1 BACKGROUND
1.1.1 Clean Water Act
The CWA establishes a comprehensive program to "restore and maintain the chemical, physical, and
biological integrity of the Nation's waters" (Section 101(a)). To implement the CWA, EPA is to issue
technology-based effluent limitations guidelines, new source performance standards and pretreatment stan-
dards for industrial dischargers. The levels of control associated with these effluent limitations guidelines and
the new source performance standards for direct and indirect dischargers are summarized briefly below.
1. Best Practicable Control Technology Currently Available (BPT)
BPT effluent limitations guidelines are generally based on the average of the best existing performance
by plants of various sizes, ages, and unit processes within the industrial category or subcategory.
In establishing BPT effluent limitations guidelines, EPA considers the following criteria: (1) total cost
of achieving effluent reductions in relation to the effluent reduction benefits, (2) the age of equipment and
facilities involved, (3) the processes employed, (4) the process changes required, (5) the engineering aspects
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of the control technologies, (6) (he non-water quality environmental impacts (including energy requirements),
and (7) other factors as the EPA Administrator deems appropriate (Section 304(b)(l)(B) of the CWA). EPA
considers the category- or subcategory-wide cost of applying (he technology in relation to the effluent
reduction benefits. Where existing performance is uniformly inadequate, BPT may be transferred from a
different subcategory of category.
2. Best Available Technology Economically Achievable (BAT)
BAT effluent limitations guidelines, in general, represent (he best existing economically achievable
performance of plants in the industrial subcategory or category. The CWA establishes BAT as a principal
national means of controlling the direct discharge of toxic pollutants and nonconventional pollutants to
navigable waters. The factors considered in assessing BAT include the following: (1) the age of the
equipment and facilities involved, (2) the processes employed, (3) the engineering aspects of the control
technologies, (4) potential process changes, (5) the costs and economic impact of achieving such effluent
reduction, (6) non-water quality environmental impacts (including energy requirements) and (7) other factors
as the EPA Administrator deems appropriate (Section 304(b)(2)(B) of the CWA). EPA retains considerable
discretion in assigning the weight to be accorded these factors. As with BPT, where existing performance
is uniformly inadequate, BAT may be transferred from a different subcategory or category. BAT may include
process changes or internal controls, even when these technologies are not common industry practice.
3. Best Conventional Pollutant Control Technology (BCT)
The 1977 Amendments added Section 301(b)(2)(E) to the CWA establishing "best conventional
pollutant control technology" (BCT) for the discharge of conventional pollutants from emting industrial point
sources. Section 304(a)(4) designated me following as conventional pollutants: biochemical oxygen demand
(BOD), 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 PR 44501).
BCT replaces BAT for the control of conventional pollutants. In addition to other factors specified
in section 304(b)(4)(B), the CWA requires that BCT effluent limitations guidelines be established hi light of
a two-part "cost-reasonableness" test (American Paper Institute v. EPA. 660 F.2d 954 (4th Cir. 1981)). The
methodology for establishing BCT effluent limitations guidelines became effective on August 22, 1986 (51
FR 24974, July 9, 1986).
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4. New Source Performance Standards (NSPS)
NSPS are based on the performance of the best available demonstrated control technology (BADCT).
Since new plants have the opportunity to install the best and most efficient production processes and
wastewater treatment technologies, Congress directed EPA to consider the best demonstrated process changes,
in-plant controls, and end-of-process control and treatment technologies that reduce pollution to the maximum
extent feasible. As a result, NSPS should generally represent the most stringent numerical values attainable
through the application of best available demonstrated control technology for all pollutants (i.e., conventional,
nonconventional, and priority pollutants). In establishing NSPS, EPA is directed to take into consideration
the cost of achieving the effluent reduction and any non-water quality environmental impacts and energy
requirements.
5. Pretreatment Standards for Existing Sources (PSES)
Under Section 307(b) of the CWA, pretreatment standards for existing sources (PSES) are developed
to prevent the discharge of pollutants that may interfere with or pass through to publicly-owned treatment
works (POTWs). These discharges to POTWs are known as indirect discharges. Pretreatment standards are
technology-based and analogous to BAT effluent limitations guidelines.
6. Pretreatment Standards for New Sources (PSNS)
Section 307(c) of the CWA authorizes EPA to promulgate pretreatment standards for new sources
(PSNS) at the same time it promulgates (NSPS). PSNS are analogous to PSES in that PSNS limitations are
developed to prevent discharges of pollutants to pass through or interfere with POTWs. New indirect dis-
chargers have the opportunity to install the best available demonstrated technologies into their new plants
similar to that of NSPS since the same factors are considered when promulgating both PSNS and NSPS
limitations; and therefore EPA sets PSNS after considering the same criteria considered for NSPS.
1.1.2 Section 304{m) Requirements and Litigation
Section 304(m) of the CWA (33 U.S.C. 1314(m)), added by the Water Quality Act of 1987, requires
EPA to establish schedules for (1) reviewing and revising existing effluent limitations guidelines and standards
(effluent guidelines), and (2) promulgating new effluent guidelines. On January 2, 1990, EPA published an
Effluent Guidelines Plan (55 FR 80), in which schedules were established for developing new and revised
effluent guidelines for several industrial categories. One of the industries for which the Agency established
a schedule was the Coastal Oil & Gas Extraction subcategory. Natural Resources Defense Council, Inc.
(NRDC) and Public Citizen, Inc., challenged the Effluent Guidelines Plan in a suit filed in U.S. District Court
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for the District of Columbia (NRDC et al v. Reilly. Civ. No. 89-2980). On January 31, 1992, the Court
entered a consent decree (the "304(m) Decree"), which establishes schedules for, among other things, EPA's
proposal and promulgation of effluent guidelines for a number of point source categories, including the
Coastal Oil and Gas Industry. The most recent Effluent Guidelines Plan was published in the Federal Register
on October 7,1996 (61 FR 52582).
1.1.3 Pollution Prevention Act
In the Pollution Prevention Act of 1990 (42 U.S.C. 13101 et seq.. Pub. 1. 101-508, November 5,
1990), Congress declared pollution prevention the national policy of the United States. This act declares that
pollution should be prevented or reduced whenever feasible; pollution that cannot be prevented should be
recycled or reused in an environmentally safe manner wherever feasible; pollution that cannot be recycled
should be treated; and disposal or release into the environment should be chosen only as a last resort.
1.1.4 Prior Regulation and Litigation for the Coastal Subcategory
EPA proposed coastal subcategory effluent limitations guidelines and standards on October 13,1976
(41 FR 44943). On April 13,1979 (44 FR 22069) EPA promulgated BPT effluent limitations guidelines for
all subcategories under the oil and gas category, but deferred action on the BAT limitations, new source
performance standards, and pretreatment standards. Table 1-1 presents the 1979 BPT limitations.
On November 8, 1989, a notice of information and request for comments on the Coastal Oil and
Gas subcategory effluent limitations guidelines development was published (54 FR 46919). The notice
presented the Agency's approach to effluent limitations guidelines development for BAT, BCT, and NSPS.
It also requested data available to develop such limitations. On February 17, 1995 (60 FR 9428), EPA
proposed effluent limitations guidelines and standards for coastal discharges under BPT, BCT, BAT, NSPS,
PSESandPSNS.
The definition of the coastal oil and gas industrial subcategory has been the subject of regulatory
and litigation activity since 1979. The 1976 regulations had previously defined "coastal" on a geographic
basis which specified boundaries in terms of longitude and latitude. Since then several changes were made
or suggested regarding the definition of the coastal subcategory. These actions are summarized below:
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TABLE 1-1
COASTAL SUBCATEGORY BPT EFFLUENT LIMITATIONS
,„, „, , ,,W^j«r,eam;,4;, ',
Produced Water
Drill Cuttings
Drilling Fluids
Well Treatment Fluids
Deck Drainage
Sanitary-MlO
Sanitary-M9IM
Domestic Wastes
, „ , , , * - PayaEQ^ter ' -
Oil and Grease
Free Oil*
Free Oil*
Free Oil*
Free Oil*
Residual Chlorine
Floating Solids
Floating Solids
'"••• BPT Effluent Limitation
72 mg/1 Daily Maximum
48 mg/1 30-Day Average
No Discharge
No Discharge
No Discharge
No Discharge
1 mg/1 (minimum)
No Discharge
No Discharge
The free oil "no discharge" limitation is implemented by requiring no oil sheen to be present upon discharge.
Source: 40 CER Part 435, Subpart D.
COASTAL DEFINITIONS
1976: Land and water areas landward of the inner boundary of the territorial seas and
bounded inland by a series of longitude and latitude points in Louisiana and Texas
(the Chapman line).
1979: The final BPT effluent guidelines defined coastal at 40 CFR, 435 as: (1) Any body
of water landward of the inner boundary of the territorial (current) seas as defined
in 40 CFR 125.1 (gg) or (2) any wetlands adjacent to such waters.
Wetlands are defined as surface areas which are saturated by surface or ground
water at a frequency and duration sufficient to support a prevalence of vegetation
typically adapted for life in saturated soil conditions. Wetlands generally include
swamps, marshes, bogs, and similar areas. (40 CFR Part 435.41 (f))
As part of the 1979 final rulemaking, EPA also attempted to reclassify approximately
1200 wells from the coastal subcategory to the onshore subcategory because these
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wells were located onshore but discharged to coastal waters. The American
Petroleum Institute challenged this reclassification.
1981: American Petroleum Institute v. EPA. 661 F.2d 340, 354-57 (5th Gir. 1981), the
Court held that EPA had failed to consider adequately the cost to the reclassified
facilities of the 1979 regulatory change. As a result of the Court's decision, EPA
suspended the applicability of the onshore subcategory guidelines to the reclassified
wells and to any wells that came into existence in the affected area after the issuance
of the 1979 redefinition. See 47 FR 31554 (July 21, 1982).
1989: EPA proposed to modify the 1979 definition to include only those facilities in saline
water (greater than 0.5 parts per thousand) landward of the inner boundary of the
territorial seas. (This would reclassify facilities located inland over saline and fresh
water areas to the onshore or another subcategory). EPA never adopted this
proposal.
1995: EPA proposed certain clarifications to the coastal definition to reflect the API
decision and use the term of art "waters of the U.S." rather than body of water.
EPA proposed revising the regulation to state that the coastal subcategory would
consist of "any oil and gas facility located in or on a water of the United States
landward of the territorial seas." The revised definition would make it clear that
facilities located in or on isolated wetlands constituting a water of the U.S. would be
considered coastal. The revised definition would no longer refer to 40 CFR Part
125.1(gg) since Part 125 was revised at 44 FR 32948 (June 7, 1979) and no longer
exists in the CFR. Also, the proposed clarification explicitly included in the
definition of "coastal" certain wells located in the area between the Chapman line
and the inner boundary of the territorial seas that were determined to be coastal as
a result of the 1981 decision of the U.S. Court of Appeals for the Fifth Circuit, API
v. EPA, supra.
As described in Chapter ffi of this document, these final effluent guidelines modify the (1979)
coastal definition as presented in the 1995 proposal.
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Additional related rulemakings included a series of general National Pollutant Discharge Elimination
System (NPDES) permits issued by EPA that set BPT, BCT and BAT limitations applicable to sources in the
coastal subcategory on a Best Professional Judgment (BPJ) basis under Section 402(a)(l) of the CWA. These
permits are described in Chapter ffl of this development document.
1-7
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CHAPTER II
SUMMARY OF THE FINAL REGULATIONS
1.0 INTRODUCTION
The processes and operations which comprise the coastal oil and gas extraction subcategory
(Standard Industrial Classification (SIC) Major Group 13) are regulated under 40 CFR 435, Subpart D.
The effluent limitations guidelines in existence prior to the new regulations discussed in this document
were issued on April 13, 1979 (44 FR 22069) and are based on BPT. This chapter summarizes the final
effluent limitations guidelines, new source performance standards, and pretreatment standards for this
subcategory based on BPT, BCT, BAT, BADCT.
1.1 BPT LIMITATIONS
In general, BPT represents the average of the best existing performances of well-known tech-
nologies and techniques for the control of pollutants. BPT for the coastal subcategory accomplishes the
following: (1) limits the discharge of oil and grease in produced water to a daily maximum of 72 mg/1
and a monthly average of 48 mg/1; (2) prohibits the discharge of free oil in deck drainage, drilling fluids,
drill cuttings, and well treatment fluids; (3) requires a minimum residual chlorine content of 1 mg/1 in
sanitary discharges; and (4) prohibits the discharge of floating solids in sanitary and domestic wastes.
Existing BPT effluent limitations guidelines are not being changed by this rule. A summary of the BPT
effluent limitations guidelines is presented in Table 1-1 in Chapter I Section 1.1.4.
Produced sand is the only wastestream for which BPT limits are being promulgated, as it is the
only wastestream covered by the coastal guidelines for which BPT limits have not been previously
promulgated.
1.2 SUMMARY OF THE FINAL RULE
This rule establishes regulations based on "best practicable control technology currently available"
(BPT) for one wastestream where BPT did not previously exist, "best conventional pollutant control tech-
nology" (BCT), "new source performance standards" (NSPS), "best available technology economically
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achievable" (BAT), "pretreatment standards for existing sources" (PSES), and "pretreatment standards
for new sources" (PSNS).
Drilling fluids, drill cuttings, and dewatering effluent are limited under BCT, BAT, NSPS, PSES,
and PSNS. BCT limitations are zero discharge, except for Cook Inlet, Alaska. In Cook Inlet, BCT limi-
tations prohibit discharge of free oil. For both BAT and NSPS, EPA is establishing zero discharge
limitations for drilling fluids and drill cuttings, except for Cook Inlet. In Cook Inlet, discharge limita-
tions include no discharge of free oil, no discharge of diesel oil, 1 mg/kg mercury and 3 mg/kg cadmium
limitations on the stock barite, and a toxicity limitation of 30,000 ppm in the suspended participate phase
(SPP). For both PSES and PSNS, EPA is establishing zero discharge limitations nationwide.
Produced water and treatment, workover, and completion fluids are limited under BCT, BAT,
NSPS, PSES, and PSNS. For BCT, EPA is establishing limitations on the concentration of oil and grease
in produced water and treatment, workover, and completion fluids equal to current BPT limits. The daily
maximum limitation for oil and grease is 72 mg/1 and the monthly average limitation is 48 mg/1. For
BAT and NSPS, EPA is establishing zero discharge limitations, except for Cook Inlet, Alaska. In Cook
Inlet, the daily maximum limitation for oil and grease is 42 mg/1 and the monthly average limitation is
29 mg/1. For both PSES and PSNS, EPA is establishing zero discharge limitations for all locations.
For produced sand, EPA is establishing zero discharge limitations under BPT, BCT, BAT, NSPS,
PSNS, and PSES.
Deck drainage is limited under BCT, BAT, NSPS, PSES, and PSNS. For BCT, BAT, and
NSPS, EPA is establishing discharge limitations of no free oil. For PSES and PSNS, EPA is establishing
zero discharge limitations.
Domestic waste is limited under BCT, BAT, and NSPS. For BCT, EPA is establishing no
discharge of floating solids or garbage as limitations. For BAT, EPA is establishing no discharge of
foam as the limitation. For NSPS, EPA is establishing no discharge of floating solids, foam, or garbage
as limitations. There are no PSES and PSNS for domestic waste under the coastal guidelines.
Sanitary waste is limited under BCT and NSPS. For BCT and NSPS, sanitary waste effluents
from facilities continuously manned by ten or more persons would contain a minimum residual chlorine
content of 1 mg/1, with the chlorine level maintained as close to this concentration as possible. Facilities
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continuously manned by nine or fewer persons or only intermittently manned by any number of persons
must not discharge floating solids. EPA is establishing no BAT, PSES, or PSNS regulations for sanitary
waste under the coastal guidelines.
These limitations are expected to reduce discharges of conventional pollutants by 2,780,000
pounds per year, non-conventional pollutants by 1,490,000 pounds per year, and priority toxic pollutants
by 228,000 pounds per year.
1.3 PREVENTING THE CIRCUMVENTION OF EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS
This rule includes a provision intended to prevent oil and gas facilities subject to 40 CFR Part
435 from circumventing the effluent limitations guidelines, new source performance standards and pre-
treatment standards applicable to those facilities by moving effluent from one subcategory to another sub-
category in order to discharge with less stringent requirements. When EPA establishes effluent
limitations guidelines and standards, it does so based on a determination, supported by analyses contained
in the rulemaking record, that facilities in that subcategory, among other factors also considered under
the CWA, can technologically and economically achieve the requirements of the rule. The purpose of
the rule is not accomplished if facilities move effluent from a subcategory with more stringent
requirements to a subcategory with less stringent requirements, or if facilities move-effluent from a
subcategory with less stringent requirements to a subcategory with more stringent requirements and
discharge effluent at the less stringent limitations. EPA believes that it would enhance the enforcement
of the effluent limitations guidelines and standards for the oil and gas industry to include a provision
preventing such circumvention in the regulations at 40 CFR Part 435.
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Accordingly, the rule prohibits oil and gas facilities from moving effluent from a subcategory
with more stringent requirements to a subcategory with less stringent requirements, unless that effluent
is discharged in compliance with the limitations imposed by the more stringent subcategory. For
example, facilities could not move produced water generated from the onshore subcategory of the oil and
gas industry (which is subject to zero discharge requirements) to the offshore subcategory of the oil and
gas industry and dispose of the effluent at the offshore limitations and standards. Similarly, this rule
prohibits facilities from moving produced water generated from the offshore subcategory to the coastal
or onshore subcategory and discharging the produced water at the offshore limitations. (An offshore oil
and gas facility could, however, pipe produced water to shore for treatment and return it to offshore
waters for disposal in compliance with the offshore limitations. Disposal of such produced water
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onshore, however, would be subject to zero discharge.) EPA intends that these provisions would be
applied prospectively in future NPDES permits (after the effective date of the coastal guidelines).
Limitations for the Agricultural and Wildlife Water Use Subcategory and the reserved status of the
Stripper Subcategory are not affected by these provisions.
1.4 THE EPA REGION VI COASTAL OIL AND GAS PRODUCTION NPDES GENERAL PERMITS
EPA's Region VI published final NPDES general permits regulating produced water and produced
sand discharges to coastal waters hi Louisiana and Texas (60 FR 2387, January 9, 1995). The permits
prohibit the discharge of produced water and produced sand derived from the coastal Subcategory to any
water subject to EPA jurisdiction under the Clean Water Act. Under an Administrative Order issued by
Region VI, operators are allowed until January 1, 1997 to cease discharges.
Much of the industry covered by this rulemaking is also covered by these general permits.
However, one difference between the permits and this rule is that the permits do not cover produced
water discharges derived from the Offshore Subcategory wells into the main deltaic passes of the
Mississippi River, or to the Atchafalaya River below Morgan City including Wax Lake Outlet. This rule-
making covers these discharges (see the discussion hi 1.3 above entitled "Preventing the Circumvention
of Effluent Limitations Guidelines and Standards").
Subsequent to the issuance of the coastal production general permit for Texas discharges, EPA
received individual permit applications from Texas dischargers seeking to continue discharging produced
water. Additionally, the U.S. Department of Energy has provided the State of Louisiana with comments
and analyses identifying a number of produced water discharges in Louisiana, and suggesting a change
to the Louisiana State law which requires zero discharge of produced water to open bays by January
1997. Promulgation of these coastal guidelines requiring zero discharge hi these areas would generally
preclude issuance of permits allowing discharge. Therefore, in addition to calculating the costs, economic
impacts, and pollutant removals incremental to current permit limits, EPA calculated an alternative
estimate of these factors using an "alternative baseline." This "alternative baseline" assumes that general
permits or Louisiana State law zero discharge requirements would no longer apply to Texas dischargers
seeking individual permits and Louisiana open bay dischargers. Under this alternative baseline, the
coastal guidelines would reduce discharges of conventional pollutants by 11,300,000 pounds per year,
nonconventional pollutants by 4,590,000,000 pounds per year, and toxic pollutants by 880,000 pounds
per year.
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CHAPTER III
INDUSTRY DEFINITION AND WASTESTREAMS
1.0 INTRODUCTION
This section describes the coastal subcategory by (1) regulatory definition, (2) geographic locations,
and (3) wastestreams regulated by the coastal guidelines.
2.0 REGULATORY DEFINITION
This rulemaking applies to coastal facilities included in the following SICs: 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.
The coastal subcategory of the oil and gas extraction point source category, as defined in 40 CFR
435.40, is comprised of those facilities involved hi exploration, development, and production operations
in waters of the United States landward of the inner boundary of the territorial seas (shoreline). The inner
boundary of the territorial seas is defined in Section 502(8) of the CWA as "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." This includes inland bays and wetlands. The inner boundary of the territorial seas
has been identified by EPA for areas where coastal oil and gas activity exists.1
Prior to this rulemaking, the coastal subcategory was defined as:
"(1) any body of water landward of the territorial seas as defined in 40 CFR 125. l(gg) or (2) any
wetlands adjacent to such waters." 40 CFR Section 435.41(e).
EPA has clarified the definition of the coastal subcategory in this rule. First, EPA revised the
regulation to state that the coastal subcategory consists of "any oil and gas facility located in or on a water
of the United States landward of the territorial seas." As suggested by the preamble to the 1979 guidelines
stating that the coastal definition was intended to encompass "all facilities located over waters landward
of the territorial seas, including wetlands adjacent to such waters"(44 FR 22017, April 13, 1979), EPA
intended the subcategory to cover all facilities located over waters under CWA jurisdiction, including
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adjacent wetlands. Since 1979, courts have made it clear that isolated wetlands with an interstate
commerce connection are waters of the United States subject to CWA jurisdiction. See, e.g.. Hoffinan
Homes. Tnc. v. Administrator 999 F.2d 256 (7th Cir. 1993). The revised definition makes it clear that
facilities located in or on isolated wetlands that are waters of the U.S. are considered to be coastal. This
application of the coastal definition is consistent with the Region 6 final general permit for coastal drilling
operations (58 FR 49126, 49127, September 21, 1993). Also, the revised definition no longer refers to
40 CFR 125. l(gg) which no longer exists in the CFR (Part 125 was revised at 44 FR 32948, June 7, 1979).
That regulatory provision, however, merely cited section 502(8) of the CWA which defines territorial seas
as "the belt of seas measured from the line of ordinary low water along that portion of the coast which is
in direct contact with the open sea and the line marking the seaward limit of inland waters, and extending
seaward a distance of three miles." 40 CFR 125.1(gg) (July 1, 1978). That statutory definition is still in
effect.
In addition, EPA has explicitly included in the definition of coastal certain wells located in the area
between the Chapman line and the inner boundary of the territorial seas that were determined to be coastal
as a result of decision of the U.S. Court of Appeals for the Fifth Circuit. American Petroleum Institute
v. EPA. 661 F.2d 340 (5th Cir. 1981). To reflect this fact, the definition of coastal in 40 CFR 453.41(e)
has been revised to include these wells.
This rule defines the coastal subcategory as follows:
(a) any location in or on a water of the United States landward of the inner boundary of the
territorial seas, or
(b)(l) any location landward from the inner boundary of the territorial seas and bounded on the
inland side by the line defined by the inner boundary of the territorial seas eastward of the point
defined by 89°45' West longitude and 29°46' North Latitude and continuing as follows west of
that point:
Direction to West Longitude Direction to North Latitude
West, 89°48' North, 29°50'
West, 90° 12' North, 30°06'
West, 90°20' South, 29°35'
West, 90°35' South, 29°30'
West, 90°43' South, 29°25'
West, 90°57' North, 29°32'
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Direction to West Longitude
West, 91*02'
West, 91° 14'
West, 91°27'
West, 91°33'
West, 91°46'
West, 91°50'
West, 91°56'
West, 92° 10'
West, 92°55'
West, 93°15'
West, 93°49'
West, 94°03'
West, 94° 10'
West, 95°20'
West, 95°00'
West, 95°13'
East, 95°08'
West, 95°11'
West, 95°22'
West, 95°30'
West, 95°33'
West, 95°40'
West, 96°42'
East, 96°40'
West, 96°S4'
West, 97°03'
West, 97° 15'
West, 97°40'
West, 97°46'
West, 97°51'
East, 97°46'
East, 97°30'
East, 97°26'
Direction to North Latitude
North, 29°40'
South, 29D32'
North, 29D37'
North, 29°46'
North, 29°50'
North, 29°55'
South, 29°50'
South, 29°44'
North, 29°46'
North, 30° 14'
South, 30°07'
South, 30°03'
South, 30°00'
South, 29°53'
South, 29°35'
South, 29°28'
South, 29° 15'
South, 29°08'
South, 28°56'
South, 28°55'
South, 28°49'
Soufli, 28°47'
South, 28D41'
South, 28°28'
South, 28°20'
South, 28°13'
South, 27°58'
South, 27°45'
South, 27°28'
South, 27°22'
South, 27° 14'
Soufli, 26D30'
South, 26° 11'
(2) last to 97°19* West Longitude and Southward to the U.S.-Mexican border.
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2.1 NEW SOURCE DEFINITION
EPA is applying the definition of new source promulgated in the offshore guidelines to the coastal
guidelines. The definition of "new source" was discussed at length in EPA's 1985 proposal for the
Offshore Subcategory of the Oil and Gas Extraction Point Source Category, (50 FR 34617-34619, August
26, 1985). As discussed in that 1985 proposal, provisions in the NPDES regulations define new source
(40 CFR 122.2) and establish criteria for a new source determination (40 CFR 122.29(b)). This rule
includes special definitions which are consistent with 40 CFR 122.29 and which provide that 40 CFR 122.2
and 122.29(b) shall apply "except as otherwise provided in an applicable new source performance
standard" (see 49 FR 38046, September 26, 1984).
The coastal guidelines apply to all mobile and fixed drilling (exploratory and development) and
production operations. In 1985, EPA addressed the question of which of these facilities are new sources
and which are existing sources under effluent guidelines for this point source category.
As discussed in 1985, Section 306(a)(2) of the Act defines "new source" to mean "any source, the
construction of which is commenced after publication of the proposed NSPS if such standards are
promulgated consistent with Section 306." The CWA defines "source" to mean any "facility . . . from
•which there is or may be a discharge of pollutants" and "construction" to mean "any placement, assembly,
or installation of facilities or equipment... at the premises where such equipment will be used."
The regulations implementing this provision state, in part:
"New Source means any building structure, facility, or installation from which there is or may be
a 'discharge of pollutants,' the construction of which is commenced:
(a) After promulgation of standards of performance under section 306 of the Act which are
applicable to such source, or
(b) After proposal of standards of performance in accordance with section 306 of the Act which
are applicable to such source, but only if the standards are promulgated in accordance with section 306
within 120 days of then: proposal." 40 CFR § 122.2.
"(4) Construction of a new source as defined under § 122.2 has commenced if the owner or
operator has:
(i) Begun, or caused to begin as part of a continuous on-site construction program;
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(A) Any placement assembly, or installation of facilities or equipment; or
(B) Significant site preparation work including clearing, excavation or removal of existing
buildings, structures or facilities which is necessary for the placement, assembly, or installation of new
source facilities or equipment; or
(ii) Entered into a binding contractual obligation for the purchase of facilities or equipment which
are intended to be used in its operation within a reasonable time. Options to purchase or contracts which
can be terminated or modified without substantial loss, and contracts for feasibility engineering and design
studies do not constitute a contractual obligation under the paragraph." 40 CFR § 122.29(b)(4) [emphasis
added].
In 1985, EPA proposed to define, for purposes of the offshore guidelines, "significant site prepara-
tion work" as "the process of clearing and preparing an area of the ocean floor for purposes of constructing
or placing a development or production facility on or over the site." [emphasis added]. Thus, development
and production wells would be new sources under the offshore guidelines. Further, with regard to 40 CFR
122.29(b)(4)(ii), EPA stated that although it was not "proposing a special definition of this provision
believing it should appropriately be a decision for the permit writer," EPA suggested that the definition
of new source include development or production sites even if the discharger entered into a contract for
purchase of facilities or equipment prior to publication, if no specific site was specified in the contract.
Conversely, EPA suggested that the definition of new source exclude development or production sites if
the discharger entered into a contract prior to publication and a specific site was specified in the contract.
As a consequence of the definition of "significant site preparation work," if "clearing or prepara-
tion of an area for development or production has occurred at a site prior to the publication of the NSPS,
then subsequent development and production activities at the site would not be considered a new source"
(50 PR 34618). Also, exploration activities at a site would not be considered significant site preparation
work, and therefore exploratory wells would not be new sources (50 FR 34618). The purposes of these
distinctions were to "grandfather" as an existing source, any source if "significant site preparation work
. . . evidencing an intent to establish full scale operations at a site, had been performed prior to NSPS
becoming effective" (50 FR 34618). At the same time, if only exploratory drilling had occurred prior to
NSPS becoming effective, then subsequent drilling and production wells would be considered to be new
sources.
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EPA also included a special definition for "site" in the phrase significant site preparation work used
in 40 CFR 122.2 and 40 CFR 122.29(b). "Site" is defined in 40 CFR 122.2 as "the land or water area
where any 'facility or activity' is physically located or conducted, including adjacent land used in
connection with the facility or activity." The term "water area" means the "specific geographical location
where the exploration, development, or production activity is conducted, including the water column and
ocean floor beneath such activities. Thus, if a new platform is built at or moved from a different location,
it will be considered a new source when placed at the new site where its oil and gas activities take place.
Even if the platform is placed adjacent to an existing platform, the new platform will still be considered
a 'new source,' occupying a new 'water area' and therefore a new site" (50 FR 34618, August 26, 1985).
EPA is using the same definition of "new source" in the coastal guidelines as was used in the
offshore guidelines.
As a consequence of these distinctions, exploratory facilities would always be existing sources.
Production and development facilities where significant site preparation has occurred prior to the effective
date of the coastal guidelines would also be existing sources. These same production and development
facilities, however, would become "new sources" under the regulatory definition if they move to a new
water area to commence production or development activities. The definition, however, presents a
problem because even though these facilities would be "new sources" subject to NSPS, they could not be
covered by an NPDES permit in the period immediately following the issuance of these regulations. This
is because no existing general or individual permits could have included NSPS until NSPS were promul-
gated. To resolve this problem, the rule will temporarily exclude from the definition of "new source"
those facilities that as of the effective date of the coastal guidelines would be subject to an existing general
permit pending EPA's issuance of a new source NPDES general permit. EPA believes this approach is
reasonable because when Congress enacted Section 306 of the CWA it did not specifically address mobile
activities of the sort common in this industry, as distinguished from activities at stationary facilities on land
that had not yet been constructed prior to the effective date of applicable NSPS. Moreover, EPA believes
that Congress did not intend that the promulgation of NSPS would result in stopping all oil and gas
activities which would have been authorized under existing NPDES permits as soon as the NSPS are
promulgated. EPA intends to issue as final, after opportunity for notice and comment, new source NPDES
permits as soon as possible.
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In summary, a drilling operation would be a new source if the drilling rig is drilling a development
well (not an exploratory well) in a new water area. Exploratory drilling or drilling from an existing
platform or rig that has not moved since it drilled a previously existing well would not be a new source.
For production, a new source would be a facility discharging from a new site even if the discharge is piped
to an existing facility at another site for ultimate treatment and/or disposal.
2.2 GEOGRAPHICAL LOCATIONS OF THE COASTAL INDUSTRY
As previously stated, coastal oil and gas activities are located on water bodies inland of the inner
boundary of the territorial seas. These water bodies include inland lakes, bays and sounds, as well as
saline, brackish, and freshwater wetlands. Although the definition includes inland waters of the U.S. in
all U.S. states, EPA knows of no existing coastal operations other than those in certain states bordering
the coast. Thus, although the rule applies to all areas defined as coastal, at this time the coastal industry
is located only in coastal states.
Current coastal oil and gas activity exists along the Gulf Coast states of Texas, Louisiana, Alabama
and Florida. The great majority of Gulf Coast activity resides in Texas and Louisiana. There, coastal oil
and gas operations exist in a number of topographical situations including bays, sounds, lakes, or wetlands..
Coastal oil and gas activity in Alabama is located in Mobile Bay. A small number of wells are also located
on wetlands along the west coast of Florida.
Coastal oil and gas activity in California exists in Long Beach Harbor. There, four man-made
islands have been constructed solely for the purpose of oil and gas extraction.
Roughly half of the coastal oil and gas activity exists in Alaska. Deep water platforms exist in the
northern part of Cook Inlet. In addition, operations resembling onshore activities (as opposed to deep
water platforms) are located on the tundra wetlands of Alaska's North Slope.
See Chapter IV for more details regarding the number of production wells, drilling activity, and
production volumes located in these areas.
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2.3 WASTESTREAMS REGULATED BY THE COASTAL GUIDELINES
The major wastestreams from drilling and production operations are those streams with the greatest
volumes and amounts of pollutants. The wastestreams regulated by the coastal guidelines are drilling
fluids, drill cuttings, dewatering effluent, produced water, produced sand, deck drainage, well treatment
fluids, well completion fluids, workover fluids, domestic wastes, and sanitary wastes. The following
sections present the regulatory definition for each of these wastestreams.
2.3.1 Drilling Fluids
The term "drilling fluids" refers to the circulating fluids (muds) used in the rotary drilling of wells
to clean and condition the hole, to counter balance formation pressure, and to transport drill cuttings to the
surface. A water-based drilling fluid is the conventional drilling mud in which water is the continuous
phase and the suspending medium for solids, whether or not oil is present. An oil-based drilling fluid has
diesel, mineral, or some other oil as its continuous phase with water as the dispersed phase. A synthetic
drilling fluid has as its continuous phase a synthetic-based material (such as poly(alpha)olefins, polyesters
and vegetable esters) produced by the reaction of specific purified chemical feedstock, as opposed to
physical separation processes to obtain materials from crude oil.
2.3.2 Drill Cuttings
The term "drill cuttings" refers to the particles generated by drilling into subsurface geologic
formations and carried to the surface with the drilling fluid.
2.3.3 Dewatering Effluent
The term "dewatering effluent" means wastewater from drilling fluids and drill cuttings dewatering
activities (including but not limited to reserve pits or other tanks or vessels, and chemical or mechanical
treatment occurring during the drilling solids separation/recycle/disposal process).
BAT and BCT limitations in the coastal guidelines for dewatering effluent are to be applicable
prospectively. BAT and BCT limitations in this rule are not applicable to discharges of dewatering effluent
from reserve pits which as of the effective date of the coastal guidelines no longer receive drilling fluids
and/or drill cuttings. Limitations on such discharges shall be determined by the NPDES permit issuing
authority. Should an abandoned reserve pit receive drilling wastes after the effective date of the coastal
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guidelines, then discharges of wastes from within the reserve pit would be required to comply with the
limitations of the guidelines.
2.3.4 Produced Water
The term "produced water" refers to the water (brine) brought up from the hydrocarbon-bearing
strata during the extraction of oil and gas, and can include formation water, injection water, and any
chemicals added downhole or during the oil/water separation process.
2.3.5 Produced Sand
The term "produced sand" refers to slurried particles used in hydraulic fracturing, the accumulated
formation sands and scale particles generated during production. Produced sand also includes desander
discharge from the produced water wastestream and blowdown of the water phase from the produced water
treating system.
2.3.6 Well Treatment Fluids
The term "well treatment" fluids refers to any fluid used to restore or improve productivity by
chemically or physically altering hydrocarbon-bearing strata after a well has been drilled.
2.3.7 Well Completion Fluids
The term "well completion fluids" means salt solutions, weighted brines, polymers, and various
additives used to prevent damage to the well bore during operations which prepare the drilled well for
hydrocarbon production.
2.3.8 Workover Fluids
The term "workover fluids" means salt solutions, weighted brines, polymers, or other specialty
additives used in a producing well to allow safe repair and maintenance or abandonment procedures.
2.3.9 Deck Drainage
The term "deck drainage" refers to any waste resulting from deck washings, spillage, rainwater,
and runoff from gutters and drains including drip pans and work areas within facilities subject to this
subpart. Within the definition of deck drainage for the purpose of this subpart, the term rainwater for those
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facilities located on land is limited to that precipitation runoff that reasonably has the potential to come into
contact with process wastewaters. Runoff not included in the deck drainage definition would be subject
to control as storm water under 40 CFR 122.26. For structures located over water, all runoff is included
in the deck drainage definition.
2.3.10 Domestic Waste
The term "domestic waste" refers to materials discharged from sinks, showers, laundries, safety
showers, eyewash stations, and galleys located within facilities subject to this subpart.
2.3.11 Sanitary Waste
The term "sanitary waste: refers to human body waste discharged from toilets and urinals located
within facilities subject to this subpart.
2.4 MINOR WASTES
In addition to those specific wastes for which effluent limitations are being promulgated, coastal
exploration and production facilities discharge other wastewaters. These wastes were investigated but are
considered to be minor and, more appropriately controlled by NPDES permit limitations. Therefore, no
controls for these wastes are proposed by this rule. These wastes are organized into the following 14
categories:
• Blowout Preventer (BOP) Fluid: hydraulic fluid used in blowout preventer stacks during well
drilling.
• Desalinization Unit Discharge: wastewater associated with the process of creating fresh water
from seawater.
• Fire Control System Test Water: sea water that is sometimes treated with biocide, used as test
water for the fire control system on platforms and other facilities.
• Non-Contact Cooling Water: sea water that is sometimes treated with biocide, used for non-
contact, once-through cooling of crude oil, produced water, power generators, and various other
pieces of machinery.
• Ballast and Storage Displacement Water: tanker or platform ballast water, either local sea
water or fresh water from the location where ballast was pumped into the vessel; may be
contaminated with crude oil or platform oily slop water.
• Bilge Water: sea water that becomes contaminated with oil and grease and solids such as rust,
when it collects at low points in the bilges.
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• Boiler Slowdown: discharges from boilers necessary to minimize solids build-up in the boilers.
• Test Fluids: discharges that occur if hydrocarbons are located during exploratory drilling and
tested for formation pressure and content.
• Diatomaceous Earth Filter Media: used to filter sea water or other authorized completion fluids
and then washed from the filtration unit.
• Bulk Transfer Operations Wastes: bulk materials such as barite or cement that may be
discharged during transfer operations.
• Painting Operations Wastes: discharges of sandblast sand, paint chips, and paint spay from
painting operations.
• Uncontaminated Fresh Water: from wastes such as air conditioning condensate or potable water
used during transfer or washing operations.
• Waterflooding Discharges: discharges associated with the treatment of sea water prior to its
injection into a hydrocarbon-bearing formation to improve the flow of hydrocarbons from
production wells. These discharges include the strainer and filter backwash water, and treated
water in excess of that required for injection.
• Laboratory Wastes: material used for sample analysis and the material being analyzed.
• Natural Gas Glycol Dehydration Wastes: spent triethylene glycol or other desiccants used in
the processing of natural gas.
3.0 CURRENT NPDES PERMIT STATUS
3.1 NPDES PERMITS
EPA has regulated discharges from coastal oil and gas operations in the Gulf of Mexico, California,
and Alaska by general and individual National Pollutant Discharge Elimination System (NPDES) permits,
issued under Section 402 of the CWA, based on BPT, State Water Quality Standards, and on Best
Professional Judgment (BPJ) of BCT and BAT levels of control.
EPA's Region 6 has developed general NPDES permits for each phase of oil and gas operations
(drilling and production). The drilling permit was published on September 21, 1993 (58 FR 49126).
General permits regulating produced water and produced sand discharges to coastal waters in Louisiana
and Texas were published on January 9, 1995 (60 FR 2387).
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The existing general NPDES permit for oil and gas operations in the Upper Cook Inlet was pub-
lished by EPA Region 10 on October 3,1986 (51 PR 35460). Although expired, conditions of this general
permit are still fully effective and enforceable until the permit is reissued. Region 10 published a new draft
permit regulating discharges in Cook Inlet on September 20, 1995 (60 FR 48796). In addition to the
general permit, the Region issued an individual permit regulating discharges from exploratory drilling
operations hi Upper Cook Inlet in May 1993.
The State of Alabama has been authorized to administer the NPDES program and has issued a final
NPDES general permit covering facilities in State waters, including offshore and coastal facilities
(including Mobile Bay) (Permit #ALG280000, May 25,1994). This permit specifically prohibits the dis-
charge of drilling fluids, drill cuttings, and produced water. The permit also does not allow the discharge
of produced sands or treatment, workover and completion fluids.
In addition to technology pollutant removal performance, regional permit requirements are based
on other factors, including water quality criteria. Table ni-1 presents a summary of the requirements in
these permits.
3.2 STATE REQUIREMENTS
Louisiana
Two state agencies regulate oil and gas exploration and production (E&P) waste management
activities in Louisiana: the Louisiana Department of Natural Resources, Office of Conservation
(LDNR/OC) and the Louisiana Department of Environmental Quality (LDEQ). The LDNR has jurisdiction
over most onsite and offsite E&P waste disposal activities, and implements the state's Underground
Injection Control (UIC) program. The LDEQ has jurisdiction over surface discharge, and has authority
to issue NPDES permits. LDEQ also regulates NORM-contaminated waste disposal and air emissions from
waste disposal facilities.
Two state regulations govern most E&P waste management activities in Louisiana: Statewide
Order 29-B2 and Louisiana Administrative Code (LAC) 33, Part IX, Section 70S.3 Statewide Order 29-B
covers the folio whig activities:
• Onsite land treatment and burial of non-hazardous oilfield wastes (NOW), excluding
drilling fluids, produced water, and completion and workover fluids;
m-12
-------
• Onsite subsurface injection of produced water, drilling and workover waste fluids;
• Offsite storage, treatment, and disposal of NOW, including commercial land treatment and
disposal well facilities.
LAC 33, Part IX, Section 708(c)(3) includes, in part, the following requirements:
• Surface discharges of drill cuttings, drilling fluids, and storm water runoff contaminated
with these wastes, including the following requirements:
There shall be no discharge of oil-based drilling fluids,
There shall be no batch or bulk discharge of drilling fluids into water bodies inland
of the territorial seas,
In fresh and intermediate marsh areas, only drill cuttings generated onsite and
their adhering native mud drilling fluids may be discharged,
There shall be no discharge of drill cuttings generated in association with the use
of oil-based drilling fluids, invert emulsion drilling fluids, or drilling fluids that
contain diesel oil, waste engine oil, cooling oil, gear oil, or other oil-based
lubricants;
LAC 33, Part IX, Section 708(c)(5) covers the following activities:
• Surface discharges of treated wastewater from drilling fluid reserve pits, abandoned or
inactive production pits, ring levee borrow ditches, shale barges, and drilling fluid
dewatering systems;
LAC 33, Part IX, Section 708(c)(2) includes, in part, the following requirements:
• Freshwater Areas
The discharge of produced water directly onto any vegetated area, soil, or
intermittently exposed sediment surface is prohibited.
There shall be no discharge of produced water to lakes, rivers, streams, bayous,
canals, or other surface waters of the state in areas regionally characterized as
upland.
There shall be no discharge of produced water to freshwater swamp or freshwater
marsh areas or to natural or manmade water bodies bounded by freshwater swamp
or freshwater marsh vegetation unless the discharge has been specifically
authorized in accordance with an approved schedule for discharge termination, or
the discharge has been authorized by a valid LWDPS permit reflecting a discharge
directed to a major deltaic pass of the Mississippi River or to the Atchafalaya
River, including Wax Lake Outlet, below Morgan City.
in-i3
-------
• Intermediate, Brackish, and Saline Water Areas Inland of the Territorial Seas
The discharge of produced water directly onto any vegetated area, soil, or
intermittently exposed sediment surface is prohibited.
There shall be no discharge of produced water to natural or man-made water
bodies located in intermediate, brackish, or saline marsh areas after January 1,
1995, unless the discharge or discharges have been authorized in an approved
schedule for elimination or effluent limitation compliance.
Operators discharging to the open waters and at least one mile from any shoreline
in Chandeleur Sound, Breton Sound, Barataria Bay, Caminada Bay, Timbalier
Bay, Terrebonne Bay, East Cote Blanche Bay, West Cote Blanche Bay, or
Vermilion Bay from production originating in these areas will have until two years
after the effective date of these regulations or one year after completion of the
U.S. Department of Energy's (DOE) study concerning Louisiana coastal bays,
whichever comes first, to show on a case-by-case basis that their particular
discharge should be exempt from these regulations, if the DOE study, after
scientific peer review, shows minimal acceptable environmental impacts.
Under the requirements of LAC 33, Part IX, Section 708(c)(2)b, requests for an extension of the
compliance period beyond the January 1, 1995, deadline will be considered by the state if submitted with
the original compliance schedule and if the following conditions are met:
• The operator establishes that surface discharge is the only immediately available and
economically feasible alternative, that continued discharge does not represent gross
potential for unacceptable environmental degradation, and that the produced water
discharge termination schedule is limited in term to the period necessary to provide an
alternate wastehandling method.
• The proposed extension would not extend the date of discharge termination or effluent
limitation compliance beyond January 1, 1997.
Texas
The Railroad Commission of Texas (RRC), Oil and Gas Division, has regulated oil and gas field
activities since 1917. The RRC oversees subsurface injection of produced water, as well as other oil and
gas field wastes, through the state's UIC program. Requirements for the construction, use, and closure
of pits is regulated via Statewide Rule 8.4 The RRC will also oversee the state NPDES program, as
delineated under a draft of Statewide Rule 77, although EPA has not yet authorized Texas to run the
NPDES program. The RRC is also seeking primacy for the RCRA Subtitle C program for the management
of hazardous oil and gas wastes.
m-i4
-------
Reserve pits, as well as many other types of pits, are authorized by Statewide Rule 8 and therefore
do not require a permit. Only wastes specified in the Rule may be placed in these pits. Wastes authorized
for placement in reserve and mud circulation pits are drilling fluids, cuttings, rig wash, drill stem test
fluids, and blowout preventer test fluids. Rule 8 also lists pits that require permits, including those (other
than reserve and mud circulation pits) used to store or dispose of drilling fluid. Pits used to store oil are
specifically prohibited.
Two methods of landfarming oilfield wastes for disposal are authorized by the RRC: landspreading
and land treatment. Landspreading is authorized by Rule 8 for the disposal of low-chloride (<_ 3,000 mg/1)
water based drilling fluids, drill cuttings, sands and silts associated with low-chloride water based drilling
fluid, and rig wash. Land treatment involves adding nutrients or microbes to enhance degradation of oily
Exploration and Production (E&P) wastes. This disposal method requires a permit and covers wastes such
as oil based drilling fluids, cuttings associated with oil based drilling fluids, basic sediment, pit sludges,
produced sand, and soil contaminated with produced water or oil. Drilling wastes that may be buried
onsite under Rule B without a permit include:
• dewatered water base drilling fluid
• drill cuttings
• sands and silts associated with water base drilling fluid
• cuttings from oil base drilling fluid (but not oil base drilling fluid)
• solids from dewatered rig wash
• inert wastes
• basic sediment
• dewatered workover and completion solids.
A permit is required to bury any waste not specifically authorized by Rule 8.
Injection of drilling wastes to a non-productive formation is allowed by permit. Statewide Rule
9 covers permits for Class n injection wells under the Texas UIC program. All non-hazardous oil and gas
wastes that are injectable are allowed to be injected to non-producing formations. Annular disposal of
drilling waste also requires a permit, is not part of the state UIC program, and is limited to the drilling fluid
used to drill the well. The type of drilling fluid is not restricted, and no waste analyses are required prior
to disposal.5
ffl-15
-------
Discharges of saline produced water to tidally influenced waters, and discharges of low-chloride
produced water, gas plant effluent, or hydrostatic test water to the land surface or to surface waters are
allowed by permit (under Rule 8(d)). Because Texas has not been authorized to administer the NPDES
program, operators must apply for both a state and CWA/NPDES permit to discharge to state waters. As
part of the state permit application process, produced water must be analyzed for 33 parameters including
total organic compounds, benzene, naphthalene, oil and grease, metals, and chlorides. Discharges to
tidally influenced waters are limited to 25 mg/1 oil and grease.5
Produced water may be injected for disposal (Rule 9) or for enhanced recovery (Rule 46).
Requirements include well construction specifications designed to protect usable water sources (e.g., casing
depths, use of tubing and packer), and mechanical integrity tests are required at least every five years.
All commercial and centralized disposal facilities that accept oilfield waste must be permitted. The
majority of E&P wastes disposed at commercial and centralized facilities are produced water and drilling
fluids, which are mostly disposed in Class n injection wells.5
California
There are no discharges of produced water in the coastal subcategory off California. All produced
water in this area is currently injected for use in waterflood operations to enhance hydrocarbon recovery.
Regulations that would be applicable to discharges from coastal oil and gas facilities in California are
included in the California State Water Resources Control Board's "Water Quality Control Plan for Ocean
Waters of California." This "Plan" requires effluent limitations be met for oil and grease of 25 mg/1 (30-
day average), 75 mg/1 (maximum at any time), settleable solids of 1 mg/1 (30-day average), 3 mg/1
(Maximum at any time), turbidity 75 NTU (30-day average), and pH of 6-9, for all discharges from
POTWs and industrial point sources.6 Total suspended solids are regulated by requiring that discharges
shall, as a 30 day average, remove 75% of suspended solids from the wastestreams before discharging.
In addition, discharge effluent limitations are specified for acute toxicity, metals, phenolic compounds and
radioactivity.
Florida
There are no discharges of produced water in coastal waters of Florida. Florida's coastal oil and
gas wastes are primarily regulated by Florida's Department of Environmental Protection (DEP).
Regulations issued by the DEP prohibit the discharge of oil and gas wastestreams.7
ra-i6
-------
TABLE in-1
NPDES PERMIT REQUIREMENTS"
4T' '<"> '-'
:'-' i '"\ ,.':-'- "V
s *f? .; '•. 4 o
^ \t^ '' i£ ~~
?i'/'t Mi tfot C™ ,v 1,
'' strewn'' •
'v <•<. •• * •• > -s
*'/<;•> ; ; ; X
Produced
Water
Produced
Sand
\- > - '» *,\ ?•' « < it o V4 - * > • '' -
••'at •'"-, <",";'- , 't.i""i"'i'-/ ,f"iv
~^~, V ' S *t' * \* ^ ?••<*-*• -^ ^ ^ % ' v^-- * '<_'
-, f <: ' t ,' ! "
''^^ttirtw'*1rt^vWlrt&i?A^tvi>fli«mV %
4^KfigIOlJ^J^y •'£/xpJ0^atlDI|/^BJ/l|H|- ^
^ i •* v^ $ r * (1^93} 'v ' ^ ^ ^^ *% '^
?CC \ ' ' ; * ^ * * '•''^ ^,,"^ ^ I
*• ! 5 !*^ ' 1 " ' - * f ,' I * !% t* ? " '.
Not Applicable
Not Applicable
l&HT'j&6tmtME!W
•» -'%•&$ ... ,,V^ , tf M*.. .„ t, jt, *, f v <,••'<• :'"w
^ ^ •" ^^ '**"* ;{^ '* ' ^ '""*' ' * *' % *
''•.* /"• '''' ^ %. '° '""••*" J ^ ' ' -S ? ^ ^ ^ " '' ^ '•• •*•
J ^ ^ lri?s(^ fiinlr fii1fp^'P^'i'i¥iif'Y'l''Jft'!W^ v*
, ;.- ^ W^wJLv^V'UUtt *|l>vjt * (JWIHI,\JIJ'7«3/. V /
, <•* " '- ^ ^ ^'* -- ^ ' *, <-•--•.!• ? -% _, <../.V -^ •- <-
'**'?*'? :* '* , "!?-' 'N V *-, , '*-"
1) Flow rate: monitor daily
2) Oil and Grease:
Phillips A/Tyonek: 20 mg/1 daily
max; 15 mg/1 monthly avg
Other facilities: 42/29 mg/1
3) pH: 6-9
4) Metals: (b)
Cu: 58-244 daily max;
29-121 monthly avg
As: 843-1780 daily max; 420-885
monthly avg
Zn: 7980-16,500 daily max; 3980-
8240 monthly avg
5) Total Aromatic Hydrocarbons
(TAH):(b)
170-182,000 daily max
85-90,500 monthly avg
6) Total Aqueous Hydrocarbons
(TaqH):(b)
255-272,000 daily max
127-136,000 monthly avg
7) Whole Effluent Toxicity:(b)
10-182 TUc daily max
7-124 TUc monthly avg
8) Metals: measure monthly for 1 year
No Discharge
••-,-i~ *..^W<
, >„ >,, ,,4 'fj- , ,v ,,:,^
^ * '"* , ' K
1^div'Ji& fc l^k»fcli*''' if
JK€^lul|*C| ^J^llllljg
^ Pefttiii (11^93y *
* ., ,. t. •:• * ,. ,, r^ ^
"J".' '?' ** "'{*•
Covered in
Production Permit
Not Applicable
^ f y -. j *•
', , ",, - , ,%.
^ W ^ *'' ' ^ *
•~t £».£ ^,w ^
^j^OpUCUOll %
•-Pei'iiiif?^
" ' ^OQ^' ' ^
• •, W-*",V « i
No
Discharge
No
Discharge
>l ',y--\^,''v
('• ,'., -',-., ,»"
;,'„' I''-'"'*
fi. k^gl^ijAl '
J/.,,^Vl3i)wI>^: Jj.
Pertnlt- f 1-9941
' * ' ^ ^ ^ -. & s •*
' *"s\* V,
No Discharge
No Discharge
a
-------
TABLE m-1 (Continued)
NPDES PERMIT REQUIREMENTS1
REGIONAL PERMIT REQUIREMENTS
Waste-
stream
Drilling
Fluids and
Cuttings
"Dewatering
Effluent"
Region 10 (CH986BPT
Permit)
1) Toxicity: Discharge only
approved generic muds
2) No free oil— static sheen
3) No discharge oil-based muds
4) 10 percent oil content for
cuttings
5) Nodieseloil
6) 1/3 mg/kg Hg/Cd in dry
barite
7) Flow rate:
>40 m = 1000 bbl/hr
> 20^10 m = 750 bbl/hr
>5-20m = 500 bbl/hr
<5m = No discharge
Not separately regulated
Region 10 Exploration Permit
(1993) , -
1) Flow rate = 750 bbl/hr
2) Use authorized muds only
3) Toxicily: 30,000 ppm in SPP
4) No free oil
5) No discharge of oil-based
fluids
6) 5 percent (wt) oil content in
cuttings
7) No discharge of diesel oil
8) 1 mg/kg Kg and 3 mg/kg Cd
in stock barite
Not separately regulated
Draft Cook Inlet Permit |1995)
1) Flow Rate (Water Depth)
>40m = 1,000 bbl/hr
>20-40m = 780 bbl/hr
5-20m = 500 bbl/hr
<5m =no discharge
2) Total Volume: monitor daily
3) Mud Plan: prior certification
4) Toxicity: 30,000 ppm SPP minimum
5) Free oil: no discharge
6) Oil-based fluids: no discharge
7) Oil content: monitor daily
Not separately regulated
Region 6 Drilling
Permit (1993)
No Discharge
1)
2) 50mg/lTSS
3) 5125 mg/1
COD
4) pH = 6-9
5) 500 mg/1
chlorides
6) 0.5 mg/1 total
Cr
7) 5.0 mg/1 Zn
8) Monitor
Volume
Region 6
production
Permit
Not
Applicable
Not
Applicable
Alabama
Permit (1994)
No Discharge
Not separately
regulated
-------
TABLE m-1 (Continued)
NPDES PERMIT REQUIREMENTS"
" •<••'»"',•""''>/:'"''''/, ~""'', ' '"]'" : ''V "B2,? ' ' *
-' Region WCCSWrBW-'*
<, s - » ,Permit) •
1) No free oil (Static Sheen)
2) No oil-based fluids
3) pH = 6-9
4) Oil and grease limits apply to
combined discharge of any
TWC commingled with pro-
duced water
1) No free oil (no visible sheen)
2) No floating solids
3) Monitor flow rate
1) No free oil (visual sheen)
2) Monitor flow rate (mo. avg.)
V * ^ ^ -f > '
Region ft E^l&ifation;Pei?nit-
^ <<• •; (1993) •;';' -• -
1) No discharge of free oil or
oil-based fluids
2) Monitor frequency of dis-
charge and volume
3) pH = 6.5-8.5
4) Oil & grease = 72 daily max.
& 48 mo. avg.
1) Monitor flow rate
2) No free oil (no visible sheen)
3) No floating solids
4) No visible foam
1) Monitor flow rale (mo. avg.)
2) No free oil (visual sheen)
J ' .Draft £ook W$ fermit (B% *
* *~ *'•-,''> ** ^ ,
„ <*;•.- , , , ,^\
1) Discharge Frequency: report type and
number of discharges
2) Flow Rate: monitor daily
3) Oil-based fluids: no discharge
4) Free oil: no free oil
5) Oil and grease: 42 mg/l daily max; 29
mg/1 monthly avg
6) pH: 6.5-8.5
7) Metals: measure once per discharge
1) Flow rate: measure monthly
2) Floating solids: no discharge
3) Foam: no discharge
1) Flow rate: measure monthly
2) Free oil: no discharge
3) Whole effluent toxicity: measure twice
per year
"Region ,6 Drilling
>«rnUa993)
Fresh Water: No
discharge
Saline Water. No
toxics, No free oil
(visual sheen),
pH = 6-9
No discharge of
solids ("garbage")
1) No free oil
(visual sheen)
2) Monitor
volume
Region 6
Production
; Permit •
0995)'
Not
Applicable
Not
Applicable
Not
Applicable
' t # ' •.
- Alabama
Permit (1994)
No Discharge
See note
below(c)
1) Monitor
daily flow
2) No free oil
(visual
sheen)
-------
TABLE III-l (Continued)
NPDES PERMIT REQUIREMENTS"
REGIONAL PERMIT REQUIREMENTS
Waste- ^
. stream
"f, ,
Sanitary
Wastes
,
Regton4 > > * <*
1) No floating solids
2) Total residual chlorine: as
close as possible to, but no
less than, l.Omg/1
3) BOD&SS(d)
24 hr = 60 mg/I
7 day = 45 mg/I
30 day = 30 mg/I
, Region 10 Exploration Permit
' A (1993)' . *
>' { ?! S-,
^ •, I*-'' s-',.. ? y
1) No free oil (no visible sheen)
2) No floating solids
3) No visible foam
4) Total residual chlorine: as
close as possible to, but no
less than, 1 mg/I
5) BOD:
30 day: 30 mg/1
24 hr: 60 mg/1
6) TSS:
30 day: TSS intake + 30 mg/I
24 hr: TSS intake + 60 mg/1
Draft Cook Wet Permit (19?s)
•? ~ ' ^ ^% *. > ^ ?
*~™ ^ ' \ S -. s, i .. "
1) Flow rate: measure monthly
2) Floating solids: no discharge
3) Total residual chlorine: as close as
possible, but no less than 1 mg/I
4) BOD:
60 mg/1 daily max
45 mg/1 weekly avg
30 mg/1 monthly avg
5) SS:
SSintake + 60 mg/1
SSintake + 45 mg/1
SSintake + 30 mg/1
6) MSDs (FC, SS, TRC): Measure twice
per month
Region 6 Drilling
Permit (1993)
, ,.'£'•'
^^ - ^,f
1) No floating
solids
2) BOD: 45 mg/1
3) TSS: 45 mg/l
4) Fecal coli-
forms: 200/
100 mis
5) Monitor flow
Region 6
Production
Permit
om .-
Not
Applicable
Alabama
Permit (B94)
a* < ** , « >
See note
below(c)
* For a complete presentation of the effluent limitations and their basis in the permits see the following: Region 10 Final Permit for Cook Inlet (51 FR 35460; 10/3/86);
Region 10 Exploration Permit (No. AK-005205-1; 5/24/93); Region 10 Draft Permit for Cook Inlet (60 FR 48796, 9/20/95); Region 6 Final General Permit for Drilling
Operations (58 FR 49126; 9/21/93); Region 6 Final General Permits for Production Operations (60 FR 2387; 1/9/95); Alabama general permit (No. ALG280000; 5/25/94).
b Limitations are facility-specific; only range is presented.
c NOTE: The Alabama permit includes limitations for sanitary and domestic wastes that vary with the type of facility and whether the wastes are mixed.
d Limits apply only to discharges to state waters and separately for BOD and SS.
-------
4.0 REFERENCES
1. Avanti, "Delineation of the Seaward Boundary of the Coastal Subcategory of the Oil & Gas
Extraction Industry," May 3, 1993.
2. Louisiana Administrative Code, Volume 17, Title 43, Natural Resources, Part XIX. Office of
Conservation - General Operations, Subpart 1. Statewide Order No. 29-B, 1990.
3. Smith, Michael, U.S. Court of Appeals (5th Circuit), facsimile transmitting Louisiana
Administrative Code (LAC) 33, Part K, Section 708 (Bureau of National Affairs, Inc., 1996),
September 11, 1996.
4. Railroad Commission of Texas, Water Protection Manual, Appendix A; Summary of Statewide
Rule 8, Statewide Rule 8, and Memorandum of Understanding, May 1992.
5. Interstate Oil and Gas Compact Commission, IOGCC/EPA State Review of Oil and Gas
Exploration & Production Waste Management Regulatory Programs, Texas State Review, April
1993.
6. Wiedeman, A., Memorandum to file regarding "Coastal Oil and Gas Activity in CA, AL, MS, and
FL," September 6, 1994.
7. Rules of the State of Florida Department of Environmental Protection, Florida Geological Survey,
Oil and Gas Section, Conservation of Oil and Gas Chapters 16C-25 through 16C-30, Florida
Administrative Code, Chapter 16C-28, Section 28.003.
-------
-------
CHAPTER IV
INDUSTRY DESCRIPTION
1.0 INTRODUCTION
This section describes the major processes associated with the oil and gas extraction and production
industry located in the coastal regions of the United States, and presents the current and future production
and drilling activities for this industry.
2.0 DRILLING ACTIVITIES
There are two types of operations associated with drilling for oil and gas: exploratory and
development. Exploratory drilling includes those operations that involve the drilling of wells to determine
potential hydrocarbon reserves. Development drilling includes those operations that involve the drilling
of production wells, once a hydrocarbon reserve has been discovered and delineated. Although the rigs
used in exploratory and development drilling sometimes differ, the drilling process is generally the same
for both types of drilling operations. Drilling in coastal areas occurs on land (or wetland areas that are dry
during certain parts of the year) as well as over water or wetlands. As described later in this section, the
drill site location (over water or land) as well as water depth are influential when determining the type of
drilling rig used.
2.1 EXPLORATORY DRILLING
Exploration for hydrocarbon-bearing strata consists of several indirect and direct methods. Indirect
methods, such as geological and geophysical surveys, identify the physical and chemical properties of
formations through surface instrumentation. Geological surveys determine subsurface stratigraphy to
identify rock formations that are typically associated with hydrocarbon bearing formations. Geophysical
surveys establish the depth and nature of subsurface rock formations and identify underground conditions
favorable to oil and gas deposits. There are three types of geophysical surveys: magnetic, gravity, and
seismic. These surveys are conducted from the surface with equipment specially designed for this purpose.
Direct exploratory drilling, however, is the only method to confirm the presence of hydrocarbons and to
IV-1
-------
determine the quantity of hydrocarbons after the indirect methods have indicated hydrocarbon potential.
Exploratory wells are also referred to as "wildcats."
Shallow exploratory wells are usually drilled in the initial phases of exploration to discover the
presence of oil and gas reservoirs. Deep exploratory wells are usually drilled to establish the extent of the
oil or gas reservoirs, once they have been discovered. These types of exploration activities are usually of
short duration, involve a small number of wells, and are conducted from mobile drilling rigs.
2.1.1 Drilling Rigs
Mobile drilling rigs are used to drill exploratory wells because they can be easily moved from one
drilling location to another. These units are self contained and include all equipment necessary to conduct
the drilling operation plus living quarters for the crew. The two basic types of mobile drilling units for
drilling in water are bottom-supported units and floating units. Bottom-supported units include
submersibles and jackups. Floating units include inland barge rigs, drill ships, ship-shaped barges, and
semisubmersibles.J
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. In
shallow and inland waters, these units may be surrounded by barges to store and to transport materials and
wastes to and from the site.
Jackups are barge-mounted drilling rigs designed with extendable legs. During transport, the
extendable legs are retracted. At the drill site, the legs are extended to the bottom. 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. Jackup rigs are used
in the Cook Inlet of Alaska for exploratory drilling.
Land-based drilling rigs are also used in the coastal region of the Gulf of Mexico and on the North
Slope. Land-based drilling rigs are different from water-based drilling rigs in that they are disassembled
and transported from location to location by trucks. Land-based drilling rigs also take up more surface area
than water-based drilling rigs. Land-based drilling rigs are usually surrounded by an earthen levee with
IV-2
-------
a ditch to capture any runoff from the site. Materials and wastes are transported to and from the drill site
by truck. Onsite living quarters are usually only provided for the supervisory personnel.
2.1.2 Formation Evaluation
The operator is constantly evaluating the characteristics of the formation during the drilling
process. The evaluation involves measuring properties of the reservoir rock and obtaining samples of the
rock and 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.1
2.2 DEVELOPMENT DRILLING
Development of the oil and gas reservoirs involves drilling of wells into the reservoirs to initiate
hydrocarbon extraction, increase production or replace wells that are not producing on existing production
sites. Development wells tend to be smaller in diameter than exploratory wells because, since the
geological and geophysical properties of the producing formation are known, drilling difficulties can be
anticipated and the number of workovers during drilling minimized. In the Gulf of Mexico coastal region,
development wells average 8,500 feet in depth. In Alaska, development wells average 12,000 feet in
depth.2
Different types of drilling rigs are used during development drilling, depending on the location of
the producing reservoir. In the Gulf of Mexico region, mobile drilling units are used for development
drilling as well as exploratory drilling. In the Cook Inlet region of Alaska, the two most commonly used
types of drilling rigs are the platform rig and the mobile drilling units. Development wells are often drilled
from fixed platforms in Cook Inlet because once the exploratory drilling has confirmed the existence of
extractable quantities of hydrocarbons, a platform is constructed at that site for drilling and production
operations. On the North Slope, development drilling is done from both dedicated and mobile drilling rigs.
The drilling rig and all the associated equipment are housed and insulated to protect them from the harsh
weather conditions.
To extract hydrocarbons from the reservoir effectively, several wells may be drilled into different
parts of the formation. A special drilling technique, termed "directional drilling", has been developed to
rv-s
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penetrate different portions of a reservoir from a fixed location directly below the rig. Directional drilling
involves drilling the top part of the well straight and then directing the wellbore to the desired location in
nonvertical directions. This requires special drilling tools and devices that measure the direction and angle
of the hole. Directional drilling also requires the use of special drilling fluids that prevent temperature
build up and stuck pipe incidents due to the increased stress on the drill bit and drill string. Directional
drilling is commonly practiced in the Cook Inlet and on the North Slope. Although not commonly
practiced in the Gulf of Mexico, some operators employ this drilling method to minimize environmental
impacts (e. g., in protected wetlands) and to speed up the well permitting process by using existing drilling
pads.3
Horizontal drilling is a specialized directional drilling technique that maximizes the length of
penetration in the pay zone (hydrocarbon reservoir) by horizontally drilling through the pay zone, thus
maximizing the fluid extraction from a single production string.4 Horizontal drilling is also referred to as
drilling under balance as there is no pressure equilibrium between the formation and the bore hole as in
conventional drilling. The formation pressure is greater than the bore hole pressure (a blow out condition)
but special surface equipment controls the down hole pressure differentials preventing a blow out.
Horizontal drilling is occasionally practiced in coastal environments when tib.e geometry of the
reservoir makes horizontal drilling the most economical method of extracting the hydrocarbon reserves.4
It should be noted that horizontal drilling is not practiced as a means of minimizing impacts to the surface
environment. Also, horizontal drilling is associated with greater volumes of waste than vertical drilling
because the length of the borehole is greater and the drilling time is longer.
2.2.1 Well Drilling
The process of drilling 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 the drilling rig
to a few hundred feet below the surface. The conductor casing, which is approximately two feet hi
diameter, is either hammered, jetted, or placed into the ground depending on tib.e composition of the
ground. If the composition of tibie ground is soft, the conductor casing can be hammered into place or
lowered into a hole created by a high-pressure jet of water. In areas where the ground is composed of
harder material, the casing is placed in a hole created by a large-diameter rotating drill bit.
IV-4
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Rotary drilling is the drilling process used to drill the well. The rotary drilling process consists
of 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. Cement is pumped into the space between the casing and the hole wall to secure the
casing in place. Each new casing string must be smaller in diameter than the previous string to allow for
installation. 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, 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, where cuttings, silt, sand, and any gases are removed before returning the fluid
down-hole to the bit. The cuttings, sand, and silt are separated from the drilling fluid by a solids separation
process which typically includes a shaleshaker, desilter, and desander and sometimes centrifuges.
Figure IV-1 presents a schematic flow diagram of the fluid circulation system. Some of the drilling fluid
remains with the cuttings after solids separation.5'6
Drilling fluids function to cool and lubricate the bit, stabilize the walls of the borehole, and
maintain equilibrium between the borehole and the formation pressure. The drilling fluid must exert a
higher pressure in the wellbore than exists in the surrounding formation, to prevent formation fluids (water,
oil, and gas) from entering the wellbore which will otherwise migrate from the formation into the wellbore,
and potentially create a blowout. A blowout occurs when drilling fluids are ejected from the well by
subsurface pressure and the well flows uncontrolled. To prevent well blowouts, high pressure safety valves
called blowout preventers (BOPs) are attached at the top of the well.
Since the formation pressure varies at different depths, the density of the drilling fluid must be
constantly monitored and adjusted to the downhole conditions during each phase of the drilling project.
IV-5
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Fluids + Cuttings
Cuttings
(Waste)
t
t
t
New Make-up
iUing Fluids
Fluids*
Sepa
Sys
>
Cuttings
ration __
tern
I
Recirt
-*• Fl
' \
;ulated
aid
r
Fluid Slowdown
(Waste)
To Disposal
Figure IV-1
Typical Drilling Fluids Circulation System
IV-6
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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. More
detailed discussion on solids control systems can be found in Chapter VII.
Operators control the solids content of the drilling fluid by adding fresh fluid to the circulating fluid
system to reduce the percentage of solids and to rebuild the desired Theological 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, greater quantities of fluid additives are required to formulate the
replacement fluid. Both of these add expenses to the drilling project.
Most drilling fluid fluids are water-based, although oil-based systems are used for specialized
drilling projects and more recently synthetic based drilling fluid systems are becoming more popular. In
the 1970's, drilling fluids were mostly oil-based. The trend away from oil-based fluids is due to: 1) the
BPT limitations which prohibit the discharge of drilling wastes if "free oil" is detected; and 2)
advancements in water-based fluids technology. In the past, only oil-based fluids could achieve the
temperature stability and lubricity properties required by special drilling conditions such as directional and
deep well drilling. However, advancements in drilling fluid technology have enabled operators to
formulate water-based fluids with similar properties to that of oil-based fluids through the use of small
quantities of oil and/or synthetic additives. Small quantities of oil and/or synthetic additives are used to
enhance the lubricity of a water-based fluid system and to aid in freeing stuck drill pipe. In the past, diesel
oil was solely used to enhance lubricity and to free stuck pipe because of its properties and its availability
at a drilling she. Mineral oil and synthetic lubricants now are used to replace diesel oil in many drilling
situations. When oil or a synthetic spotting fluid is used as an aid in freeing stuck drill pipe, a standard
technique is to pump a slug or "pill" of oil or oil-based fluid down the drill string and "spot" it in the
annulus area where the pipe is stuck. Most of the pill can be removed from the bulk fluid system and
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disposed of separately. However, one hundred percent removal of the pill is not possible and a portion
of the spotting fluid remains with the fluid system.7
The most significant waste streams, in terms of volume and constituents associated with drilling
activities, are drilling fluids and drill cuttings. Drill cuttings are generated throughout the drilling project,
although higher quantities of cuttings are generated during drilling of the first few thousand feet of the well
because the borehole is the widest during this stage. The largest quantities of excess drilling fluids are
generated as the project approaches final well depth. Fluids are generated during the drilling process
because of displacement due to solids control, fluid changeover, and displacement by cement and casing.
Fluid generation is the greatest at well completion because the entire fluid system must be removed from
the hole and the fluid tanks. Some of the constituents hi the drilling fluid can be recovered after completion
of the drilling program, either at the rig or by the supplier of the drilling fluid. Where drilling is
continuous, such as on multiple-well platforms, the fluid can be conditioned and reused from one well to
another.8
3.0 PRODUCTION ACTIVITIES
This section describes the activities and processes associated with producing hydrocarbons from
the formation and processing the production fluids. The activities and processes described hi this section
are well completion, fluid extraction, fluid separation, well treatment, and workover.
3,1 COMPLETION
After confirmation of a successfully producing formation, the well must be prepared for
hydrocarbon extraction, or "completion." Completion operations include the setting and cementing of the
production casing, packing the well and installing the production tubing. During the completion process
equipment is installed hi the well which allows hydrocarbons to be extracted from the reservoir.
Completion methods are determined based on the type of producing formation, such as hard sand, loose
sand, fine grain loose sand, and loose fine and coarse grain sands. Bridging agents are used to prevent
fluid loss from the well to the formation.9-10
There are two types of completions: open hole and cased hole. Open hole completions are
performed on consolidated formations. Cased hole completions are performed on unconsolidated
formations. Figure IV-2 presents schematic diagrams of the four most common completion methods used
rv-8
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A. FOR HARD SAND FORMATION
-OPEN HOLE COMPLETED-
PRODUCTION
TUBING
B. FOR LOOSE SAND FORMATION
-CLOSED HOLE COMPLETION-
PRODUCTION
TUBING
CEMENT
HANGER
CASING
UNER
CEMENTED
AND
PERFORATED
OIL SANDS
GRAVEL
PACK
C. FOR FINE GRAIN LOOSE SANDS
PRODUCTION
TUBING
CEMENT
CASING
D. FOR LOOSE FINE AND COARSE GRAIN SANDS
PRODUCTION
TUBING
LINER
SCREEN
LINER
OIL SANDS
Figure IV-2
Typical Completion Methods
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for different formation types. All completion methods consist of four steps: wellbore flush, production
tubing installation, casing perforation, and wellhead installation.
Completion fluids are used during the completion phase to clean the wellbore or for pressure
maintenance until production is initiated. The initial wellbore flush consists of a slug of water that is
injected into the casing. These fluids are considered cleaning or pre-flush fluids and can be circulated and
filtered many times to remove solids from the well and to minimize the potential of damage to the
formation.11 When the well has been cleaned, a second completion fluid termed a "weighing fluid" is
injected. This fluid maintains sufficient pressure to prevent the formation fluids from migrating into the
hole until the well completion is finished.
During the second step of well completion, production tubing is installed inside the casing using
a packer which is placed at or near the end of the tubing. The packer, which consists of pipe, gripping
elements, and sealing elements, is made of rubber. The purpose of the packer is to keep the tubing in place
by expanding to form a pressure-tight seal between the production tubing and the well casing.1-12 The
packer seals off the annular space and forces the reservoir fluids to flow up through the tubing and not into
the well annulus. Packer fluids are completion fluids that are trapped between the casing and the
production tubing by the packer. These fluids are used to provide long-term protection against corrosion.
Packer fluids are typically mixtures of a polymer viscosifier, a corrosion inhibitor, and a high concentration
salt solution.13 Packer fluids remain in place and may be removed during workover operations.14
After the production tubing is secured in place with packers, it must be perforated to allow the
hydrocarbons to flow from the reservoir into the wellbore. Perforation may be accomplished with a special
gun (usually lowered into the well by wireline) that fires steel bullets or shaped charges which penetrate
the casing and cement. An additional means of perforation is achieved by suspending a small perforated
pipe from the bottom of the casing.1-12
The final step in well completion is the installation of the "Christmas tree," a device that controls
the flow of hydrocarbons from the well. When the valves of the Christmas tree are initially opened, the
completion fluids remaining in the tubing are removed and flow of fluids from the formation begins.
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3.2 FLUID EXTRACTION
The fluid produced from oil reservoirs consists of oil, natural gas (referred to hereafter as gas),
and produced water. Gas wells may produce dry gas, but usually also produce varying quantities of light
hydrocarbon liquids (known as natural gas liquids or condensate) and produced water. Produced water
contains dissolved and suspended solids, hydrocarbons, metals, and may contain small amounts of
radionuclides. Suspended solids consist of sands, clays, or other fines from the reservoir.
Crude oil can vary widely in its physical and chemical properties. Two important properties are
its density and viscosity. Density usually is measured by the "API gravity" method which assigns a number
to the oil according to its specific gravity. Oil can range from very light gasoline-like materials (called
natural .gasolines) to heavy, viscous asphalt-like materials.
V
Production fluids flow to the surface through tubing inserted within the cased borehole. For oil
wells, the energy required to lift the fluids up the well is supplied by the natural pressure in the formation,
known as natural drive. There are four kinds of natural drive mechanisms found with oil and gas
production: dissolved-gas drive, gas-cap drive, water drive, and combination gas and water drive.
As hydrocarbons are produced, the natural pressure in the reservoir decreases and additional
pressure must be added to the reservoir to continue production of the fluids. Additional pressure can be
provided artificially to the reservoir by various mechanisms at the surface. The most common methods
of artificial lift, or secondary recovery, are the following three: (1) gas lift, which is the injection of gas
into the well in order to lighten the column of fluid in the borehole and assist in lifting the fluid from the
reservoir as the gas expands while rising to the surface; (2) waterflooding, which is the injection of water
into the reservoir to maintain formation pressure that would otherwise drop as the withdrawal of the
formation fluids continue; and (3) employment of various types of pumps in the well itself. As the fluids
in the well rise to the surface, they flow through a series of valves and flow control devices that make up
the wellhead.
3.2.1 Enhanced Oil Recovery
When an oil field is depleted by primary and secondary methods (e.g., natural flow, artificial lift,
waterflooding), as much as 50 percent of the original oil may remain in the formation. Enhanced oil
recovery (EOR) processes have been developed to recover a portion of this remaining oil. The EOR
IV-11
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processes can be divided into three general classes: (1) thermal, (2) chemical, and (3) miscible
displacement.
Thermal: Thermal processes include steam stimulation, steam flooding, and in situ combustion.
Steam stimulation and flooding processes differ primarily in the number of wells involved in a field. Steam
stimulation uses an injection-wait-pump cycle in a single well, whereas the steam flooding process uses a
continuous steam injection into a pattern of wells and continuous pumping from other wells within the same
pattern. The in situ combustion process uses no other chemicals than the oxygen required to maintain the
fire.
Chemical: Chemical EOR processes include surfactant-polymer injection, polymer flooding, and
caustic flooding. In the first process, a slug of surfactant solution is pumped down the injection well
followed by a slug of polymer solution to act as a drive fluid. The surfactant "washes" the oil from the
formation, and the oil/surfactant emulsion is pushed toward the producing well by the polymer solution.
In polymer flooding, a polymer solution is pumped continuously down the injection well to act as both a
displacing compound and a drive fluid. Surfactant and polymer injection may require extensive treatment
of the water used in solution make-up before the surfactant or polymer is added. Caustic flooding is used
to drive oil through a formation toward producing wells. The caustic is delivered to the injection wells via
a manifold system; the injection head is similar to that used in steam flooding.
Miscible displacement: These EOR processes use an injected slug of hydrocarbon (e.g., kerosene)
or gas (e.g., carbon dioxide) followed by an immiscible slug (e.g., water). The miscible slug dissolves
crude oil from the formation and the immiscible slug drives the lower viscosity solution toward the
producing well. The injection head and manifold system are similar to those used for steam flooding.
3.3 FLUID SEPARATION
As they surface, the gas, oil, and water are separated for further processing and sale, and for
treatment. The gas, oil, and water are separated in a single vessel or, more commonly practiced, in a
series of vessels. Gas dissolved in oil is released from solution as the pressure of the fluid drops. Fluids
from high-pressure reservoirs may be passed through a number of separating stages at successively lower
pressures before oil is free of gas. The oil and brine do not separate as readily as the gas does. Usually,
a quantity of oil and water is present as an emulsion. This emulsion may occur naturally in the reservoir
or can be caused by the extraction process which tends to vigorously mix the oil and the water. The
IV-12
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passage of the fluids into and up the well, through wellhead chokes, various pipes, headers, and control
valves into separation chambers, and through any centrifugal pumps in the system, tends to increase
emulsification. Moderate heat, chemical addition, quiescent settling, and/or electrical charges aid in the
separation of emulsified liquids. The produced fluid separation system is a series of separation vessels
arranged in a multistage separation process. Figure IV-3 presents a flow diagram of a typical produced
fluid separation system.
The first stage of the produced fluids separation system consists of two-phase separators, or in some
cases of three-phase separators. High-, intermediate-, and low-pressure separators are the most common
arrangement, with the high-pressure liquids passing through each stage hi series and gas being taken off
at each stage. For gas wells the two-phase separators may generate light hydrocarbons that condense out
as the pressure and temperature drop. These light hydrocarbons (known as gas liquids of condensate) can
be processed and sold separately at a higher price than oil, or most commonly combined and processed
with the oil. In a two-phase separator, the gas is separated from the liquid products. The separated gas
is dehydrated hi a glycol dehydrator and then used for electrical power generation, gas lift operations, or
sold via pipeline. The liquid products free of gas are further treated in the oil treatment unit. A schematic
of a two-phase separator is presented in Figure IV-4.
A three-phase separator, often referred to as bulk separator, is sometimes used instead of a two-
phase separator to separate the produced fluids into gas, oil and water. The gas stream is drawn off the
top of the vessel and further treated in a glycol dehydrator. The oil stream is drawn off the middle and
piped to the oil treatment system for further processing. The water stream is drawn off the bottom and is
piped to the water treatment system for further treatment. A schematic diagram of a bulk separator in
presented in Figure IV-5.
Following the gas separation, the oil-water mixture is directed to the oil treatment system for
separation. The oil treatment system consists of free-water knock out (FWKO) tanks, heater-treaters,
and/or gun barrels. These types of oil-water separation systems may be used singly or in various
combinations. FWKOs are often used to remove free water (water that is not in emulsion) from the
influent to heater-treaters hi order to reduce the amount of fluids to be heated, thus reducing the energy
needed to heat the fluids.
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Production
Fluids
Gas to Pipeline
t_
Oil to Pipeline
Phase Separation
Oil/Water
Oil Treatment System
Oil
Water
Water
OPTIONAL
Oil
Water Treatment System
Produced Water to
Surface Discharge,
Injection or Transported
to Another Facility
Figure IV-3
Produced Water Treatment System
-------
GAS OUT
INLET
LIQUID OUT
PRESSURE
RELIEF
Source: Smith Industries, Inc., 1980
,15
Figure IV-4
Two-Phase Separator
IV-15
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PRODUCTION
FLUID
INLET
PRIMARY
SEPARATION
SECTION
CONTROL VALVE
UNIT
HgureIV-5
Three-Phase Separator
-------
Whether or not a phase separator is used, if oil-water emulsions are present heater-treaters are
required. Heat and/or emulsion-breaking chemicals are almost always necessary to break the oil-water
emulsions to assure low water content in the oil product (most pipelines have water content limitations on
the oil that can be transported). Heater-treaters are designed to remove emulsified water from the product
oil through gravity separation aided by heat and/or the addition of chemicals to enhance and accelerate
separation. Oil is drawn off the top of the heater/treater unit and sent to the oil product vessel for storage.
Water is removed from the bottom of the heater/treater unit and is either piped to the gun barrel or the
water treatment unit. A schematic diagram of a heater-treater is presented in Figure IV-6.
Gun barrels are sometimes used as a final oil-water separation process. The name refers to the fact
that these units are usually configured as tall vertical tanks to allow for gravity flow of oil to the oil stock
tanks. Figure FV-7 presents a schematic diagram of a gun barrel. A gun barrel is essentially a tall settling
tank which utilizes gravity separation, sometimes assisted with heat and/or chemicals to farther break the
oil water emulsion. The water is piped to the water treatment unit.
The water treatment system receives produced water from the oil treatment unit. Water treatment
usually consists of one or more large settling tanks, also called skim tanks, which utilize gravity to remove
any residual suspended oil droplets from the produced water. This process is sometimes aided with the
use of treatment chemicals such as surfactants.
An oil layer accumulates in the top portion of the tank. Oil is periodically removed from the top
of the tank and is piped back to the oil treatment unit. Water is drawn off the bottom of the vessel and is
either discharged to surface waters if it meets the BPT oil and grease limitations, injected underground or
transported to another site for disposal. In addition to the skim tank, the water treatment unit may include
gas flotation and coalescers. A detailed discussion of these other produced water treatment technologies
can be found Chapter VHI.
The major waste stream associated with production activities is the produced water stream.
Produced sand or production solids is another waste stream of lesser volume. Both waste streams originate
with the production fluids and are separated from the hydrocarbon products in the produced water
treatment system.
IV-17
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GAS OUTLET
EMULSION INLET
EMULSION
DOWNCOMER
OIL OUTLET
Source: Sunda, November 23,199416
SEPARATOR
SECTION WITH
GAS MIST
EXTRACTOR
EXHAUST
STACK
FIRE TUBE
ASSEMBLY
WITH BURNER
& FLAME
ARRESTOR
FREE WATER
KNOCKOUT
SECTION
WATER DUMP
VALVE &
CONTROLLER
WATER
OUTLET
Figure IV-6
Vertide Heater - Treater
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GAS EQUALIZER
EMULSION INLET
3»- GAS VENT
OIL OUTLET
WATER
OUTLET
WATER
LEG
GUN BARREL
Source: API, 1983"
Figure IV-7
-------
3.4 WELL TREATMENT
Well treatment is the process of stimulating a producing well to improve oil or gas productivity.
There are two basic methods of well treatment: hydraulic fracturing and acid treatment. The specific
method is chosen based on the characteristics of the reservoir, such as type of rock and water cut.n A well
treatment job will enlarge the existing channels within the formation and increase the productivity of the
formation. Typically, hydraulic fracturing is performed on sandstone formations, and acid treatment is
performed on formations of limestone or dolomite.10-12
Hydraulic fracturing injects fluids into the well under high pressure, approximately 10,000 pounds
per square inch gage (psig). This causes openings in the formation to crack open, increasing their size and
creating new openings. The fracturing fluids contain inert materials referred to as "proppants," such as
sand, ground walnut shells, aluminum spheres, and glass beads, that remain in the formation to prop the
channels open after the fluid and pressure have been removed.10*18 Hydraulic fracturing is rarely done in
Gulf of Mexico operations because the unconsolidated sandstone formations hi the region do not require
fracturing.
Acid stimulation is performed by injecting acid solutions into the formation. The acid solution
dissolves portions of the formation rock, thus enlarging the openings in the formation. The two most
common types of acid treatment are acid fracturing and matrix acidizing. Acid fracturing utilizing high
pressures results in additional fracturing of the formation. Matrix acidizing uses low pressures to avoid
fracturing the formation. The acid solution must be water soluble, safe to handle, inhibited to minimize
damage to the well casing and piping, and inexpensive.10
In addition to well treatment using hydraulic fracturing and acidizing, chemical treatment of a well
may also be performed. Well treatment with an organic solvent like xylene or toluene will remove
paraffins or asphalt blocks from the wellbore. These deposits of solid hydrocarbons occur due to the
decrease in temperature and pressure when the liquid hydrocarbons are extracted from the well.19
3.5 WORKOVER
Workover operations are performed on a well to improve or restore productivity, repair or replace
downhole equipment, evaluate the formation, or abandon a well. Loss of productivity can be the result
of worn out equipment, restricted fluid flow due to sand hi the well, corrosion, malfunctions of lift valves,
etc. Workover operations include well pulling, stimulation (acidizing and fracturing), washout,
IV-20
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reperforating, reconditioning, gravel packing, casing repair, and replacement of subsurface
equipment.I0-20'21 Responses to EPA's 1993 survey of coastal oil and gas facilities (discussed in Section V)
indicated that workovers or treatment jobs occur approximately once per year.2 The EPA survey of coastal
operators is described in detail in Chapter V.
The four general classifications of workover operations are pump, wireline, concentric, and
conventional22, Workovers can be performed using the original derrick if drilled from a drilling platform,
a mobile workover rig, or by wireline. The operation is begun by using a workover fluid to force the
production fluids back into the formation to prevent them from exiting the well during the operation. Then
tools and devices can be attached to the wireline (a spool of strong fine wire) and lowered and pulled from
the well to perform the required operations.
4.0 PRODUCTION AND DRILLING: CURRENT AND FUTURE
The industry profile is based on the information available at proposal revised to reflect changes in
the production operations or in the regulatory requirements. For coastal production facilities in Texas and
Louisiana, the issuance of EPA Region 6 General Permits has reduced the number of effected facilities
significantly since proposal (60 FR 2387; January 9, 1995). In Cook Inlet, operational changes have
resulted hi revisions to the industry profile since proposal. The industry profile used in development of
the final rule is described in Sections 4.1, and 4.2.
Subsequent to the issuance of the general permits requiring zero discharge hi the Gulf Mexico
region, EPA received individual permit applications seeking to discharge produced water. Additionally,
the U.S. Department of Energy (DOE) has provided the State of Louisiana with comments and analyses
in order to suggest a change hi the Louisiana state law that currently requires zero discharge of produced
water to open bays by January 1997. Because promulgation of this rule requiring zero discharge in these
areas would preclude issuance of permits allowing discharge, EPA also calculated an alternative estimate
of the costs, economic impacts, and pollutant removals under an "alternative requirements baseline." This
"alternative requirements baseline" assumes that zero discharge under the general permits would no longer
apply to Texas dischargers seeking individual permits and Louisiana open bay dischargers. The alternative
requirements baseline industry profile is described in Section 4.3.
EPA updated the profile of Cook Inlet production facilities with current hydrocarbon and water
production rates to address information submitted by industry hi comments. The profile was also updated
IV-21
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with current waterflood rates for use in estimating compliance costs under the produced water zero
discharge option. The most notable changes to the Cook Inlet production profile include one platform
which resumed oil production and ceased waterflooding; two platforms that resumed waterflooding; and
one platform substantially reduced its waterflood rate. Production and waterflood levels for the remaining
Cook Inlet facilities have not changed significantly since 1993. These profile changes are discussed in
detail in Section 4.2 and in the technical support document for Cook Inlet.23
4.1 INDUSTRY PROFILE
Coastal oil and gas extraction activities currently exist in the Gulf of Mexico coastal regions of
Texas, Louisiana, Alabama and Florida, in Long Beach Harbor, California, and in Cook Inlet and the
North Slope, Alaska. Because of dramatic geological, topographical and climatological differences
between these areas, production and drilling activities in these areas are equally as varied. In addition to
the geographic location, several other factors affect the operations of this industry. These factors include
whether oil, gas or both oil and gas are produced, whether the producing well(s) is located over water and
wetlands or on land, the depth of water, whether it is a single producing well or a cluster of single wells,
and whether it is a multi-well platform. The coastal oil and gas industry is described below hi terms of
production and drilling activity, as well as location and operational differences, where appropriate.
In general, the same factors that affect the operations of the producing wells will also affect the
configuration of the separation/treatment facilities (production facilities) that service these wells.
Production facilities consist of the treatment equipment and storage tanks that process the produced fluids
to separate the hydrocarbons from the water and treat the water for discharge or injection. Production
facilities may be configured to service one well, or as central facilities (also known as tank batteries or
gathering centers) to service multiple satellite wells. Production facilities are also configured to service
a single multi-well platform, or to service multiple platforms. A multiple-well producing platform is a
fixed structure usually located hi deep waters, with at least two producing wells that have the same surface
location.24
Coastal production facilities can be located over water or on land. Production facilities located
over water exist in generally two types of configurations: 1) individual deep water multi-well platforms
or 2) central facilities supported on barges or wooden or concrete pilings that service multiple satellite wells
in shallow water or wetlands. Production facilities on land may service satellite wells hi any combination
of locations.
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Depending on operational preference or regulatory requirements, many of the coastal production
facilities do not discharge produced water. Table IV-1 summarizes the number of producing wells and
annual drilling activities for the coastal regions of the United States and the number of producing facilities
that would incur costs due to this rulemaking, presented by geographic locations. The production facilities
listed in Table IV-1 are discharging produced water into major deltaic passes of the Mississippi River,
below Venice, Louisiana, and into the Cook Inlet in Alaska. This set of produced water dischargers is the
current requirements baseline population, and represents only 1.6 percent of the population of production
facilities accounted for in Table IV-1. The volumes and locations of discharges are discussed in more
detail in Sections 4.2.1.1 and 4.2.4. All other Louisiana and Texas facilities are required to meet zero
discharge of produced water under the requirements of NPDES permits (60 Fed. Reg. 2387; January 9,
1995). Along with the General permit, EPA issued a general administrative order providing until January
1997 to meet the zero discharge requirement. Other Gulf of Mexico production facilities, including those
in Mississippi, Alabama, Florida, and those in Long Beach Harbor, California, and the North Slope of
Alaska inject all of their produced water either for disposal or for waterflooding. Based on data provided
by the 1993 Coastal Oil and Gas Questionnaire, 62 percent (528 out of 853 production facilities), were
meeting zero discharge as of the 1992 time frame of the questionnaire.25
There are no discharges of drilling fluids or cuttings from coastal operators except for those in
Cook Inlet, Alaska. The volumes and locations of discharges are discussed in more detail in Section 4.4.
4.2 CURRENT PRODUCTION OPERATIONS
4.2.1 Gulf of Mexico Current Requirements Baseline
4.2.1.1 Facilities
Multi-well platforms, such as those found in the Gulf of Mexico offshore area, are not commonly
found in the Gulf coastal area. Based on an earlier mapping effort of all oil and gas wells, EPA determined
that there are only four structures owned and operated by four different operators in the coastal Gulf of
Mexico region that can be classified as multi-well platforms.24 In addition, many single wellheads are
located throughout coastal waters, serviced by gathering centers located on land or on platforms.
Production facilities in the Gulf of Mexico can be divided into two different types of structures:
those located on land or fill material and those located over water or wetlands. Production facilities located
IV-23
-------
TABLE IV-1
PROFILE OF COASTAL OIL AND GAS INDUSTRY
1
Coaslaf* .
Location
* f<
Gulf of Mexico
Alaska
California
TOTALS
*" Region-*
TX and LA
ALandFL
Cook Inlet
North Slope
Long Beach
Harbor
-
~SP*
x
4,675(a)
56(e)
225(g)
2,085(h)
586(e)
7,639
* Production *
' t Bcilittes ^
4 y 5-
853(a)
NE(f)
8(g)
Uffl
4(e)
876
No, of
Discharging in
'1992
s ''" ''
325(b)
0(e)
8(h)
W
0(c)
333
"No,, of Operators
* *58'> ^
270-435(a)
(162 dischargers(b))
NE(t)
3(g)
3(k)
Ke)
277-442
No««f
" Discharging
After-January
, 1997
JW »^ > }
6(0
0
3(g)
0
0
9
No, of Production
Discharging After
,, January 199^
^'^ * *
6(c)
0(e)
8(g)
000
0(0
14
No. New Wells Drilled per
Year
Types
f
686(d)
NE(f)
90)
1610)
NE(f)
856
WeBsOnly*
*
187(d)
5-7(e)
60)
NE(f)
6-7(0
204-207
Notes and Ref.s: (a) Jones, Sept. 26,1994 (25)
(b) Mclntyre, December 30,1994 (26)
(c) See Table IV-2.
(d) SAIC, Jan. 31, 1995 (2)
(e) Wiedeman, Sept. 6,1994 (27)
(0 NE = Not Estimated
(g) See Table IV-3.
(h) Wiedeman, Aug. 31, 1994 (28)
(i) Appendix X-l (Worksheet 2). Includes only development and recompletion wells.
(j) See discussion in Section 4.2.5.
(k) SAIC, Jan. 6,1995 (29)
0) Erickson, Jan. 24,1995 (30)
-------
on land and fill material in wetlands and shallow water usually utilize earthen berms around storage tanks
and equipment to contain spills. Production facilities located over water and protected wetlands can be
located on diked concrete platforms supported on wooden or concrete pilings. In deeper waters such as
in open bays, steel jacketed pilings or offshore type platforms may be necessary. Some of the older
facilities have been constructed using wooden platforms or pilings. Another configuration for facilities
over water is the use of barges to support equipment and for use as storage tanks. Although there are some
exceptions, in most cases those located on land can be accessed by car or truck (land-access) while those
facilities located over water must be accessed by boat or barge (water-access). Data from the 1993 Coastal
Oil and Gas Questionnaire indicated that in most cases production facilities located on land could be
accessed by car or truck (land-access), while those located over water must be accessed by boat or barge
(water-access). This distinction was particularly important at proposal for estimating compliance costs and
impacts. However, all of the facilities discharging into major deltaic passes of the Mississippi River have
been determined subsequent to proposal to be water-access. The production facilities listed in Table IV-1
that are discharging produced water in coastal areas of Louisiana were each determined to be water-access
facilities. Table IV-2 summarizes effluent production information for oil and gas production facilities for
the current requirements baseline facilities located in coastal Louisiana.
4.2.1.2 Population
Based on the data available to EPA at proposal, EPA estimated that there would be 216 production
facilities discharging in the Gulf of Mexico by July 1996 (the date scheduled for promulgating final Coastal
Guidelines). Shortly before the proposal was published, EPA's Region 6 published final NPDES General
Permits regulating produced water and produced sand discharges to coastal waters in Louisiana and Texas
(60 Fed. Reg. 2387; January 9, 1995). These permits prohibited the discharge of any produced water
derived from coastal waters of Louisiana and Texas. Because much of the industry covered by the
proposed Coastal Guidelines is also covered by these General Permits, the industry profile used in the cost
and economic analyses for the proposed rule overstates the number of facilities that would be incrementally
affected by the final Coastal Guidelines. This possibility was noted at proposal. In the preamble for the
proposed Coastal Guidelines, EPA stated that due to the close proximity (one month) of the timing of the
publication of the Region 6 General Permits and the proposed guidelines, the costs and impacts of the
proposed Coastal Guidelines were being presented in the preamble as if the General Permits were not final.
EPA presented preliminary results of how the costs and impacts of the Coastal Guidelines would be
reduced when the General Permits became effective and stated that the regulatory effects of the General
Permits would be incorporated in the analysis conducted for the final guidelines.
IV-25
-------
TABLE IV-2
GULF OF MEXICO DISCHARGERS OF OFFSHORE PRODUCED WATER
TO RIVER PASSES "
3229-001-3 Chevron Pipe Line Company
2963-006 Warren Petroleum Company
2071-004-1 Floras & Rucks, Inc.
2400-001 Gilf South Operators, toe.
2184-002-2 North Central (formerly
Forcenergy)
2184-003-1 North Central (formerly
Forcenergy)
2184-001 North Central (formerly
Forcenergy)
3407-001 Amoco
Main Pass Blk 69 North 0 18,920 18,920
Delta Gathering Station TantePhine - - 1,808
South Pass Blk 24 Southwest 30,779 123,116 153,895
Raphael Pass Raphael 271 20 291
South Pass Blk 24 Southwest 0 1,910 1,910
South Pass Blk 24 Southwest 0 7,606 7,606
South Pass Blk 24 Southwest 0 572 572
Grand Bay Emeling 0 6.290 6,290
TOTAL
-------
The main difference between the general permits and the Coastal Guidelines is that the permits
cover wastes generated by onshore Stripper Subcategory wells that are not covered under the Coastal
Guidelines and the Louisiana permit does not cover produced water derived from Offshore Subcategory
wells that is discharged into a major deltaic pass of the Mississippi River, or to the Atchafalaya River
below Morgan City including Wax Lake Outlet. Since proposal, EPA has worked with industry sources
and State regulatory authorities to identify those facilities whose discharges are covered by the Coastal
Guidelines, but are not covered by the requirements of the General Permits. No facilities discharging
Offshore Subcategory produced water into the Atchafalaya River were identified. Six production facilities
with a total of eight outfalls were identified as discharging produced water derived from Offshore
Subcategory wells into the major deltaic passes of the Mississippi River. These are presented hi
Table IV-2.
No new source facilities are expected hi the main deltaic passes of the Mississippi River.
Discharges at other coastal facilities are already required to comply with zero discharge under the Region
6 General Permits (60 PR 2387, January 9, 1995).
4.2.2 Mississippi, Alabama, Florida
According to the Mississippi State Oil and Gas Board, there are currently no coastal wells operating
in the wetlands of Mississippi. None are planned in the foreseeable future. The only Mississippi oil and
gas activity is onshore some 6 miles inland.32
Alabama coastal oil and gas activity consists of approximately 15 producing gas wells located in
Mobile Bay.33 Approximately 3-5 new wells are drilled hi Mobile Bay each year.34 All produced waters
from the Bay's activities are injected for disposal in UIC Class n wells located onshore. All drilling fluids
and cuttings are also transported to shore for disposal at onshore commercial disposal facilities.
In Florida, approximately 41 producing oil and gas wells currently exist hi coastal Subcategory
areas on the western side of the state.33 Average drilling rate is approximately two new wells per year.
All produced water is injected hi Class n UIC wells, primarily for disposal although some is also injected
for waterflooding. All drilling fluids are either reused, annularly injected, or left in a dry wellbore. Drill
cuttings are either disposed of in reserve pits or hauled off site to landfills.
IV-27
-------
4.2.3 California
The California coastal oil and gas industry currently exists on four man-made islands in Long
Beach Harbor behind the barrier islands in San Pedro Bay. The facilities on these islands are operated by
THUMS, a consortium of five oil and gas operating companies (Texaco, Humble (now Exxon), Union,
Mobil and Shell). On these four islands operated by THUMS, approximately 586 wells are producing as
of 1993.3S Six to seven new wells are drilled each year. All produced waters from these operations are
injected, primarily for waterflooding. No discharges occur from drilling fluids, drill cuttings, and
dewatering effluent. Closed-loop solids control technology is employed by these operations. All dewatered
solids are sent to an onshore landfill. The water from the solids dewatering equipment is allowed to settle
(on-site) and the decant is directed to the on-site produced water treatment system. Plans are to begin using
a grinding and injection operation in 1994 for drilling waste disposal. The ground wastes will be injected
into a UIC well on site.
4.2.4 Cook Inlet
All the coastal oil and gas production is currently confined to the Upper portion of Cook Inlet.' Oil
and gas is produced from multi-well platforms that are similar in construction to offshore platforms. Table
IV-3 presents information on existing oil and gas production facilities in Cook Inlet as of March 1996.
There are three major operators hi Cook Inlet: Unocal Corp., Phillips Petroleum Co., and Shell Western
E&P Inc. la addition, ARCO and Phillips Petroleum are together developing a new discovery, the Sunfish
field, which is located hi the North Upper Cook Inlet. The total current oil production in Cook Inlet is
about 37,400 barrels per day (bpd) and the total gas production is 385,000,000 cubic feet per day (cfd).
There are a total of 15 multi-well platforms in Cook Inlet, 13 of which were productive as of
March 1996. Five of the thirteen platforms separate and treat the production fluids at the platform.
Produced water from each of the five platforms is discharged directly overboard after treatment. The
remaining eight platforms pipe the production fluids (oil, gas, and water) to three shore-based facilities for
separation and treatment. Produced water from the three shore-based facilities is discharged to Cook Inlet
after treatment. Of the three shore-based facilities, two discharge treated produced water from the facility,
and the third sends its produced water back to one of the platforms for discharge. These three facilities
treat and discharge 96% of the produced water generated from all platforms in Cook Met (see Table IV-3).
As of March 1996, Unocal owned and operated twelve platforms in the Trading Bay, Granite
Point, and Middle Ground Shoal fields, which included a total of 163 oil producing wells, 55 service wells
IV-28
-------
TABLE IV-3
OIL AND GAS PRODUCTION FACILITIES IN COOK INLET REGION
ASOFMARCH19963'
•feifityjtorae
Operator.
fofaltfo.-
^wflaWe •
, Slots ,
-, Ho, Qil&Servfce'
,, ' "Wells
BjfcGas
w Wete,,
' l' ' * ' ^ '" '
Oil Production
* -$pa> •
*> v " /
Gas Production
,, $s>\v
, Seawateis ' '-
-Wate-flooding-
Vol.0pd) ?
Ave-lrStKlttcc'lH
-Water Vol. -
'- {"Pft -
>W6|i«bafgl',
location
PLATFORMS
King Salmon
Monopod
Grayling
Granite Point
Dillon
Bruce
Anna
Baker
Dolly Varden
Spark
Steelhead
Spurr
SWEPI "A"
SWEPI "C"
Tyonek "A"
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Unocal
Shell
Western
Shell
Western
Phillips
32
32
48
48
32
32
32
33
48
12
48
12
32
24
-
19 oil; 5 injection
22 oil; 2 injection
23 oil; 8 injection
1 1 oil; 7 injection
10 oil; 3 injection
13 oil; 7 injection
23 oil; 7 injection
14 oil; 5 injection
24oil; 9 injection
S(shut-in)
4 oil; 2 injection
6(shut-in)
17
17
0
1
0
1
0
0
0
0
2
1
9(shut-in)
9
l(shut-in)
1
0
13
3,864
1,981
5,207
6,086
841
86S
3,117
1,301
4,983
0
4,184
0
3,200
1,800
0
Platform Use
Platform Use
Platform Use
Platform Use
0
Platform Use
Platform Use
Platform Use
Platform Use
0
165,000,000
0
Platform Use
Platform Use
220,000,000
40,067
5,608
52,387
94
0
0
1,333
5,863
38,890
0
11,597
0
4,000
4,200
0
40,540
6,230
45,180
226
3,116
199
919
924
31,510
0
2,270
0
300
1,400
30
Trading Bay
Trading Bay
Trading Bay
Granite Point
Platform(a)
PlatfornKa)
Platforni(a)
Platform(a)
Trading Bay
Platform(a)
Trading Bay
Granite Point
East Foreland
East Foreland
Platform(a)
LAND-BASED TREATMENT FACILITIES
Granite Point
Trading Bay
E. Foreland
Unocal
Unocal
Shell
Western
-
-
--
-
-
-
-
--
•-
-
-
--
-
-
-
-
-
-
929
127,468
1,700
Spark Platform(a)
Outfall(a)
Outfall(a)
Metered outfall. Total produced water discharge is 135,285 bpd.
-------
used to inject seawater, and 14 gas producing wells. On average, these platforms produced 32,400 bpd
of oil in 1996. Only one Unocal-owned platform (Steelhead) produces enough gas to sell commercially.
The Steelhead platform has 9 wells that produce an average of 165,000,000 cubic feet of gas per day.
Most of the gas produced by Unocal-owned wells is not sold and is used to power equipment on platforms.
Four of the platforms separate and treat the production fluids on the platform. Oil is piped to shore for
sale, while the produced water, which totals an estimated 5,158 bpd from these four platforms, is
discharged overboard. The remaining eight platforms pipe the production fluids to two shore-based
facilities for separation and treatment. All produced water from these platforms, totaling an estimated
125,956 bpd, is discharged to Cook Inlet after treatment at the onshore facilities.
Shell Western E&P owns and operates two platforms in the Middle Ground Shoal field, including
a total of 34 oil producing and service wells and one gas producing well. The gas produced is not sold and
is only used to power equipment on platforms. The total produced water flow from the two platforms is
1,700 bpd. All production fluids are piped to the East Forelands shore-based facility for separation and
treatment. Produced water is discharged to Cook Inlet after treatment.
Phillips Petroleum operates one platform in the North Cook Inlet field, including 13 wells
producing 220,000,000 cubic feet of gas per day. All produced water generated is treated at the platform
and discharged overboard.
4.2.5 North Slope
Table IV-4 summarizes information regarding oil and gas production on the North Slope. As can
be seen from Table IV-4, there are a total of 2,085 oil, gas, and service wells on the North Slope. The
Prudhoe Bay field is the largest production field on the North Slope, accounting for about 71% of the total
oil production on the North Slope. The two major operators in Prudhoe Bay, ARCO and BP Exploration
(BPX), which own and operate the east side and the west side, respectively.
Production fluids are piped to gathering centers for separation and treatment. All the produced
water from the North Slope oil production operations is injected either for waterflooding or into regulated
disposal wells. About 88% of all the produced water is injected for waterflooding. The remaining 12%
is injected into Class n disposal wells.28
IV-30
-------
TABLE IV-4
OIL AND GAS PRODUCTION FACILITIES ON THE NORTH SLOPE28
\ , ,'
<:
Field Name
Prudhoe Bay
Kuparuk
Endicottb
Lisburne
Milne Point
West Beach
r-' - •
•.- Operator -
ARCO&BPX
ARCO
BPX
ARCO
Conoco0
ARCO
Total
Number of ''"'
Oil, teas, and
ServiceWeBs
1,159
663
85
86
91
1
2,085
. -;' M :
Pjroduction3
(bpd) , :
1,126,000
300,000
115,000
30,000
19,000
3,000
1,593,000
Average - -
, Produced
Water £q>d)-
1,233,000
300,000
80,000
8,000
11,000
0
1,632,000
Number of ,..
,„ Gathering
Centers
6
3
1
1
1
0
12
a Oil production data include natural gas liquid and condensate production, where applicable.
b Endicott field data also include production from BP's Sag Delta near Endicott.
c Conoco sold this field to BPX in December, 1993.
NOTE:
Point Mclntyre, West Beach, and N. Prudhoe Bay production is handled in the Lisburne Production Center.
There are a total of 12 production facilities (gathering centers) on the North Slope, of which all
but the Endicott gathering center are in the coastal region. The Endicott field is currently produced from
two gravel islands constructed in the Beaufort Sea. The production facilities on these islands are permitted,
by the Alaskan Department of Environmental Conservation, as offshore facilities. All the produced water
from the Endicott field is injected for waterflooding.28
4.2.6 Alternative Requirements Baseline
Alternative requirements baseline facilities include, in addition to all Cook Inlet facilities, Texas
facilities seeking individual permits allowing discharge and Louisiana open bay facilities as discussed in
the Industry Profile. Separate efforts were conducted to determine the population of Texas and Louisiana
alternative baseline facilities.
4.2.6.1 Texas Dischargers Seeking Individual Permits
The population of Texas dischargers seeking individual permits was obtained from the Railroad
Commission of Texas (RRC) intake log of facilities currently under Region 6 NPDES general permits
IV-31
-------
who are seeking individual permits or who have notified RRC of their intent to do so.38 The original RRC
intake log includes 91 outfalls, which were consolidated to 82 outfalls. The entire log was used, with
updated volume information from the RRC, to characterize the Texas alternative baseline population.
Revisions to the original RRC log included:
• Elimination of four facilities (RRC permits # 708, 731, 732, and 733). These facilities were
located in the Gulf of Mexico (offshore) rather than hi (coastal) open bay areas.39
• Revisions of produced water flow rates for four facilities, as noted.
• Combination of outfalls for identical permit numbers within the same field.
• Confirmation of zero produced water flow as logged by RRC, except for four new flow rates
extracted from permit applications.38
The Texas alternative baseline population is presented hi Table IV-5. Based on the data from the
1993 Coastal Questionnaire, these facilities are all considered land-access production facilities.
No new sources of produced water or drilling fluids are expected from the Texas alternative
baseline population. If new sources were to occur, they would be subject to pre-existing zero discharge
requirements and would not incur costs under this rule.
4.2.6.2 Louisiana Open Bay Dischargers
The inventory of Louisiana open bay dischargers was identified from the facilities listed in the
U.S. Department of Energy (DOE) report: "Final Report: Risk Assessment for Produced Water
Dischargers to Louisiana Open Bays."40 Based on the DOE report, the Louisiana open bay population
consists of 45 outfalls. The Louisiana open bay population is presented hi Table IV-5. Based on the DOE
report, the Louisiana open bay population consists of 45 outfalls.
Produced water flow rates were also obtained from the DOE study with certain exceptions. In
the case of two permits, the operator provided EPA with updated produced water flow rates which varied
substantially from the flow rates hi the DOE report. In five other cases, produced water flow rates were
omitted, intermittent, or listed as zero. EPA was reluctant to underestimate the population described in
the DOE report, so the average produced water flow rate (4,621 bpd) was substituted for discharges from
these five permits. (An underestimation could result hi underestimated costs and impacts for these
facilities.)
IV-32
-------
TABLE IV-5
TEXAS DISCHARGERS SEEKING INDIVIDUAL
PERMITS AND LOUISIANA OPEN BAY DISCHARGERS38
, ,
- Permit
Number , ,
927
242
264
*
552
922
605
202
684
694
637
822
970
710
174
967
921
679
124
238
731
619
968
666
105
937
60
167
166
20
904
85
45
969
80
*
90
68
81
77
164
813
952
113
954
953
TOTAL PW VOLUME
Current
Volume
(bbj/day) %
95.0
104.0
114.0
115.0
140.0
143.0
150.0
153.0
165.0
185.0
200.0
200.0
250.0
358.0
384.0
397.0
410.0
454.0
455.0
515.0
517.0
536.0
540.0
628.0
650.0
659.0
685.0
690.0
1,029.0
1,151.0
1,360.0
1,379.0
1,400.0
1,480.0
1,492.0
1,500.0
1,800.0
2,185.0
3,090.0
3,552.0
4,353.0
4,893.0
4,980.0
5,127.0
7,384.0
9,316.0
68,290.0
* Railroad Commission Permit Pending.
LOUISIANA
,
Peranit
Number
2,827
2,856
3,023
2,479
2,857
1,870
3,032
2,915
2,952
2,704
2,901
3,072
3,002
2,816
2,825
2,898
1,866
2,273
2,995
3,014
4,206
2,881
2,523
2,860
2,672
2,859
3,063
2,142
1,856
1,934
2,084
2,618
3,320
2,134
2,504
2,072
1,901
TOTAL PW
VOLUME
Current
Volume
{bbl/day)
1.0
3.0
3.4
10.0
20.0
49.0
50.0
130.0
2230
524.0
1,076.0
1,489.0
2,017.0
2,271.0
2,910.0
3,617.0
4,621.0
4,621.0
4,621.0
4,621.0
4,621.0
5,010.0
5,364.0
6,800.0
8,366.0
10,807.0
11,500.0
12,076.0
15,000.0
15,675.0
16,743.0
22,500.0
22,579.0
23,333.0
37,113.0
37,750.0
41,700.0
329,814.4
IV-33
-------
4.3 FUTURE COASTAL OIL AND GAS ACTIVITY
4.3.1 Drilling
Coastal drilling efforts vary from year to year depending on such factors as the price and supply
of oil, the amount of State and Federal leasing, and reservoir discoveries. EPA estimates that a total of
161 wells will be drilled in North Slope coastal areas, including development wells and recompletions.30
4.3.1.1 Cook Inlet
Based on drilling projections provided by the industry, EPA estimates future drilling in the Cook
Inlet region to be a total of 61 wells (or 9 per year) over the 7-year period from 1996 through 2002.41 The
projected 61 wells include development wells and recompletions. Based on the data provided by industry,
EPA estimates that 41 of the 61 wells are development and exploratory wells and 20 are recompletions.
These estimates are based on industry-projected drilling activity estimates and on the number of unused
slots on each platform. Projections were assumed to represent recompletions for those platforms where
drilling was projected but no slots are available for new wells. Out of these 61 wells, none will be
classified as "new sources" under EPA's NPDES program. This is because the projected wells will be
drilled from existing platforms, or will be exploratory wells (classified as existing sources). See also
Chapter HI of this document.
4.3.1.2 Other Coastal Areas
EPA estimates that the current drilling rate experienced by other coastal states in 1992 (see Table
IV-1) will be similar to future annual drilling rates, also. This is a conservative estimate based on
projections where drilling rates are not expected to increase (due to the maturity of the Gulf coastal oil
fields). Rather than project a decrease in drilling rates, EPA is estimating a linear projection.42 Thus, out
of the 686 well drilling operations performed per year in Texas and Louisiana, 187 of them will be for new
production wells (as reported in the EPA's statistical analysis of the 1993 Coastal Oil and Gas
Questionnaire.2 (Note: The Questionnaire is discussed in detail in Chapter V).
These estimated 187 projected drilling operations per year are new sources because they are
expected to be drilled over a new "water area". The remaining 499, which are either recompletions,
sidetracks of existing wells, exploration or service wells, are not new sources because they are drilled from
existing operations.
IV-34
-------
4.3.2 New Production Activity
New production activity for Louisiana and Texas is estimated to include six new facilities or
separation/treatment facilities per year, based on results of the 1993 Coastal Oil and Gas Questionnaire,43
For Alabama and Florida, EPA estimates a maximum of one new production facility per year, based on
a comparison of the number of producing wells in Alabama/Florida to the number of wells in
Louisiana/Texas.
No new sources are expected in Alaska. Although exploration and development of new fields will
continue on the North Slope, according to the operators there are no plans to build new production
facilities.44 For new discoveries, operators on the North Slope intend to take advantage of existing
separation/treatment facilities as much as possible, assuming that these facilities have sufficient capacity
to handle the increased load.44 For Cook Inlet, no new source production facilities are expected to occur
in the near future. This is because, even considering the Sunfish discovery, no new platforms construction
is expected.45
EPA knows of no plans for new islands at the THUMS facility at Long Beach Harbor, California.
1V-35
-------
5.0 REFERENCES
1. Baker, Ron, "A Primer of Offshore Operations," Second Edition, Petroleum Extension Service,
University of Texas at Austin, 1985. (Offshore Rulemaking Record Volume 22)
2. SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31, 1995.
3. Navarro, Armando R., "Innovative Techniques Cut Costs in Wetlands Drilling," in Oil and Gas
Journal. October 14, 1991, pp. 88-90.
4. Walters, Herb, Swaco Geolograph, Personal communication with Joe Dawley of SAIC regarding
drilling characteristics of the Gulf Coast region, August 17, 1993.
5. Ray, James P., "Offshore Discharges of Drill Cuttings," Outer Continental Shelf Frontier
Technology, Proceedings of a Symposium, National Academy of Sciences, December 6, 1979.
(Offshore Rulemaking Record Volume 18)
6. Meek, R.P., and J.P. Ray, "Induced Sedimentation, Accumulation, and Transport Resulting from
Exploratory Drilling Discharges of Drilling Fluids and Cuttings on the Southern California Outer
Continental Shelf," Symposium - Research on Environmental Fate and Effects of Drilling Fluids
and Cuttings, Sponsored by API, Lake Buena Vista, Florida, January 1980.
7. 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.
8. U.S. EPA. Response to "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160, July 1993.
9. American Petroleum Institute, "Detailed Comments on EPA Supporting Documents for Well
Treatment and Workover/Completion Fluids," Attachment to API Comments on the March 13,
1991 Proposal, May 13, 1991. (Offshore Rulemaking Record Volume 146)
10. Walk, Haydel and Associates, "Industrial Process Profiles to Support PMN Review; Oil Field
Chemicals," prepared for EPA, undated but received by EPA on June 24, 1983. (Offshore
Rulemaking Record Volume 26)
11. Wiedeman, Allison, U.S. EPA, Memorandum to Marv Rubin, U.S. EPA, "Supplementary
Information to the 1991 Rulemaking on Treatment/Workover/Completion Fluids," December 10,
1992.
12. Wilkins, Glynda E., Radian Corporation, "Industrial Process Profiles for Environmental Use
Chapter 2 Oil and Gas Production Industry," for U.S. EPA, EPA-600/2-77-023b, February 1977.
(Offshore Rulemaking Record Volume 18)
13. Gray, George R., H. Darley, and W. Rogers, "Composition and Properties of Oil Well Drilling
Fluids," January 1980.
IV-36
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14. Arctic Laboratories Limited, et. al., "Offshore Oil and Gas Production Waste Characteristics,
Treatment Methods, Biological Effects and their Applications to Canadian Regions," prepared for
Environmental Protection Services, April 1983. (Offshore Rulemaking Record Volume 110)
15. Smith Industries, Inc. Equipment Manual, 2nd Edition, Oil and Gas Division, Houston TX,
December 1980.
16. Sunda, John, SAIC, Memorandum to the record regarding "Production operation diagram
submitted by Tim Brown of Texaco in response to follow-up questions regarding the Bayou Sale,
Louisiana Tank Battery sampled by EPA on Oct. 23, 1992," November 23, 1994.
17. American Petroleum Institute, "Introduction to Oil and Gas Production," 1983.
18. U.S. EPA, Report to Congress, "Management of Wastes from the Exploration, Development and
Production of Crude Oil, Natural Gas, and Geothermal Energy," Volume 1, EPA/530-SW-88-003,
December 1987. (Offshore Rulemaking Record Volume 119)
19. Hudgins, Charles M., Jr., "Chemical Treatments and Usage in Offshore Oil and Gas Production
Systems," Prepared for American Petroleum Institute, Offshore Effluent Guidelines Steering
Committee, September, 1989. (Offshore Rulemaking Record Volume 145)
20. Acosta, Dan, "Special Completion Fluids Outperform Drilling Muds," Oil and Gas Journal,
March 2, 1981. (Offshore Rulemaking Record Volume 25)
21. American Petroleum Institute, "Exploration and Production Industry Associated Wastes Report,"
Washington, D.C., May 1988.
22. Parker, M.E., "Completion, Workover, and Well Treatment Fluids," June 29, 1989. (Offshore
Rulemaking Record Volume 116)
23. Avanti, "Compliance Costs and Pollutant Removals for Produced Water Generated at Oil and Gas
Production Platforms Located in Cook Inlet, Alaska," September 16, 1996.
24. Kaplan, Maureen, ERG, Memorandum to Neil Patel, EPA, regarding "Multi-Well Platforms -
ERG Definition and Survey Results," February 2, 1994.
25. Jones, Anne, ERG, Memorandum to Neil Patel, EPA regarding "Estimates for total numbers of
coastal wells, operators, and production," September 26, 1994.
26. Mclntyre, Jamie, SAIC, Memorandum to Allison Wiedeman, U.S. EPA, regarding "Compilation
of Discharge Monitoring Reports from Louisiana Department of Environmental Quality (LADEQ)
and Railroad Commision of Texas (RRC)," December 30, 1994.
27. Wiedeman, Allison, U.S. EPA, Memo to file regarding coastal oil and gas activity in CA, AL,
MS, and PL, September 6, 1994.
28. Wiedeman, Allison, U.S. EPA, "Trip Report to Alaska - Cook Inlet and North Slope Oil and Gas
Facilities, August 25-29, 1993," August 31, 1994.
IV-37
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29. SAIC, "Oil and Gas Exploration and Production Wastes Handling Methods in Coastal Alaska,"
January 6, 1995.
30. Erickson, Manuela, SAIC, Facsimile to Allison Wiedeman, U.S. EPA, regarding Seven-Year
Projected Drilling for North Slope, with attachments. January 24, 1995.
31. Avanti, "Compliance Costs and Pollutant Removals for Coastal Gulf of Mexico Produced Water
Assuming Compliance with Zero Discharge Under the EPA Region 6 General Permit," September
16, 1996.
32. Wiedeman, Allison, U.S. EPA, Telephone conversation with Walter Boone, Mississippi State Oil
and Gas Board regarding Coastal Well Profile, March 30,1994.
33. Wiedeman, Allison, U.S. EPA, Telephone conversation with Dave Bolin, Alabama Oil and Gas
Board regarding Coastal Well Profile, April 6,1994.
34. Wiedeman, Allison, U.S. EPA, Telephone Conversation with Dave Bolin, Alabama Oil and Gas
Board regarding Coastal Well Profile, May 17,1994.
35. Wiedeman, Allison, U.S. "EPA, Telephone conversation with Charles Tootle, Florida Department
of Natural Resources regarding Coastal Well Profile, March 29, 1994.
36. Wiedeman, Allison, U.S. EPA, Telephone Conversation with Kathy Lehman, Environmental
Compliance Specialist, THUMS regarding Coastal Well Profile, April 29, 1994.
37. Mclntyre, J., Avanti, Personal communication with Alice Bullington, Unocal, regarding "Updating
Produced Water Discharge Volumes, Oil and Gas Production Volumes, and Other Pertinent
Information," April 28, 1996.
38. Mason, T., Avanti, Memorandum to the record regaiding "Texas Dischargers Seeking Individual
Permits and Louisiana 'Open Bay' Dischargers: Costs and Loadings Estimates," September 30,
1996.
39. Montgomery, R., Avanti, Memorandum to the record regarding individual analysis of
latitudes/longitudes submitted by the Railroad Commission of Texas for applicants seeking
individual permits, June 7, 1996.
40. U.S. Department of Energy, "Final Report: Risk Assessment for Produced Water Dischargers to
Louisiana Open Bays," BNL-62975, March 1996.
41. Avanti, "Compliance Costs and Pollutant Removals for Drilling Fluids and Drill Cuttings,"
September 16,1996.
42. Jones, Anne, ERG, Memorandum to Allison Wiedeman, U.S. EPA, regarding "Future well-
drilling estimates," November 21, 1994.
43. Stralka, Kathleen & L. Bergeron, SAIC, Requested Quick Response Estimates from the Coastal
Oil and Gas Survey, July 12, 1994.
IV-38
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44. Erickson, Manuela, SAIC, Telephone conversation with Janet Platt, BPX, North Slope, Alaska
regarding BP's plans for new production fluid gathering centers on the North Slope, August 11,
1994,
45. Wiedeman, Allison, U.S. EPA, Communication with Jim Short, ARCO, regarding status of
ARCO's Sunfish operations in Cook Inlet, Alaska, May 9, 1994.
IV-39
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CHAPTER V
DATA AND INFORMATION GATHERING
1.0 INTRODUCTION
The major studies presenting information on coastal oil and gas effluents and treatment technologies
EPA used to develop the final rule are summarized in the following sections. These include: an
investigation of the underground injection of produced water and associated produced water treatment
technologies; an investigation of solids control technologies for drilling fluids; an investigation of the
drilling fluids and cuttings waste generation, treatment, and disposal in coastal Alaska; and an investigation
of commercial non-hazardous oil and gas waste disposal facilities and technologies. In addition, a
comprehensive Clean Water Act Section 308 survey of the industry was conducted to gather information
to help characterize the coastal oil and gas subcategory. The Questionnaire and a summary of results are
described in this section. A listing is included of certain data obtained in previous studies, and used in the
coastal rulemaking, conducted during the development of the offshore subcategory effluent guidelines
development.
2.0 INFORMATION TRANSFERRED FROM THE OFFSHORE RULE
Due to the similarities in the technologies employed and wastes generated by the offshore and
coastal subcategories of the oil and gas industry, certain data generated during the offshore rulemaking
have been utilized in the development of this rule where appropriate. Those data most influential in the
development of this rule, listed below, are described in more detail in the Offshore Development Document
and will not be discussed further in this section.1
• Produced Water Characteristics for Cook Inlet
The BPT-level produced water characteristics for Cook Inlet were used hi calculating the
pollutant reductions and the BCT cost test for the gas flotation and zero discharge options for
Cook Inlet discharges. The data used included flow-weighted averages of the organics and zinc
data in the Envirosphere report2, BPT level effluent concentrations from the Gulf of Mexico data
cited in Table XII-15 of the Offshore Development Document (where Cook Inlet data were
missing for certain pollutant parameters, as discussed in Chapter Vin of this document), and
radium data from the Alaska Oil and Gas Associations Comments submitted in response to the
offshore rule, 56 FR 10664 March 13, 1991 and 56 FR 14049 April 5, 1991.3
V-l
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Produced Water Characteristics for Effluent from Improved Gas Flotation
The difference between the pollutant concentrations for BPT-level effluent and the pollutant
concentrations achieved using improved gas flotation (IGF) were used to calculate pollutant
reductions for the IGF option. These data were reported in Table XII-15 of the Offshore
Development Document.
Drilling Fluids and Drill Cuttings Characteristics
The concentrations of organic pollutants in mineral oil were used to calculate the pollutant
loadings in drilling fluids and cuttings. The concentrations used were the averages of
concentrations for three types of mineral oil presented in the Offshore Development Document,
Table VE-9.
The barium concentration used to calculate the barium loading of the discharged drilling fluid
was calculated from the total pounds of barite in the drilling fluid. Based on the information
provided in the Offshore Development Document, page XI-8, the barite was assumed to be pure
barium sulfate (100% BaSO4) and the barium sulfate was assumed to contain 58.8 percent (by
weight) barium.
Deck Drainage Characteristics
The deck drainage characteristics from Chapter X of the Offshore Development Document were
incorporated into the descriptive portions of this document and were not used in any analysis.
Domestic Waste Characteristics
The domestic waste characteristics from Chapter XVI of the Offshore Development Document
were incorporated into the descriptive portions of this document and were not used in any
analyses.
Sanitary Waste Characteristics
The sanitary waste characteristics from Section XVII of the Offshore Development Document
were incorporated into the descriptive portions of this document and were not used in any
analyses.
Non-Water Quality Environmental Impacts
The non-water quality environmental impacts data were used to estimate the non-water quality
environmental impacts of this regulation. This includes the estimation of increases in air pollution
emissions and safety. The data used are information from the offshore rulemaking and
supplemented with information from sources described later in this Chapter. The data from the
offshore rulemaking effort and the supplemental sources are listed below:
Equipment power and fuel requirements4
Equipment operating parameters4
Personnel casualty and injury data5
V-2
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3.0 INDUSTRY SURVEY
A comprehensive questionnaire (comprising 99 pages) entitled the 1993 "Coastal Oil and Gas
Questionnaire" was developed under the authority of Section 308 of the CWA. This Questionnaire was
distributed to all known coastal oil and gas operators and requested detailed economic data and information
on oil and gas waste generated, treatment and disposal methods, and disposal costs for these wastes.
Prior to this, a draft of the Questionnaire was reviewed by several industry trade associations,
comments were considered and incorporated where appropriate. A pre-test Questionnaire was then sent
to seven coastal operators in August 1992. After reviewing the pre-test results and consulting the
operators, EPA made significant changes and improvements in the Questionnaire. In order to minimize
the burden, the seven operators were not included in the final survey.
The 1993 Coastal Oil and Gas Questionnaire, hereafter referred to as the EPA Questionnaire, was
divided into four sections. The first two sections requested information concerning the technical and
financial contacts. Section 3 requested technical operating information in two parts: Section 3.1
"Production Operations," and Section 3.2 "Well Drilling Operations." Section 4 "Finances" requested
financial information about the operator.
Section 3.1 "Production Operations" requested detailed information on: production data, treatment
system wastewater disposal, outfall data, treatment technologies, treatment costs, injection costs,
miscellaneous waste generation and disposal, miscellaneous waste disposal costs, and treatment chemical
usage. Section 3.2 "Well Drilling Operations" requested detailed information on: type of well, well depth,
drilling costs, type of drilling used, solids separation technologies, drilling fluid and cuttings disposal,
waste handling and disposal costs, miscellaneous waste generation and disposal, miscellaneous waste
disposal costs, reserve pit data, and drilling chemical usage.
The survey was designed to cover three interrelated populations. Population is a statistical term
used to describe the set of all units of interest. The three populations are: (1) all operators of coastal oil
and gas extraction facilities, (2) all coastal oil and gas wells, (3) all wastewater treatment facilities for
coastal oil and gas extraction. There are two basic methods for conducting a survey: one is to perform a
"census" which requests data on all identified units in a population, the second is to sample a subset of the
population which is referred to as a "survey." The EPA Questionnaire was sent to all known coastal
operators (a census) but only requested information on some of their wells (a survey).
V-3
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EPA developed a list of coastal operators and their wells by combining information from several
sources.6 Three data sources were used to identify production wells and their locations. One source was
the database maintained by the Petroleum Information Corporation. The database contains information on
the wells completed or worked-over between 1980 and 1990. Worked-over wells were sometimes drilled
decades prior to 1980. The second source was Tobin Survey Incorporated. Tobin compiles information
on wells by geographic location. The third source was information supplied by the Alaska Oil and Gas
Conservation Commission including wells that were active in 1991. As a result, the final list of operators
to be surveyed contained 361 coastal operators and 3,623 wells.6
The operators were grouped into three categories; majors, large independents, and small
independents. The wells were grouped into those completed before and after 1990 and those located in
saline and freshwater environments. Table V-l presents the breakdown of all 3,623 coastal wells into the
categories described above. The survey was designed so that a census of all 361 operators (not including
the seven pretest operators) was conducted. All operators were required to complete Section 4 "Finances."
Information on all 3,623 wells was not requested. The 327 wells surveyed in the pre-test Questionnaire
were excluded from responding to the Questionnaire. For 179 wells where particular situations existed that
were limited in occurrence, EPA requested information on all of these wells. Such circumstances included
wells located in marine wetlands (one well), wells located on platforms in the Gulf of Mexico (35 wells),
and all wells owned by small independent operators (143 wells). The remaining 3,177 wells were surveyed
using a stratified probability design (see Glossary), where a representative well population of 603 out of
3,177 wells were selected for purposes of responding to the Questionnaire. Operators were instructed to
provide technical information only on the wells identified and the separation and treatment facility
associated with each well.
Information was reported for all wells under Section 3.1 of the Questionnaire, entitled "Production
Operations," but operators were not expected to retain drilling information associated with older wells.
For Section 3.2 of the Questionnaire, entitled "Drilling Operations," EPA identified 191 wells that had
been newly drilled or worked-over during the period of 1990 through 1992. Information on drilling
operations was requested for only those identified wells. Of these, 167 were in the Gulf of Mexico and
24 were in Alaska. Data were received for 138 of the 191 wells surveyed for drilling operations.
V-4
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TABLE V-l
TOTAL WELL COUNT SURVEYED FOR COASTAL OIL & GAS WELLS BY CATEGORY
' _, ff& " " *
f f v, £ '' * ..
-,, '•• Population
Alaska
Gulf
Major
Major
Sm. Ind.
Other
ALL
, ,r m»r,f«t99<>
" SHfefc''
640
496
95
902
2,133
iMg'™*
282
119
26
355
782
::,:; Including 3S9Q and After
'f'lFJresi^ '
21
174
21
300
516
'-Saffinie '-'
39
67
2
84
192
Total
^Well\>
Coon?
982
856
144
1,641
3,623
Actual,
,WeHs ,
Surveyed
100
133
143
227
603
Of the 361 EPA Questionnaires that were sent out, 89 were out of scope because they were non-
coastal operators or out of business. Of the remaining 272 surveyed operators that were in scope, 236
responded. Sufficient numbers of respondents were available to generate estimates for each of the survey
strata, or analysis groups.
Upon their return, the EPA Questionnaires were reviewed for completeness and technical content
and then were transcribed into a computer readable format using double key-entry procedures. Survey
responses were used to generate statistical estimates describing that portion of the coastal oil and gas
industry associated with wells completed or recompleted after 1980.
As described in the Economic Impact Analysis,7 the well-specific data, statistical results, and an
adjustment factor related to flie number of producing wells that have not been recompleted since 1980 were
then used in determining waste volumes, treatment and disposal methods and costs. The survey results
were also used to estimate future industrial activity.
4.0 INVESTIGATION OF SOLIDS CONTROL TECHNOLOGIES FOR DRILLING
FLUIDS
In 1993, EPA collected samples and gathered technical data at three drilling operations in the
coastal region of Louisiana. The purpose of this effort was to gather operating and cost information
regarding closed-loop solids control technology at active oil and gas well drilling operations and to collect
samples of water generated from drilling waste dewatering operations. Samples were analyzed for a
V-5
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variety of analytes in the categories of organic chemicals, metals, conventional and non-conventional
pollutants, radionuclides, and toxicity.
Three drilling operations were visited and samples were collected during drilling of three
exploratory wells. The three wells were:
• The Gap Energy well (Sweetlake Land & Oil No. 1) in Holmwood, spudded on May 24,
1993;8
• The Arco well (Miami Corporation No. 1) on the Black Bayou Prospect in Cameron
Parish, spudded on June 22, 1993 ;9 and
• The Unocal well (LA. FURS. C-16) at Freshwater Bayou in Vermilion Parish, spudded
on August 7, 1993.10
The Gap and Arco wells were drilled using land-based rigs, while the Unocal well was drilled using
a posted-barge. At the time of the sampling visits, all three wells were being drilled using water-base
drilling fluids. However, for one well, oil-based fluids were used for the final section of the well.
Table V-2 presents summary information obtained regarding drilling of these three wells.
Samples of dewatering centrifuge liquid were collected to determine the characteristics of this
process stream. This process stream consisted mostly of the water phase of the drilling fluid. This
dewatering effluent was not discharged at any of the sites visited. One solids control contractor suggested
that further treatment with activated carbon would be necessary hi order to meet applicable discharge
criteria.9
One set of grab samples was collected on two consecutive days from the liquid discharge from the
centrifuge processing the drilling fluids. The major difference between the solids control systems was that
both Gap and Arco were using chemical treatment of the centrifuge influent with coagulant and polymer
to enhance centrifugation during the time of sampling while Unocal was not. The result was that separation
of the drilling fluid solids from the water was much more efficient at both the Gap and Arco sites. Both
the Gap and Arco samples were relatively free of suspended solids (TSS ranged from 24 to 520 mg/1) while
the Unocal samples were analyzed as a solids sample with total solids ranging from 23 % to 24.7% and had
the consistency of a drilling fluid.
V-6
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TABLE V-2
TECHNICAL DATA FOR THE THREE WELL DRILLING OPERATIONS VISITED
;?°;-t*; ";n^'-' *'*•'•*>•
.-i'j$~^^:r''*''
:£?-wWi*"^i;
Gap Energy
Holmwood, LA
Arco
Black Bayou
Prospect, LA
Unocal
Freshwater
Bayou, LA
,'• ',. <*'l!Mf*1
i ,«* '- ?' " " ' A 'H
l;teal-i)eptiiX
^ *f •• t ** *'* *
/? -^ '"• "•"''%• vf"?%y, '"
12,860 ft.
14,928 ft.
19,260 ft.
>•?' 3 , •"'.?•.> -i-'v . * ^
'~,\ '-*!«-« i'if'if'
t,4,,§aStf^i(B^lj-«
* > j- o, •> -g "i *'•*,. * ^-
f%.i, •;>,.. »- *."?*<•
norillingliuidi
• .^V^^jpl^V^
Water-base
Water-base
0-13,545 ft:
Water-base
> 13,545 ft:
Oil-base
; ,v, -;; '•* Jtti'f-! , ,- -*;**•* ,,..,..
S * f ¥" ^ -.^ 1 ' fe /«' ^ i-,'- *>V<. V, t*f, :'•:'*''' t,f *,$ ..
?-. f %', t° ^-*-- *•' ' -J •••• *, ,*> '*?•<' ' ^ <- "-'/v^-- '/' ^ '
fj 4 - ^ -,--- - <•-< "' - - :- / --' , >' v * ^\«> * - ' c-«
, •> '? , •* '' •> -? 4- v,, >; ^ ^ '.. J -•*•!,# ? ' £• fV •; s\-s •> *; ',
1 1; , ,5;. ^M^^^^Wto^"^' ^\
Shale Shakers, Degasser, Desander, Desilter
with Shaker, Barite Recovery Centrifuge,
Chemically Enhanced Centrifugation
Shale Shakers, Degasser, Desander, Desilter
with Shaker, Barite Recovery Centrifuge,
Chemically Enhanced Centrifugation
Shale Shakers, Degasser, Desanders, Desilter
with Shaker, Barite Recovery Centrifuge,
Centrifuge' (no chemical addition)
l*u^ il,F;;:
!r;fSolro;i!;«,;
V,$%g*»8fsji
90%
90%
75%
' Estimate provided by solids control contractor for equipment configuration during day of sampling.
-------
The combination chemical treatment and centrifugation, referred to as "chemically enhanced
centrifugation," allows the water to be recycled back into the drilling fluid recirculation system without the
build up of fine drill cuttings that is detrimental to the drilling fluid. This drilling technology is discussed
in greater detail in Chapter VII.
In addition to the sampling activities, technical and cost information was collected on the following
topics:
• drilling waste volumes and disposal methods
• solids control equipment design and performance
• drilling fluids
• well design and construction
• drilling operations
• annular injection
• miscellaneous waste volumes and disposal methods.
The results of this investigation were used to determine methods and costs of drilling waste
disposal, and to provide information on miscellaneous waste volume, treatment and disposal.
5.0 SAMPLING VISITS TO 10 GULF OF MEXICO COASTAL PRODUCTION
FACILITIES
From May 11 through November 13, 1992, EPA visited ten coastal oil and gas production facilities
located in Texas and Louisiana. The purpose of this effort was to gamer operating and cost information
at active oil and gas production facilities and to collect samples of produced water and associated wastes.
Samples were analyzed for a variety of analytes in the categories of organic chemicals, metals,
conventional and non-conventional pollutants, and radionuclides. Sampling at each site was conducted for
one day over a span of eight hours. Technical and cost data were collected in addition to the production
waste samples. Table V-3 presents the operator name, field name, and location of the 10 facilities. A
report was prepared, entitled "Coastal Oil and Gas Production Sampling Summary Report," that
summarizes and describes the samples collected, treatment systems employed, and data generated.21
Below is a brief summary of the facilities, the samples collected and the types of pollutants
analyzed in this study.21
V-8
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TABLE V-3
PRODUCTION FACILITIES SAMPLED
;: Operator Name
Greenhill Petroleum
Oryx Energy
Exxon Corporation
Orvx Energy
Texaco
Texaco
Arco
Texaco
Badger Oil Corporation
Texaco
•. ' - <. .. A
Field Name
Bully Camp
Chacahoula
Clam Lake
Caplen
Sour Lake
Port Neches
Bayou Sale
Bayou Sale
Larose
Lake Salvador
Location -
La Fourche Parish, LA
La Fourche Parish, LA
Jefferson County, TX
Galveston County, TX
Hardin County, TX
Orange County, TX
St. Mary Parish, LA
St. Mary Parish, LA
La Fourche Parish, LA
St. Charles Parish LA
Reference
11
12
13
14
15
16
17
18
19
20
Of the ten facilities sampled, six were in southeastern Louisiana and four were in southeastern
Texas.
Five were accessible by car and five were accessible by boat.
One site operator was a small independent company, one was a medium size company, and eight
were major companies.
Four facilities produced only oil and six produced both oil and gas.
Produced water flowrates ranged from 2,500 bpd to 11,500 bpd.
Nine facilities utilized injection wells for produced water disposal and one utilized surface
discharge.
Nine facilities utilized settling tanks as the primary step for removal of solids and trace quantities
of oil from produced waters.
One facility utilized a coalescer for removal of trace quantities of oil prior to settling.
All of the four facilities that were accessible only by .boat disposed of produced water using
injection wells and utilized filtration as a final treatment step between settling and injection. Three
of these facilities used cartridge filters and one used a 200 mesh screen.
Aqueous samples were collected from settling tank effluent at all ten facilities.
V-9
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Aqueous samples were collected at the influent (settling effluent) and effluent of all four filtration
systems.
Aqueous samples were also collected at the influent and effluent of the coalescer, although the
effluent samples were analyzed only for oil and grease and TSS.
Two consecutive four-hour grab composite samples were collected at all aqueous sample locations.
Each four-hour aqueous composite was analyzed for the following analytes:
Volatile Organics
Semi-volatile Organics
Metals
Conventional Parameters
Non-conventional Parameters
Radionuclides.
Four consecutive two-hour grab composite samples were also collected at all aqueous sample
locations. Each two hour composite was analyzed for the following:
Oil and Grease
- TSS.
Samples of cartridge filters were collected at all three facilities that utilized them. The samples
were analyzed for radionuclides only.
A grab sample of settling tank bottoms was collected at four facilities. Due to limited quantities
available at two of these facilities, one of these samples was analyzed for radionuclides only and
the other sample was analyzed for radionuclides and metals only.
A grab sample of material that was cleaned out of a heater-treater (mostly sand and some oil) was
collected at one facility.
The remaining two settling tank bottoms samples and the heater-treater sample were analyzed for
the following analytes:
Volatile Organics
Semi-volatile Organics
Metals
Conventional Parameter
Non-conventional Parameters
Radionuclides.
One grab sample of coalescer tank bottoms was collected, and since the solids were dilute, the
sample was analyzed as a liquid (aqueous) sample.
One sample of sand generated during the workover of an oil producing well was collected and
analyzed for radionuclides only.
V-10
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Figure V-l presents the location of the waste samples collected and also presents the five different
treatment and disposal sequences observed at the 10 facilities.
In addition to the sampling activities, technical and cost information was collected on the following
topics:
• separator and treatment system technologies and configuration
• equipment space requirements
• support structures
• miscellaneous waste volumes treatment and disposal methods
• produced water volumes and disposal methods
• energy requirements
• injection well remedial work requirements
• ancillary equipment requirements (besides the injection well) for injection
• injection well design and operation
• production data.
In response to comments on the proposed coastal oil and gas rulemaJdng, EPA excluded three
facilities in the 10 Production Facility Study with settling effluent oil and grease concentrations greater than
the BPT daily maximum discharge limit of 72 mg/1. These facilities were determined not to be
representative of current BPT practices. The data from the remaining seven facilities were statistically
evaluated to derive settling effluent average pollutant concentrations.22 The results from the 10 Production
Facility Study, together with data from the EPA Questionnaire, formed the basis for EPA's produced water
treatment and disposal cost analyses discussed later in Chapter XI. The analytical data was used to
characterize produced water effluent characteristics from BPT treatment system.
6.0 STATE DISCHARGE FILE INFORMATION
EPA obtained detailed information on produced water discharges, for operators in Texas and
Louisiana, by reviewing state discharge permits. The Louisiana Department of Environmental Quality
(LADEQ) and the Railroad Commission of Texas (RRC) supplied state permit data for all known
dischargers in the coastal areas.23 The state permit information identifies the operator, the name of the
producing field, the location of the production facility, the volume of produced water discharged, the
location and permit number of the outfall, and in Louisiana only, the compliance date by which the
V-ll
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Sequence
Number
1
3 __.,.,
4 „ „_
5
Produced ,,„,„,,.„,.. CoalMcw Settllno Filtration
Water Jrom c ™^ Effluent Effluent Effluent
Sun Barrels or SarW° _... Sample Sample SarnDlo
FWKDs - ^ Coalsscer ^
(') 0) (')
Produced l ' l ' '
Water from
Gun Barrels or
FWKDs
Produced
Water from
Gun Barrels or
FWKOs
Produced
Water from
Gun Barrels or
FWKDs
Produced / 1 \
Water from * '
Gun Barrels or
FWKDs
_^_: Aqueous Sample
^. : Tank Bottoms Sample
• : Filter Sample
^
Cartridge
Settling _A..to Filtration A •*. Inlnrtlnn Wnlli
0>A ,3, (3)| ,3,
Filtration
" "" ( \ ) ( 1 )
d)
Settling _
(2) A
The number in the parentheses indicates the number of
different facilities at which these samples were collected.
Figure V-l
Sample Locations and Treatment System Sequences
at the 10 Coastal Production Facilities
-------
discharge must cease. These data were used at proposal and during final rulemaking efforts to identify the
discharging population affected by the regulations. For the alternative baseline requirements analysis
(discussed in Chapter IV), EPA obtained from the RRC a list of produced water dischargers seeking
individual permits. The inventory of Louisiana open bay dischargers was identified from the facilities listed
in the U.S. Department of Energy (DOE) report entitled "Final Report: Risk Assessment for Produced
Water Dischargers to Louisiana Open Bays.Il24
7.0 COMMERCIAL DISPOSAL OPERATIONS
7.1 COMMERCIAL DRILLING WASTE DISPOSAL SITE VISIT
In May 1992, EPA visited two non hazardous oil and gas waste land treatment facilities at Bourg
and Bateman Island, Louisiana and also two waste transfer stations at Port Fourchon and Morgan City on
Bayou Boeuf, Louisiana. Campbell Wells is the operator of these four facilities. The purpose of these
visits was to investigate the transportation, handling, disposal methods employed and associated costs of
these operations. Detailed information was gathered concerning the operation of the landfarm treatment
process used for the disposal of non-hazardous oil field wastes, transportation equipment, transfer
equipment, equipment fuel requirements and costs incurred by the facilities and costs charged to the
customers. This information was summarized in the "Trip Report to Campbell Wells Landfanns and
Transfer Stations in Louisiana."23 The information was used in the development of compliance costs and
the non-water quality impacts for the various regulatory options being considered.
7.2 SAMPLING VISITS TO Two COMMERCIAL PRODUCED WATER INJECTION FACILITIES
On March 12, 1992, U. S. EPA visited two commercial produced water injection facilities to
collect samples and technical data.26'27 The purpose of the visits was to collect information regarding costs
of produced water disposal and other operating costs as well as to collect samples of produced water, filter
solids, used filters and tank bottoms solids for radioactivity analysis. The two facilities were Campbell
Wells in Bourg, Louisiana and Houma Saltwater in Houma, Louisiana. Both facilities received produced
water mostly by truck but also had the capability to receive produced water by barge. Both facilities
utilized sedimentation and filtration as treatment processes for produced water followed by underground
injection. The filtration systems differed slightly in that Houma Saltwater used bag and cartridge filters
in series while Campbell Wells (Bourg) used only bag filters. At the Campbell Wells (Bourg) facility,
water from the landfarming operation was combined with produced water received from offsite prior to
treatment and injection.
V-13
-------
At both facilities, samples of produced water from the influent and effluent of the filtration system
were collected as well as solids from the bag filters, settling tank bottoms and at Houma Saltwater, a used
cartridge filter. These samples were then analyzed for Ra-226, Ra-228, Gross Alpha, and Gross Beta.
The technical information gathered at these sites was used in developing compliance costs and the non-
water quality impacts for the various regulatory options being considered. The results of the radio- activity
analyses were used in an evaluation of radioactivity concentrations in oil and gas wastes. This evaluation
is described below.
8.0 NORM STUDY
EPA reviewed all known data regarding the presence of naturally occurring radioactive materials
(NORM) found in discharges of produced water and associated with scales and sludges (produced sand)
generated by production equipment from the coastal oil and gas industry. The oil and gas production
process can extract naturally occurring radionuclides from within the geologic formation. The most
common of these radionuclides found are radium-226, radium-228, and lead-210, which are soluble in the
produced water. Radium-226 and radium-228 concentrations in ocean water may range from 0.024 to
0.182 pCi/1 and 0.0001 to 0.1 pCi/1, respectively.28
EPA has prepared a report summarizing produced water radioactivity data from the 22 available
studies EPA has reviewed, focusing on data from coastal sites.29 Each of these 22 studies is summarized
in that report according to the location of the sites, sampling plans, and analytical methods used to measure
the radionuclides.
Tables V-4, V-5 and V-6 summarize the findings from this evaluation. This information was used
in characterizing produced water effluents hi the Gulf Coast.
9.0 ALASKA OPERATIONS
9.1 REGION 10 DISCHARGE MONITORING STUDY
In an effort to characterize discharges to Cook Inlet, EPA Region 10 conducted a comprehensive
Discharge Monitoring Study of facilities that discharge produced water.2 Produced water discharges from
production facilities were sampled and analyzed for one year, from September 1988 through August 1989.
Samples were collected and analyzed from two oil platforms, one natural gas platform and three shore-
based treatment facilities, all of which discharge produced water to Cook Inlet. The results of this
V-14
-------
TABLE V-4
SUMMARY STATISTICS OF RADIUM-226 (pCi/1)
FROM COASTAL OIL AND GAS SITES29
Stady "
1
2
3
6
7
8
9
10
11
16
17
20
21
22
*% ••''„?..*
; ' "* Source " , -
Formation Water
Untreated Effluent
Acidified/Filtered Effluent
Acidified/Unfiltered Effluent
Produced Water (all sample pts)
Produced Water Effluent
Produced Water Effluent
(all methods)"
Produced Water Effluent
(Method 707E only)"
Produced Water Effluent
Produced Water Effluent"
Produced Water Effluent
Produced Water Effluent
Produced Water Eff. (MOGA)"
Produced Water Eff. (DEQ)b
Produced Water Eff. (CSA)
Produced Water Effluent
Produced Water Effluent
(commercial facilities)1*
Produced Water Effluent
(production facilities)11
Production Equipment Scale'
Production Equipment SIudgec
Disposal Wastes"
Produced Water Effluent
Drilling Waste Effluent*
No^f-v
"'Sites
15
4
6
7
1
1
407
352
3
1
6
4
267
405
3
2
2
10
25
2
- ,No,'
-------
TABLE V-5
SUMMARY STATISTICS OF RADIUM-228 (pCi/1)
FROM COASTAL OIL AND GAS SITES29
Study
1
3
6
7
8
9
11
16
17
20
22
'• s /s^1"" fc-""^
: . .: Source ".. s, „{
& < •**•*•.!
• JV *
Formation Water
Produced Water (all sample pts)
Produced Water Effluent1
Produced Water Effluent1
Produced Water Effluent
Produced Water Effluent
Produced Water Effluent
Produced Water Eff. (MOGA)1
Produced Water Eff. (DEQ)1
Produced Water Eff. (CSA)
Produced Water Effluent
Produced Water Effluent
(commercial facilities)1
Produced Water Effluent
(production facilities)1
Production Equipment Scale'
Production Equipment Sludgec
Disposal Wastes'
Drilling Waste Effluent1
,, No. of
/ Sites' '
15
1
1
407
3
1
6
267
405
3
2
2
10
.
2
Sfo, of ;;
Samples,:
15
14
4
407
6
1
8
267
405
3
2
2
20
.
.
4
"'/" <-< "-
4-Meaij s
472.0
24.0
17.5
184.5
294.1
460.0
7.5
219.7
164.5
294.1
98.6
34.9C
228.411
120.0"
19.01
30.01
7.3C
>tf /
$f A V
11.6
5.8
375.9
69.4
3.1
77.2
71.3
4.0=
49.4
.
2.4=
^Mta,;;
' % A' -1
18.7
11.2
11.2
0"
233.6
5.3
0"
0"
244.4
48.2
17.5
3.1
5.7
\ JM[ax
1248
54.5
24.9
7090
386
9.7
928
928
383.0
149
49.0
500
.
10.5
' Samples below the minimum level of detection are set equal to the detection limit.
k One sample was reported with a detection limit of 0 pCi/1.
c Mean is arithmetic average of facility means; Standard deviation is pooled within-facility estimate.
* From SAIC, January 31,1995s
e Combination of coastal, offshore, and onshore sites.
sampling effort are summarized in Table Xn-15 in the Offshore Development Document1 and are used in
the coastal rulemaking to characterize Cook Inlet BPT produced water discharges.
9.2 EPA SITE VISITS AND INFORMATION GATHERING EFFORTS
In 1993, EPA visited drilling and production operations in both the Cook Inlet and the North Slope
regions of Alaska. Information and data were obtained during these visits, as well as by contacting the
V-16
-------
TABLE V-6
SUMMARY STATISTICS OF LEAD-210 (pCi/1)
FROM COASTAL OIL AND GAS SITES29
tff •' •' ^
<;$&%'
i^1-1- "*
3
17
20
22
" '"Source ! , ;
Produced Water (all sample pts)a
Produced Water Effluent1
Produced Water Effluent
(commercial facilities)2
Produced Water Effluent
(production facilities)*
Production Equipment Scale0
Production Equipment Sludge0
Disposal Wastes0
Centrifuge Effluent"
No. of
, Sites ,
1
1
2
10
.
2
No, of '
Samples
14
4
2
20
4
"• 'Mean'
7.1
7.1
47.4
75.2b
360.0"
56.0d
90.0d
12. 1"
•5
% S*d '-
0.5
0.4
0.9
27.4"
5.6
Mm
6.4
6.5
42.5
40.1
7.0
% ^ite'
8.0
7.5
50.5
221.0
19.0
a Samples below the minimum level of detection are set equal to the detection limit.
b Mean is arithmetic average of facility means; Standard deviation is pooled within-facility estimate.
c Combination of coastal, offshore, and onshore sites.
d Units are pCi/g for these samples.
Alaska Oil and Gas Association (AOGA), state regulatory authorities, and individual operators. The EPA
findings from the site visits are presented in a report on Cook Inlet and North Slope oil and gas facilities.30
AOGA and individual operators submitted, upon request from EPA, information on projects and
technologies currently being developed and used in Cook Inlet and on the North Slope to handle drilling
and production wastes, and the costs associated with these projects. The information regarding waste
handling methods and technologies was incorporated into a report prepared for EPA.31 This report
reviews all past and current exploration and production waste handling methods in both Cook Inlet and on
the North Slope, as well as the climate conditions and current state and Region 10 regulatory requirements.
The following sections summarize the information EPA has obtained through these efforts.
V-17
-------
9.2.1 Drilling Operations on the North Slope
In their effort to achieve zero discharge, operators of oil and gas exploration facilities on the North
Slope have developed a grinding and injection system for drilling fluids and cuttings as an alternative to
land disposal. The grinding and injection system is a result of many years of investigation of technologies
that can achieve zero discharge of drilling wastes.
As part of this program, operators investigated methods to reduce the volume of drilling fluids and
cuttings that would require disposal. One such waste reduction method involved the separation of the
surface cuttings from the drilling fluid, washing of the cuttings, and deterrnining their potential reuse as
construction material. Surface cuttings (cuttings generated from the first 3500 feet of drilled depth) account
for approximately 50% of the total cuttings volume. On the North Slope, these cuttings are very similar
to sand and gravel from the local pit mines which are used as construction material.31
The drill cuttings reclamation program established the potential of surface cuttings reclamation and
reuse as construction gravel material. The next step hi this program was to establish the technical
achievability and costs of winterized, mobile cuttings processing units. In general, the study of the cuttings
processing units consisted of processing surface hole cuttings through two separate, mobile, and winterized
units. Processed sands and gravel were collected and analyzed at specific intervals to determine then- reuse
potential as construction materials. Coarse materials were recovered for reuse, while fines and fluids were
disposed by injection.
As a result of this program, successful implementation of the use of grinding and injection for
drilling fluids and cuttings disposal on the North Slope has been occurring for the past several years.30
9.2.2 Production Operations on the North Slope
All production waste handling methods on the North Slope are currently regulated by state
agencies. Produced water, workover/treatment/completion (WTC) fluids, deck drainage, and produced
sand are not discharged from the North Slope coastal facilities including Endicott Island. Only domestic
and sanitary wastes may be discharged on the North Slope, after treatment. Produced water is injected for
waterflooding and for disposal into Class n injection wells.30
V-18
-------
9.2.3 Drilling Operations in Cook Inlet
Marathon Oil Co. and Unocal Corp. submitted to EPA a report on drilling waste disposal
alternatives and their implementation costs based on projected drilling schedules.32 Three alternatives were
investigated hi terms of technological achievability and costs: discharge to Cook Inlet, land-based disposal,
and disposal by injection.
EPA evaluated the information presented in this report and utilized the relevant information hi the
development of regulatory options for drilling wastes hi Cook Inlet. Costing information was used to
estimate the regulatory compliance costs.
9.2.4 Production Operations in Cook Inlet
Marathon Oil Co. and Unocal Corp. submitted to EPA a report on the technological and economic
feasibility of zero discharge of produced water from the Trading Bay onshore treatment facility.33 This
report presented the costs and technological achievability for three produced water injection alternatives.
EPA evaluated the information presented in this report and utilized the relevant information in the
development of the zero discharge option for produced water hi Cook Inlet by injection. Costing
information was used to estimate the regulatory compliance costs.
10.0 REGION 10 DRILLING FLUID TOXICITY DATA STUDY
In order to determine the appropriate toxicity level for a more stringent toxicity option for drilling
fluids and cuttings, EPA attempted to evaluate effluent toxicity test results for Cook Inlet drilling fluids and
cutting discharges.34 EPA reviewed permit compliance monitoring records, from EPA's Region 10,
containing 161 sets of results for toxicity testing of drilling fluids and drill cuttings used hi the Alaska
offshore and coastal regions between 1985 and 1994. (The measure of toxicity is a 96 hour test that
estimates the concentration of drilling fluids suspended particulate phase (SPP) that is lethal to 50 percent
of the test organisms.) The records were summarized into a database which was evaluated on the basis of
the toxicity of drilling fluids and drill cuttings used hi Alaska as a whole and Cook Inlet hi particular.
These evaluations utilized an available database obtained from EPA's Region 10, which provides
an account of the relationship between toxicity and drilling fluids currently being discharged. The toxicity
values are identified hi the available database by operator, permit number, well name, date and base fluids
V-19
-------
system (mud). In addition, some of the values are related to an identified volume of muds discharged.
However, many of the values in the summary do not have either a volume identified or whether the drilling
fluids were discharged. The findings of these evaluations were incorporated into the descriptive portions
of this document and were not used in any analysis.
11.0 CALIFORNIA OPERATIONS
EPA visited coastal oil and gas operations in Long Beach Harbor, California in February of 1992.35
Four man-made islands have been constructed in the Harbor for the purpose of oil and gas extraction, and
the facilities on these islands are operated by THUMS. EPA met with state regulatory officials and was
given a tour of one of the islands by THUMS personnel. Both drilling and production were occurring at
the time of the visit.
Information regarding waste generation, treatment, disposal, and costs were obtained during the
visit. The information provided EPA with specific waste disposal technology and cost information which
has, where appropriate, been incorporated into cost analyses, and enabled EPA to characterize California
coastal oil and gas operations.
12.0 OSW SAMPLING PROGRAM
EPA's Office of Solid Waste conducted a sampling program of various oil and gas wastes in
1992.3S<37 As part of this effort, samples were obtained for completion, workover, and treatment fluids.
EPA has used this database to characterize the effluent for these fluids. Treatment, workover and
completion fluids were collected from operations in Texas, New Mexico, and Oklahoma. Treatment,
workover and completion operations at onshore and coastal sites are identical, thus these data are valid for
characterizing discharges of these fluids at coastal operations. The samples were analyzed for
conventional, nonconventional and priority pollutants.
13.0 ESTIMATION OF INNER BOUNDARY OF THE TERRITORIAL SEAS
EPA specifically estimated the location of the outer boundary of the coastal subcategory (which
is the inner boundary of the Territorial Seas)38 by estimating the latitude and longitude coordinates covering
that part of the inner boundary of the Territorial Seas along Alaska's North Slope and Cook Inlet, Texas,
Louisiana, Alabama, and Southern California.
V-20
-------
Much of this boundary has been delineated on nautical charts published by the National Ocean
Service of the National Oceanic and Atmospheric Administration (NOAA). In some locations, however,
this boundary has not previously been delineated by NOAA, and EPA completed the coordinates using
established procedures described hi the Convention of the Territorial Seas and the Contiguous Zone,
Articles 3-13. This boundary was used by EPA to determine the number of coastal oil and gas wells that
exist in this subcategory.
14.0 OTHER INFORMATION SOURCES
EPA utilized specific information submitted with public comments on the proposed rule.
Commenters provided information that EPA included, where applicable, in the compliance cost, pollutant
removal, and non-water quality environmental impact (NWQI) analyses presented in this Development
Document. The information provided in the comments was augmented with additional data and
information as needed to update the corresponding sections of this document. The Construction Cost Index
(CCI) reported in the Engineering News Record was used to convert to 1995 dollars otherwise unmodified
compliance cost estimates as well as equipment or service costs from other years.39 In addition, EPA
contacted individual operators to confirm current drilling plans, oil and gas production facility locations,
current produced water discharging volumes, and produced water outfall configurations. The specific
sources of this information are cited throughout the chapters of this document.
V-21
-------
15.0 REFERENCES
1. U.S. EPA. Developent Document for Effluent Limitations Guidelines and New Source Performance
Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category, Final.
January 1993.
2. Envirosphere Co., "Summary Report: Cook Inlet Discharge Monitoring Study: Produced Water,
Discharges 016", prepared for Anchorage Alaska Offices of Amoco Production Company, Arco
Alaska, Marathon Oil Co., Phillips Petroleum Co., Shell Western E&P, Inc., Unocal Corp., and
U.S. Environmental Protection Agency, Region 10, August 1989. (Offshore Rulemaking Record,
Volume 156)
3. AOGA (Alaska Oil and Gas Association). "Alaska Oil and Gas Association Comments on U.S.
Environmental Protection Agency 40 CFR 435 Oil and Gas Extraction Point Source Category,
Offshore Subcategory; Effluent Limitations Guidelines and New Source Performance Standards;
Proposed Rule (56 FR 10664, March 13, 1991 and 14049, April 5, 1991)." May 13, 1991.
4. U.S. EPA, Engineering and Analysis Division, "Non-Water Quality Environmental Impacts
Resulting from the Onshore Disposal of Drilling Fluids and Drill Cuttings from Offshore Oil and Gas
Drilling Activities." January 13, 1993.
5. SAIC, "Evaluation of Personnel Injury/Casualty Data Associated with Drilling Activity for the
Offshore Oil and Gas Industry, prepared for Engineering and Analysis Division, U.S. Environmental
Protection Agency, January 11, 1993 (Offshore Rulemaking Record, Volume 156)
6. Murphy, Matt, ERG. Memorandum to Allison Wiedeman (U.S. EPA) regarding the Status Report
for the Section 308 Coastal Oil and Gas Questionnnaire. September 8, 1994.
7. U.S. EPA, "Economic Impact Analysis for Final Effluent Limitations Guidelines and Standards for
the Coastal Subcategory of the Oil and Gas Extraction Point Source Category," October 31, 1996.
8. U.S. EPA. Sampling Trip Report to GAP Energy Drill Site, Holmwood, Louisiana. June 16-17,
1993. June 8, 1994.
9. U.S. EPA. Sampling Trip Report to ARCO Oil and Gas Drill Site, Black Bayou Field, Sabine
Wildlife Refuge, Lake Charles, Louisiana. July 21-22, 1993. October 21, 1994.
10. U.S. EPA. Trip Report to Unocal, Intracoastal City, Louisiana, September 8-9, 1993. January 25,
1994.
11. U.S. EPA. Trip report to Greenhill Petroleum Corporation, Bully Camp Field, La Fourch Parish,
Louisiana. February 9, 1993.
12. U.S. EPA. Trip Report to Oryx Energy Company, Chacahoula Field - DS&B Lease, Chacahoula,
Louisiana. March 23, 1993.
13. U.S. EPA. Trip Report to Exxon Corporation, Clam Lake, Texas. September 15, 1993.
14. U.S. EPA. Trip Report to Oryx Energy Company, Caplen, Texas. September 15, 1993.
15. U.S. EPA. Trip Report to Texaco, Inc., Sour Lake, Texas. September 15, 1993.
V-22
-------
16. U.S. EPA. Trip Report to Texaco, Inc., Port Neches, Texas. September 15, 1993.
17. U.S. EPA. Trip Report to Arco, Bayou Sale Field, Louisiana. June 15, 1993.
18. U.S. EPA. Trip Report to Texaco, Inc., Bayou Sale Field, Louisiana. June 29, 1993.
19. U.S. EPA. Trip Report to Badger Oil Corporation, Larose, Louisiana. July 20, 1993.
20. U.S. EPA. Trip Report to Texaco, Inc., Salvador Lake, Texas. July 15, 1993.
21. U.S. EPA. Coastal Oil and Gas Production Sampling Summary Report. Draft Report. April 30,
1993.
22. SAIC. "Final Report: Statistical Analysis of Settling Effluent from Coastal Oil and Gas Extraction
Facilities," June 27, 1996.
23. Mclntyre, Jamie, SAIC, Memorandum to Allison Wiedeman, U.S. EPA, regarding Compilation of
Discharge Monitoring Report Data from Louisiana Department of Environmental Quality (LADEQ)
and Texas Railroad Commission (RRC), December 30, 1994.
24. Brookhaven National Laboratory. "Final Report: Risk Assessment for Produced Water Dischargers
to Louisiana Open Bays," BNL-62975, March 1996.
25. U.S. EPA. "Trip Report to Campbell Wells Landfarms and Transfer Stations in Louisiana, May 12
and 13, 1992." June 30, 1992.
26. U.S. EPA. "Trip Report to Houma Saltwater in Louisiana, March 12, 1992," May 29, 1992.
27. U.S. EPA. "Trip Report to Campbell Wells Land Treatment, Bourg, Louisiana, March 12, 1992,"
May 29, 1992.
28. Hamilton, Meinhold, and Nagy. Produced Water Radionuclide Hazard/Risk Assessment. Prepared
for the American Petroleum Institute. June 1991. (Offshore Rulemaking Record Volume 149)
29. SAIC. "Summary of Radioactivity Studies for the Coastal Oil & Gas Subcategory." September 30,
1994.
30. Wiedeman, Allison, EPA. "Trip Report to Alaska Cook Inlet and North Slope Oil and Gas
Facilities - August 25-29, 1993," August 31, 1994.
31. SAIC. "Oil and Gas Exploration and Production Wastes Handling Methods in Coastal Alaska,"
prepared for EPA, Final, January 6, 1995.
32. Marathon Oil Co. and Unocal Corp., "Drilling Waste Disposal Alternatives, A Cook Inlet
Perspective," Cook Inlet, Alaska, March 1994.
33. Marathon Oil Co. and Unocal Corp., "Zero Discharge Analysis, Trading Bay Production Facility,"
Cook Inlet, Alaska, March 1994.
34. SAIC, "Preliminary Statistical Analysis of Permit Compliance Monitoring Records for the Toxicity
of Drilling Fluids in Alaska (EPA Region 10), Draft Final Report," December 9, 1994.
V-23
-------
35. SAIC, "Oil & Gas Point Source Category: Trip Report of the U.S. EPA's Visit to the THUMS
Island Grissom Facility on February 7, 1992," July 16,1992,
36. Strauss, Matthew A,, Director, Waste Management Division, EPA Office of Solid Waste,
Memorandum to Thomas P. O'Farrell, Director Engineering and Analysis Division, EPA Office of
Water, regarding "Use of OSW Oil and Gas Exploration and Production Associated Waste Sampling
and Analytical Data," October 4, 1994.
37. Souders, Steve, EPA Office of Solid Waste, Memorandum to Allison Wiedeman, EPA Office of
Water regarding "1992 OSW Oil and Gas Exploration and Production Associated Wastes Sampling -
Facility Trip Reports," October 27, 1994.
38. Avantt, "Delineation of the Seaward Boundary of the Coastal Subcategory of the Oil and Gas
Extraction Industry," May 3,1993.
39. Engineering News Record, "First Quarterly Cost Report," March 25,1996.
V-24
-------
CHAPTER VI
SELECTION OF POLLUTANT PARAMETERS
1.0 INTRODUCTION
This section presents information concerning the selection of the pollutants to be limited for the
Coastal Effluent Guidelines. The discussion is presented by wastestream.
2.0 DRILLING FLUIDS, DRILL CUTTINGS, AND DEWATERING EFFLUENT
EPA is establishing BAT, BCT, NSPS, PSES, and PSNS limitations that would require zero
discharge of drilling fluids, drill cuttings, and dewatering effluent, except for BAT, BCT, and NSPS in
Cook Inlet, Alaska.
For BAT and NSPS in Cook Inlet, discharge limitations include no discharge of free oil, no
discharge of diesel oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a
toxicity limitation of 30,000 ppm SPP.
The toxic metals identified in drilling fluids and cuttings include zinc, beryllium, cadmium,
chromium, copper, nickel, lead, mercury, silver, arsenic, selenium, and antimony. Toxic organic com-
pounds in drilling fluids and cuttings include naphthalene, fluorene, and phenanthrene. Also included are
the alkylated forms of the toxic organics along with total oil, TSS and other metals including iron, tin, and
titanium. The pollutant data is summarized in Chapter VII of this document. Where zero discharge is
required, EPA will be controlling all pollutants in the wastestream.
For Cook Inlet, EPA has determined that it is not technically feasible to regulate separately each
toxic or nonconventional pollutant found in drilling fluids and drill cuttings discharges. The control of
diesel oil and free oil will control toxic and nonconventional pollutants found in these discharges; and thus,
diesel oil and free oil serve as indicator pollutants for these toxic and nonconventional pollutants, including
those that are not otherwise controlled by the diesel and free oil prohibitions. Limitations on toxicity and
cadmium and mercury content in barite control toxic and nonconventional pollutants in drilling waste
discharges, as discussed in the following sections.
VI-1
-------
With respect to EPA's BCT and NSPS limits prohibiting discharge of free oil, free oil would serve
as a surrogate pollutant for oil and grease in recognition of the complex nature of the oil present in drilling
fluids.
2.1 DIESEL OIL
Diesel oil may contain 20 to 60 percent by volume poly aromatic hydrocarbons (PAH's) which
constitute most of the toxic components of petroleum products. Diesel oil also contains a number of non-
conventional pollutants, including PAHs such as methylnaphthalene, methylphenanthrene, and other
alkylated forms of the listed organic priority pollutants. Prohibiting the discharge of diesel oil would
eliminate the discharge of the constituents of diesel oil listed in Table VI-1. Diesel oil is considered an
indicator of specific toxic pollutants present in the complex hydrocarbon mixtures used in drilling fluid
systems (see Section 2.2).
The use of mineral oil instead of diesel oil as an additive in water-based drilling fluids reduces the
quantity of toxic and nonconventional organic pollutants that are present in drilling fluids, as compared to
the quantity of these pollutants present when using diesel oil as an additive (See Table VI-1). Mineral oils
contain lower concentrations of some of the same pollutants than diesel oil due to their lower aromatic
hydrocarbon content and lower toxicity.
2.2 FREE OIL
The basis for a prohibition on discharges of free oil in drilling fluids and cuttings is substitution
of water-based fluids for oil-based fluids, use of non-petroleum oil containing additives and minimization
of the use of mineral oil. An additional technology basis for compliance with the prohibition on the
discharge of free oil is transporting the drilling wastes to shore facilities for treatment, disposal or reuse.
Transporting the drilling wastes to shore facilities would be done instead of product substitution when the
used drilling fluids are contaminated by crude oil due to the contribution of the oil from the formation being
drilled. In these situations, toxic and nonconventional pollutants contained in crude oil are eliminated from
discharge.
Free oil would be used as an indicator pollutant for the control of toxic pollutants. Free oil would
also be used as a surrogate for oil and grease in BCT options in recognition of the complex nature of the
oils present in drilling fluids including crude oil from the formation being drilled. Both free oil and diesel
VI-2
-------
TABLE VI-1
ORGANIC CONSTITUENTS OF DIESEL AND MINERAL OILS1
Concentration in rag/ml unless noted otherwise
••x
'<• i A
* -. '• •• "* ''
Organic Constituents .
: „ '- s .f ^ ;-- -
Benzene
Ethylbenzene
Naphthalene
Fluorene
Phenanthrene
Phenol Oig/g)
Alkylated benzenes(a)
Alkylated naphthalenes**
Alkylated fluorenes*'
Alkylated phenanthrenes9*
Alkylated phenols Gtg/g)(c)
Alkylated biphenyls®
Total dibenzothiophenes
Og/g)
Aromatic content (%)
&#£ytf
Mexico.
-. Diesel
ND
ND
1.43
0.78
1.85
6.0
8.05
75.68
9.11
11.51
52.9
14.96
760
23.8
M S "" I $ f
Ca»r;:
Diesel
„,,,„ -•„ ,
0.02
0.47
0.66
0.18
0.36
ND
10.56
18.02
1.60
1.41
106.3
4.03
1200
15.9
- , ,X'S, -
Alaska"
Dfesdl
0.02
0.26
0.48
0.68
1.61
1.2
1.08
25'. 18
5.42
4.27
6.60
6.51
900
11.7
EPA/Afet
K€f,
FiielOjS
0.08
2.01
0.86
0.45
1.06
ND
34.33
38.73
7.26
10.18
12.8
13.46
2100
35.6
Mineral
QttA
ND
ND
0.05
ND
ND
ND
30.0
0.28
ND
ND
ND
0.23
ND
10.7
'"M&fscai -
OUB
ND
ND
ND
0.15
0.20
ND
ND
0.69
1.74
0.14
ND
5.57
370
2.1
/Mineral ,
Oil £
ND
ND
ND
0.01
0.04
ND
ND
ND
ND
ND
ND
0.02
ND
3.2
Note: The study characterized six diesel oils and three mineral oils. For the purpose of the general comparison and summary
presented above, the Alaska, California, and Gulf of Mexico diesels are assumed to be representative of those used in
coastal drilling operations.
ND = Not Detectable
(a) Includes Cl through C6 alkyl homologues
w Includes Cl through C5 alkyl homologues
** Includes cresol and C2 through C4 alkyl homologues
oil are considered to be indicators and to control specific toxic pollutants present in the complex
hydrocarbon mixtures used in drilling fluid systems. These pollutants include benzene, toluene,
ethylbenzene, naphthalene, phenanthrene, and phenol. As an illustration of the relationships between oils
and drilling fluids, Table VI-2 shows an increase in oil and grease concentrations from water based fluids
to water-based fluids with mineral oil additives. This table is from Chapter VII, Section 4.3 of the 1993
VI-3
-------
TABLE VI-2
POLLUTANT ANALYSIS OF GENERIC DRILLING FLUIDS2
Generic .
Mud No,
i
2
3
4
5
6
7
8
2-01
2-05
2-10
8-01
8-05
8-10
Type of Mud
KC1 Polymer
Seawatcr Lignosulfonate
Lime
Nondispersed
Spud
Seawater/Freshwater
Lightly Treated
Lignosulfonate
Lignosulfonate Freshwater
Mud 2+ l%(Vol.)
Mineral Oil
Mud 2 + 5% (Vol.)
Mineral Oil
Mud 2+ 10% (Vol.)
Mineral Oil
Mud 8 + l%(Vol.)
Mineral Oil
Mud 8 + 5% (Vol.)
Mineral Oil
Mud 8 + 10% (Vol.)
Mineral Oil
PH
8.05
10.10
11.92
8.60
8.10
7.95
8.50
8.60
10.95
9.75
8.55
8.00
9.22
8.50
Specific
Gravity
1.74
2.15
1.73
1.44
1.09
1.09
1.44
2.12
2.15
2.07
2.04
2.21
2.23
2.25
%
Weight
toss
ttOS'C)
(b)
34.1
26.6
44.0
659.6
90.1
88.0
56.2
27.1
26.4
27.2
25.7
27.0
26.3
25.6
BODS
ACT
in
SOW
(b)
1,813
1,483
1,657
<50
<50
181
1,470
1,530
1,416
3,416
1,558
1,373
2,207
1,423
BOD,
POLY
In
SOW
-------
Offshore Development Document where characteristics of eight generic drilling fluids, representing water-
based drilling fluids commonly used in the drilling industry, were presented.3
The relationship between oils and toxic organic constituents can be illustrated by noting, as an
example, the concentrations of the toxic organic, phenanthrene, in drilling fluids. Table VI-3 shows an
increase in organic constituent concentrations from water-based fluids to water-based fluids with mineral
additives. Note a particular increase in phenanthrene from "not detected" in water-based fluids, to a range
of 1,060 to 19,300 /ig/kg *& water-based fluids with mineral oil additives. Furthermore, Table VI-1 shows
a general trend toward increases in organic concentrations from mineral oils to diesel oils. Note, for
phenanthrene in particular, a concentration in the range of not detected to 0.04 mg/ml in mineral oil to a
range of 0.36 to 1.85 mg/ml in diesel oil.
Prohibiting the discharge of free oil reduces the level of oil and grease present in the drilling fluids
and drill cuttings allowed to be discharged and eliminates the pollutants listed above to the extent that these
are present to a lesser degree in substitute' fluids and additives.
2.3 TOXIC1TY
Acute toxicity is a measurement used to determine levels of pollutant concentrations which can
cause lethal effects to a certain percentage of organisms exposed to the suspended paniculate phase (SPP)
of the drilling fluids and drill cuttings (for more details on the acute toxicity test see the final Offshore
Guidelines 58 FR 12507, March 4, 1993—Appendix 2 to Subpart A of Part 435). Toxicity of drilling
fluids, drill cuttings, and dewatering effluent is being regulated as a nonconventional pollutant that controls
certain toxic and nonconventional pollutants. The technology basis for the toxicity limitation is product
substitution, i.e., substitution using less toxic drilling fluids, or if the toxicity limitation cannot be met,
transporting the drilling fluids and cuttings to shore for disposal.
Additives such as oils and some of the numerous specialty additives, especially biocides, may
greatly increase the toxicity of the drilling fluid and drill cuttings (due to the adherence of drilling fluid to
the drill cuttings). The toxicity is, in part, caused by the presence and concentration of toxic pollutants.
However, control of free oil and diesel oil, hi some cases, may not be an effective means of regulating
these additives since they are neither diesel oil nor do they contain constituents with a free oil component.
A toxicity limitation requires that operators must also consider toxicity in selecting additives and select the
less toxic alternatives. Thus, the toxicity limitation will also serve to reduce discharges of toxic and non-
VI-5
-------
TABLE VI-3
ORGANIC POLLUTANTS D1T1GT1D IN GENERIC DRILLING FLUIDS2
Generic
Mud No,
i
2
3
4
5
6
7
8
2-01
2-05
2-10
8-01
8-05
8-10
/;"'". . ^a«;€|M^L,yl;.,,
KCl Polymer
Seawater Lignosulfonate
Lime
Nondispersed
Spud
Seawatet/Freshwater Gel
Lightly Treated Lignosulfonate
Lignosulfonate Freshwater
Mud 2 + 1 % (Vol.) Mineral Oil
Mud 2 + 5% (Vol.) Mineral Oil
Mud 2+10* (Vol.) Mineral Oil
Mud 8 + 1% (Vol.) Mineral Oil
Mud 8+5% (Vol.) Mineral Oil
Mud 8 + 10* (Vol.) Mineral Oil
;> jPhenartthiiiw
-
-
-
-
-
-
-
-
1,060
8,270
19,300
-
5,580
11,100
. Bibewite?m
-
-
-
-
-
-
-
-
-
827
1,040 .
-
-
933
N-Dodecanfc
•.'....:,.'..<$»>:.. . :..:.
899
-
809
819
854(822)
847 (802)
736
780
726
6,540
13,300
-
9,380
8,270
Diplictiylatnine
-
-
-
-
-
-
-
-
-
-
4,280
-
-
5,200
BIpften|I
-
-
-
-
-
-
-
'
-
867
2,290
-
-
1,120
Note: Concentrations are in jtg/kg
-------
conventional pollutants. The limitation would encourage the use of the lowest toxicity generic water-based
drilling fluids or newer drilling fluid compositions with lower toxicity than the generic fluids, and the use
of low-toxicity drilling fluid additives.
By regulating the toxicity of drilling fluids and cuttings, certain toxic and nonconventional pollu-
tants are controlled. It has been demonstrated, during EPA's development of the Offshore limitations
(discussed in Chapter V of the Offshore Development Document),2 that toxicity directly controls the type
and amount of mineral oil that can be added to a drilling fluid and pollutants such as PAHs identified as
constituents of mineral oil. Drilling fluids and drilling fluid additives with low toxicity would be
encouraged by a toxicity limitation.
2.4 CADMIUM AND MERCURY
By limiting cadmium and mercury content in the stock barite, toxic and nonconventional pollutants
in drilling fluids and cuttings can be controlled. EPA has determined that it is not technically feasible to
specifically control the toxic pollutants controlled by the mercury and cadmium limits. Limitations on
cadmium and mercury content in the stock barite would control toxic and nonconventional pollutants hi
drilling fluids and cuttings discharges. This limitation directly controls the levels of cadmium and mercury,
and indirectly controls the levels of other toxic pollutant metals. Control of other toxic pollutant metals
occurs because cleaner barite mat meets the mercury and cadmium limits has been shown to have reduced
concentrations of other metals.
Barite is an additive used in drilling operations to increase the weight of the drilling fluid necessary
when drilling "deep" formations. Barite is mined from either bedded or veined deposits. Research has
shown that bedded deposits are characterized by substantially lower concentration of heavy metal
contaminants including mercury and cadmium (See Table VI-4). Thus, use of barite from bedded deposits
will result hi less toxic drilling fluids.
Table VI-5 presents metal concentrations hi barite. Comparing the concentrations of metals for
"duty" (vein deposits) versus "clean" (bedded deposits) barite clearly indicate that for some metals, the
concentrations decrease when using "clean" barite and others stay virtually the same. Limiting cadmium
and mercury to 3 mg/1 and 1 mg/1 respectively hi stock barite indirectly controls the levels of toxic
pollutant metals by using cleaner barite because of reduced concentrations these metals have in clean barite.
VI-7
-------
TABLE Vl-4
ANALYSIS OF TRACE METALS IN BARITE SAMPLES4
Source
Literature Values:
Vein Deposits
Bedded Deposits
8-22,000
100-3,000
4-1,220
10-4,100
<200*""
0.06-14
0.06-
0.19
7*
<500*"
2-26
1-11
< 0.2-19
<50~
19"
<5
2-97
3-20
ND
<5-60
Kramer, et. al.:
Vein Deposits
Bedded Deposits
200-
59,000
2,500-
6,000
3,370
1-1.8
<0.2-
9,020
6-10
0.8-28
0.13-
0.26
0.008-170
1.4-1.8
0.5-0.7
0.4-5.7
5,4-7.6
1-2.2
Crust Average
Ocean Sediment
50,000
50,000
15
110
65
40
0.1
0.3
2
8
2
8
0.2
1
80
240
45
350
23
100
* - One Sample
** - Mean of 83 Samples
*** - Semiqoantitative Emission Spectrographic Method
ND -Notdetected
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, tftantan, and zinc; and the concentration of cadmium with the concentra-
tions of arsenic, boron, calcium, sodium, tin, titanium, and zinc.5
2.5 POLLUTANTS NOT REGULATED
Where zero discharge would be required, all pollutants would be controlled in drilling fluids, drill
cuttings and dewatering effluent discharges. In Cook Inlet, EPA has determined that it is not technically
feasible to specifically control each of the toxic constituents of drilling fluids and cuttings that are controlled
by the limits on the pollutants established in this regulation.
EPA has determined that certain of the toxic and nonconventional pollutants are not controlled by
the limitations on diesel oil, free oil, toxicity, and mercury and cadmium hi stock barite. EPA exercised
its discretion not to regulate these pollutants because EPA did not detect these pollutants in more than a
VI-8
-------
TABLE VI-5
METALS CONCENTRATION IN BARITE5
» ' \ Metal ^ ^"1*!
•, *• f "^ """" •> "-. •* "i*
Cadmium
Mercury
Antimony
Arsenic •
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
«J)irtjf * Barite€o»eea^tibtt
*~- ; (jtig/kgr^r % *
Priority Pollutants
2.3
0.7
5.7
12.0
0.7
561.4
39.9
66.7
13.5
1.1
0.7
1.2
200.5
"Cleaitf Barite Concentration
; - (wg^g) ? ,
1.1
0.1
5.7*
7.1
0.7a
240.0
18.7
35.1
13.5a
l.l1
0.7a
1.2a
200.5a
Nonconventional Pollutants
Bariumb
Iron
Tin
Titanium
120,000.0
15,344.3
14.6
87.5
120,000.0"
15,344.3a
14.6a
87.5a
3 Value substituted from "dirty" barite dataset where not available in "clean" barite dataset.2
b Source: SAIC, June 6, 1994.5
very few of the samples from EPA's field sampling program and does not believe them to be found through
out the industry; the pollutants when found are present in trace amounts not likely to cause toxic effects;
and due to the large number and variation in additives or specialty chemicals that are only used inter-
mittently and at a wide variety of drilling locations, it is not feasible to set limitations on specific
compounds contained in additives or specialty chemicals.
3.0 PRODUCED WATER
EPA is establishing BAT and NSPS limitations for produced water requiring zero discharge every-
where except for Cook Inlet, Alaska where oil and grease would be limited to a 29 mg/1 monthly average
VI-9
-------
and a 42 mg/1 daily maximum. BCT establishes limitations on the concentration of oil and grease in
produced water equal to current BPT limits (48 mg/1 monthly average, 72 mg/1 daily maximum). These
limitations represent the appropriate levels of control under BAT, BCT and NSPS.
3.1 POLLUTANTS REGULATED
"Where zero discharge is required, all pollutants found in produced water discharges are controlled.
In Cook Inlet, EPA is regulating oil and grease under BAT as an indicator pollutant controlling the
discharge of toxic and nonconventional pollutants. Oil and grease is limited for produced water under BCT
as a conventional pollutant. Oil and grease is limited under NSPS as both a conventional pollutant and as
an indicator pollutant controlling the discharge of toxic and nonconventional pollutants.
As previously denoted in the Offshore Technical Development Document (Chapter VI), oil and
grease serves as an indicator for toxic pollutants in the produced water wastestream which include phenol,
naphthalene, ethylbenzene, and toluene. Also see Table VTH-3 of Chapter VITJ which lists organic
pollutants detected in EPA's sampling programs.
The technology basis for the oil and grease limitations is improved gas flotation. In addition to oil
and grease, gas flotation technology with chemical addition removes both metals and organic compounds.
The insoluble metal hydroxide particle formation and adsorption by the chemical (polymer) floe of oil and
the action of the gas bubbles forces both the oil (oil and grease) containing floe and metal hydroxide floe
to the surface for removal (skimming), thus resulting in lower concentration levels in the discharge of oil
and grease for the above priority pollutants. (See Chapter VIE for discussions of gas flotation technology.)
During the Offshore Guideline development, EPA determined the characteristics of produced water
both after the BPT level of control and after gas flotation technology. Table VI-6 demonstrates that as oil
and grease is removed, so too are the organic pollutants. (Note, this table is taken from the Offshore
Guidelines and presents data that may be different from that used in the development of the Coastal
Guidelines presented throughout the proceeding sections of this document).
3.2 POLLUTANTS NOT REGULATED
"Where EPA requires zero discharge, all pollutants found in produced water would be regulated.
Thus, this discussion pertains only to EPA's BAT and NSPS limits for Cook Inlet and the BCT limitations.
VI-10
-------
TABLE VI-6
POLLUTANT LOADING CHARACTERIZATION—PRODUCED WATER2
•. ""-.•.' •. ~" ~~
, ,,, - . ,",
-------
The feasibility of regulating separately each of the constituents of produced water determined to be
present was evaluated during the development of the Offshore Guidelines (See Chapter VI of the Offshore
Technical Development Document).2 EPA determined that it is not feasible to regulate each pollutant
individually for reasons that include the following: 1) the variable nature of the number of constituents in the
produced water, 2) the impracticality of measuring a large number of analytes, many of them at or just above
trace levels, 3) use of technologies for removal of oil which are effective in removing many of the specific
pollutants, and 4) many of the organic pollutants are directly associated with oil and grease because they are
constituents of oil, and thus, are directly controlled by the oil and grease limitation. These reasons apply to
the Coastal Guidelines.
While the oil and grease limitations limit the discharge of toxic pollutants, EPA determined during
the Offshore Guidelines rulemaking that certain of the toxic priority pollutants, such as pentachlorophenol,
1,1-dichloroethane, and bis(2-chloroethyl) ether, would not be controlled by the limitations on oil and grease
in produced water. EPA is not regulating these pollutants in this rule because EPA did not detect them in the
samples within the coastal oil and gas data base. (See the Offshore Development Document, Chapter VI,
page VI-7).
Naturally occurring radioactive materials (NORM), mainly consisting of radium 226 and radium 228,
in produced water were found in concentrations averaging 400 pCi/1 (for both Radium 226 and Radium 228
combined, sometimes referred to as total radium) in the coastal areas of the Gulf of Mexico.6 This pollutant
would be eliminated by a zero discharge requirement.
Existing data for radium 226 and radium 228 in Cook Inlet produced water show that radium is
detected either at levels of detection or not at all. Data presented in Chapter VIE show radium 226 was not
detected in six out of eight produced water samples, and radium 228 also was not detected in six out of eight
samples. Where these analytes were detected, they were found at low concentrations only slightly above
levels of detection. Under the CWA, EPA has discretion to determine what pollutants to regulate. EPA has
determined that radium is not a pollutant of concern in Cook Inlet because it is either not detectable or, when
present, is present only in trace amounts not likely to cause toxic effects.
Produced water treatment technology, other than subsurface injection, has not been shown to remove
NORM. According to data submitted for the offshore record, removals of radium 226 and radium 228 by
granular filtration and improved gas flotation, if any, are believed to be minimal.7 The Offshore Development
VI-12
-------
Document also presents the membrane filtration performance on pollutant removals (summarized on Table
IX-17 of that document), which shows insignificant radium removals.
4.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
EPA is establishing BAT and NSPS limitations for well treatment, completion and workover fluids
requiring zero discharge for all coastal areas except for Cook Inlet, where BAT and NSPS establish oil and
grease limitations (29 mg/130-day average; 42 mg/1 daily maximum). EPA is also establishing a no discharge
of free oil limitation for BCT as determined by the static sheen test and a zero discharge requirement for all
coastal areas under PSES and PSNS. These limitations represent the appropriate level of control under BAT,
BCT, PSES, PSNS and NSPS.
Where zero discharge is required, all pollutants found in well treatment, workover and completion
fluids are controlled. As with produced water, oil and grease serves as an indicator for toxic pollutants in well
treatment, workover and completion fluids including, phenol, naphthalene, ethylbenzene, toluene, and zinc..
EPA has determined that it is not technically feasible to control these toxic pollutants specifically, and that the
limitations on oil and grease reflect control of these toxic pollutants at the BAT and NSPS levels. BCT limits
for treatment, workover and completion fluids prohibit the discharge of "free oil" as a surrogate for control
over the conventional pollutant "oil and grease." No discharge of "free oil" is determined by the static sheen
test. EPA is prohibiting discharge of "free oil" as a surrogate for control over the conventional pollutant "oil
and grease" in recognition of the complex nature of the oils present in drilling fluids, including crude oil from
the formation being drilled. Oil and grease is limited under NSPS as both a conventional pollutant and as an
indicator pollutant controlling the discharge of toxic and nonconventional pollutants.
EPA has determined, moreover, that it is not feasible to regulate separately each of the constituents
in well treatment, completion and workover fluids because these fluids in most instances become part of the
produced water wastestream and take on the same characteristics as produced water. Due to the variation of
types of fluids used, the volumes used and the intermittent nature of their use, EPA believes it is impractical
to measure and control each parameter. However, because of the similar nature and commingling with
produced water, the limitations on oil and grease and/or free oil in the Coastal Guidelines will control levels
of certain toxic priority and nonconventional pollutants for the same reason as stated in the previous discussion
on produced water.
VI-13
-------
4.1 POLLUTANTS NOT REGULATED
While the oil and grease and, in certain instances, the no free oil limitations limit the discharges of
toxic and nonconventional pollutants found in well treatment, completion and workover fluids, certain other
pollutants are not controlled. These pollutants are the same as those listed in produced waters as not being
controlled by an oil and grease limitation. EPA exercised its discretion not to regulate these pollutants because
EPA did not detect them in more than a very few of the samples within the subcategory and does not believe
them to be found throughout the coastal subcategory; and the pollutants when found are present in trace
amounts not likely to cause toxic effects.
5.0 PRODUCED SAND
EPA is establishing BPT, BCT, BAT, NSPS, PSES and PSNS limitations for produced sand equal
to zero discharge, which will control all pollutants present in the produced sand wastestream. This limitation
represents the appropriate level of control under BAT, BCT, NSPS, PSES and PSNS.
6.0 DECK DRAINAGE
EPA is controlling pollutants found in deck drainage by the prohibition on the discharge of free oil.
This limitation is the current BPT level of control and represents the appropriate level of control under BCT,
BAT and NSPS.
The specific conventional, toxic and nonconventional pollutants found to be present in deck drainage
are those primarily associated with oil, with the conventional pollutant oil and grease being the primary
constituent. In addition, other chemicals used in the drilling and production activities and stored on the
structures have the potential to be found in deck drainage.
The specific conventional, toxic and nonconventional pollutants controlled by the prohibition on the
discharges of free oil are the conventional pollutant oil and grease and the constituents of oil that are toxic and
nonconventional pollutants (see previous discussion in Section 2.2 of this chapter describing the chemical
constituents of oil). EPA has determined that it is not technically feasible to control these toxic pollutants
specifically, and that the limitation on free oil in deck drainage reflects control of these toxic pollutants at the
BAT and NSPS level.
VI-14
-------
Additional controls on deck drainage were rejected based on the technical fafeasibiliry of deck
drainage add-on systems to existing sump and skim pile systems currently being used. Deck drainage
discharges are not continuous, vary significantly in volume, and contain a wide range of chemical constituents
and concentration levels of the constituents, many of which are at or near trace levels. At times of platform
washdowns, the discharges are of relatively low volume and anticipated; during rainfall events, very large,
unanticipated volumes may be generated.
Vl-15
-------
7.0 REFERENCES
1. Batelle New England Marine Research Laboratory, "Final Report for Research Program on
Organic Chemical Characterization of Diesel and Mineral Oils Used as Drilling Mud Additives"
prepared for the Offshore Operators Committee—December 31, 1984 (Offshore Rulemaking
Record, Volume 13).
2. CENTEC Analytical Services Inc., "Results of Laboratory Analysis and Findings Performed on
Drilling Fluids and Cuttings - Draft," submitted to Effluent Guidelines Division, U.S. EPA, April
3, 1984 (Offshore Rulemaking Record Volume 13).
3. 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, EPA 821-R-93-003, January 1993.
4. Kramer, J.R., ELD. Grundy, and L.G. Hammer, "Occurrence and Solubility of Trace Metals in Barite
for Ocean Drilling Operations," Symposium—Research on Environmental Fate and Effects of
Drilling Fluids and Cuttings, Sponsored by API, Lake Buena Vista, Florida, January 1980. (Offshore
Rulemaking Record 26).
5. SAIC, "Descriptive Statistics and Distributional Analysis of Cadmium and Mercury Concentrations
in Barite, Drilling Fluids, and Drill Cuttings from the API/USEPA Metals Database," prepared for
Industrial Technology Division, U.S. Environmental Protection Agency, February 1991. (Offshore
Rulemaking Record Volume 120).
6. SAIC, "Statistical Analysis of Effluent from Coastal Oil and Gas Extraction Facilities (Final
Report)," September 30, 1994.
7. Jordan, R., Engineering and Analysis Division, U.S. EPA, Memorandum to Record. "Offshore
Oil and Gas—Characterization of BPT- and BAT- Level Produced Water Effluent," December 10,
1992.
8. SAIC, "Analysis of Oil and Grease Data Associated with Treatment of Produced Water by Gas
Flotation Technology," prepared for the Engineering and Analysis Division, U.S. EPA, January
. 13, 1993. (Offshore Rulemaking Record Volume 169).
VI-16
-------
CHAPTER VII
DRILLING WASTES
CHARACTERIZATION, CONTROL AND TREATMENT TECHNOLOGIES
1.0 INTRODUCTION
The first three parts of this section describe the sources, volumes, and characteristics of drilling
wastes generated from coastal oil and gas exploration and development activities. The last part of this
section describes the control and treatment technologies currently available to reduce the volume of drilling
wastes and the quantities of pollutants discharged to surface waters.
2.0 DRILLING WASTE SOURCES
This section focuses on three wastes generated during drilling: spent drilling fluid, drill cuttings,
and dewatering liquid. Drilling fluid and drill cuttings are both major wastes streams of concern because
they are generated in significant volumes. Dewatering liquid is a process stream that sometimes becomes
a waste stream. EPA has found that coastal facilities either recycle or send dewatering liquid offsite with
waste drilling fluids and cuttings to commercial disposal facilities.
2.1 DRILLING FLUID SOURCES
Drilling fluids, also referred to as drilling muds, are suspensions of solids, chemicals, and other
materials in a base of water, oil, or synthetic-based material which is specifically formulated to lubricate
and cool the drill bit, carry drill cuttings from the hole to the surface, and maintain downhole hydrostatic
pressure. Drilling fluids typically contain a variety of specialty chemicals (called "additives" in this report)
to control density (weight) and viscosity, reduce fluid loss to the formation, inhibit corrosion, and control
or impart other properties to the drilling fluid.
Drilling fluids are formulated at the drill site according to the drilling conditions. Once formulated,
the fluid is pumped down the drill pipe and ejected to the borehole through jets in the drill bit. The drilling
fluid returns to the surface through the annulus (space between the casing and the drill pipe). As the fluid
travels up the annulus, it carries the drill cuttings in suspension. The fluid then passes through the solids
vn-i
-------
control equipment (shale shaker screens, hydrocyclones, etc.) to remove the cuttings, and is returned to
the mud tank for recirculation. The design and use of solids control equipment are discussed in detail in
Section 5.5, "Waste Muiimization-Enhanced Solids Control."
Excess drilling fluids are removed from the fluid circulation system during the drilling operation
and at the end of the drilling program for various reasons. Excess drilling fluids are generated during
drilling when:
• cement, casing, drill pipe or packer fluid are placed downhole,
• the fluid is diluted to maintain constant rheological properties, and
• the entire drilling fluid system is periodically changed over in response to changing drilling
conditions.
At the end of the drilling program, the remaining fluid left over in the circulation system and the storage
tanks is either considered waste or recycled and/or regenerated for future use.
2.2 DRILL CUTTINGS SOURCES
Drill cuttings are small pieces of formation rock that are generated by the crushing action of the
drill bit. Additional hole material can slough off the drill hole wall, which is commonly referred to as
"washout." Drill cuttings are carried out of the borehole with the drilling fluids. Drill cuttings can
disperse as fine drill solids into the drilling fluids and can significantly effect the fluid's rheological (flow)
properties. Solids control is the process of maintaining the concentration of drill solids in the drilling fluid
at an acceptable level. The most common solids control methods are mechanical removal, dilution, and
displacement.
Dilution and displacement are usually practiced together because each method is dependent on the
other. As the level of fine drill solids increases in the drilling fluid, the viscosity also increases. For a
drilling fluid to remain effective, the viscosity must be maintained at a specific level. Diluting the drilling
fluid with make-up water has been the traditional method of viscosity control. In order to maintain other
properties of the drilling fluid after dilution, additives must be mixed into the fluid in correct proportions.
Therefore, the dilution method of viscosity control increases the total volume of drilling fluid in the system
and requires the purchase of additional drilling fluid materials. Since the drilling fluid circulation system
can hold only a limited volume of fluid at any time, the excess volume generated as a result of dilution
vn-2
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must be removed from the active system. Thus, the major waste generated from the use of
dilution/displacement is spent drilling fluid. The disposition of the displaced drilling fluid depends on
several factors including, but not limited to, site location, applicable regulations, and the operator's waste
management budget. Detailed discussions regarding the management and disposal of waste drilling fluid
are provided in later sections.
Viscosity can also be maintained by mechanically separating undesirable solids (drill cuttings) from
the drilling fluid (see also Section 5.5). It is important to note that dilution/displacement is often practiced
in combination with mechanical solids control as a means of maintaining desired drilling fluid properties,
although the amount of excess drilling fluid is minimized in this application. The major waste resulting
from mechanical solids control is drill cuttings with adhering drilling fluid. The disposition of the waste
drill cuttings depends on the same factors listed above for waste drilling fluid. These factors are discussed
in detail in later sections.
2.3 DEWATERING LIQUID SOURCES
Dewatering liquid may come from one of two sources: the dewatering of a waste drilling fluids
and/or cuttings storage vessel or pit, or from a dewatering centrifuge used as part of the solids control
system. EPA does not consider this as a separate waste stream because it is often recycled back into the
drilling fluid circulation system as make up water or mixed with waste drilling fluids and cuttings that are
sent to offsite commercial disposal facilities.
EPA investigated this particular potential waste source because it has been regulated separately hi
the Region 6 general NPDES permit (58 FR 49126; September 21, 1993). Dewatering liquid was the focus
of an EPA sampling program at three active drill sites in southern Louisiana.1-2'3 These sampling efforts
are described in Section V.4.0, "Investigation of Solids Control Technologies for Drilling Fluids." These
data were not used for regulatory purposes because EPA later determined through contacts with industry
and onsite visits, that this waste stream is rarely, if ever, discharged as a separate waste. BAT and BCT
limitations hi the coastal guidelines for dewatering effluent are to be applicable prospectively. BAT and
BCT limitations hi this rule are not applicable to discharges of dewatering effluent from reserve pits which
as of the effective date of the coastal guidelines no longer receive drilling fluids and/or drill cuttings.
Limitations on such discharges shall be determined by the NPDES permit issuing authority. Should an
abandoned reserve pit receive drilling wastes after the effective date of the coastal guidelines, then
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discharges of wastes from within the reserve pit would be required to comply with the zero discharge
limitations of the rule.
The technical aspects of dewatering liquid generation are discussed in greater detail in Sections
5.5.5 and 5.5.6.
3.0 DRILLING WASTE VOLUMES
Approximately 89,000 bbls per year of drilling fluids and cuttings are being discharged by the
coastal oil and gas industry, all of which is occurring in Cook Inlet. All other coastal areas are prohibited
from discharging drilling wastes. Thus, approximately 626,000 barrels of drilling fluids and cuttings will
be discharged from all of the Cook Inlet drilling projects currently planned by industry extending until the
year 2002. The following sections discuss the factors affecting the volumes of drilling waste generated and
numerical estimates of these volumes.
3.1 FACTORS AFFECTING DRILLING WASTE VOLUMES
Drilling fluids discharges are typically in bulk form and occur intermittently during well drilling
and at final well depth. Low volume bulk discharges are the most frequent and are associated with fluid
dilution, the process of maintaining the required level of solids in the fluid system. High volume bulk
discharges occur less frequently during a well drilling operation, and are associated with drilling fluid
system changeover and/or emptying of the mud tank at the end of the drilling program.
The volume of drilling fluid generated and the volume of drill cuttings recovered at the surface will
depend on the following:
• Size and type of drill bit
• Hole enlargement
• Type of formation drilled
• Efficiency of solids control equipment
• Type of drilling fluid
• Density of drilling fluid.
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The EPA Offshore Oil and Gas Development Document describes the effect of each of these factors
on drilling fluid volume.4
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. Drill solids are continuously removed via the solids
control equipment during drilling. 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. Continuous and
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.
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. Soft formations 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.
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.
Additional information regarding hole enlargement due to washout is listed in Table VEH. These
data were provided to EPA by drill site operators during visits to three coastal sites in southern
Louisiana.1'2-3 Because the volume of washout varies depending on the type of formation being drilled, no
single set of numbers can be applied as a rule of thumb to all drilling situations. However, Table VII-1
indicates that the percent washout generally decreases with hole depth. It should be noted that the values
in Table VH-1 were estimates obtained from industry operators during EPA's drilling site study and were
not directly measured.
3.2 ESTIMATES OF DRILLING WASTE VOLUMES
In order to compare waste volumes generated during various drilling projects, a normalized waste
volume can be determined by dividing the total reported waste discharged from the active drilling fluid
circulation system by the total volume of hole drilled. The volume of hole drilled is calculated from the
bit sizes used for specific depth intervals, and from estimated washout volumes. The volume of waste
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TABLE VH-1
PERCENT WASHOUT FACTORS
Reference
*
SAIC, May 25, 19941
SAIC, Aug. 8, 19942
SAIC, Aug. 5, 19943
Sv % s t **%Sji,\1X\l!(s'«X< W^ -, "* .. -1 'l
^, ?; Depth Interval >
C.A^fA/Jf66*) -f "
0 - 3,000
3,000-11,500
> 11,500
0-4,000
4,000-11,000
11,000-13,000
> 13,000
0 - 3,000
3,000 - 10,000
> 10,000
Percent Washout
' - "-' ' \ r '
100
25-50
10
75
40
20
10
100
50
25-50
discharged is typically available from waste transport reports or other records maintained at the drill site,
and are often estimated based on the volume of the vessel used to store and/or transport the waste. Once
calculated, the ratio of waste-to-hole volume can then be compared between drilling projects. For drill
cuttings, this ratio is called the "expansion factor" because it indicates how much a given volume of
cuttings increased after it was drilled out of the hole. No such distinctive name is used for the ratio of
waste drilling fluid to calculated hole volume. For both drilling fluids and cuttings, the waste-to-hole
volume ratio should always be greater than one, although in some cases it is less than one due to the
disposal of fine cuttings with the waste fluid, or to inaccurate waste volume tracking procedures or records.
Table VII-2 lists the hole volumes, waste volumes, and the calculated waste-to-hole volume ratios for eight
different drilling projects in the coastal Gulf of Mexico region. The first three projects were created based
on a "model well" as part of EPA Region 6's development of two general NPDES permits for coastal
Louisiana and Texas (55 FR 23348), and were not actual wells drilled. The characteristics of the model
well (e.g., depth intervals, hole volume, percent washout, etc.) and the solids control system parameters
were designed to represent typical coastal drilling projects. The remaining five projects in Table VII-2
were actual wells, including two offshore and three coastal.
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TABLE VLI-2
WASTE DRILL CUTTINGS AND DRILLING FLUID VOLUMES
C-> ,,:'- s 'i '•• ;;f|lefei?nj*''-> - > i , :*'•,. - , '*
"••* '"W •"> -• *•?> * < >'*••%
*.*;*-.,.- * > f ,*, ^, -JiJjWv'*' '>"^'J/W">
.. <. ,',,', i" :, : '"', ' $ •/, ' ?^M-'" '
55 PR 23348
(EPA Region 6 general NPDES permit)
Offshore Operators Committee, 1981'
(Data for two offshore wells)
SAIC, May 25, 1994'
(Data obtained during EPA site visit)
SAIC, August 8, 19941
(Data obtained during EPA site visit)
SAIC, Augusts, 19943
(Data obtained during EPA site visit)
Average
''," Clo|^«tpV$oliife j.
;;""-t --'Efflcienc^?7"x
•'} -f",'- ">•,„ \-^: ^,1
Scenario 1: 36%
Scenario 2: 62%
Scenarios: 90%
50%
90%
90%
75%
70%
'., iWeli^fipth":
-f'^ffK>V
•",¥•'"- —"", ;
'"'"S >,, I,*' ^ \ 'v ^ AS
'S\ '.,**«ii^
15,000
10,000
18,000
12,860
14,928 .
19,260
15,000
, 5 Calculated *-'<.
Hofe;Viili]ine%<'
'^"--(bbfe) ~ '/'£
1,881
2,453
4,619
2,126
3,689
7,510
3,173
Drliiuig Fluids
l-Volufae11"'''
:^*ttj:-
21,220
12,938
3,405
5,349
10,486
2,690
5,850
8,198
8,767
,- tals)?
11.2
6.88
1.81
2.18
2.27
1.27
1.59
1.09
3.54
-;t«8to.::
;- "CutBngs •- -
TVoIume6^'
_,,',. jSb® ~ '
2,264
3,301
3,889
1,430
2,781
3,256
10,070
8,130
4,390
,:^*p:i
• Expansion <
'/rSUefor4 ",
jlOJtjWBB^f
1.20
1.75
2.07
0.58
0.60
1.53
2.73
1.08
1.44
"Hole Volume" was calculated from drilled hole diameter and depth data provided in the references. The data have been adjusted to compensate for hole enlargement due to erosion (washout).
"Discharged Cuttings/Mud Volume" includes the total volume of cuttings or spent drilling fluids that were either discharged or hauled-off by the end of drilling, as reported in the references. These values may
be derived estimates or actual data, depending on the reference document.
"Expansion Factor" = Discharged Cuttings Volume (bbls) / Calculated Hole Volume (bbls).
-------
A number of observations can be made from the data in Table VII-2. Referring to the EPA Region
6 data only, it is apparent that as solids control system efficiency increases, the fluid-to-hole volume ratio
decreases and the cuttings expansion factor increases. A low efficiency solids control system will allow
a significant volume of drill cuttings to remain in the circulating drilling fluid, thus requiring greater
dilution of the drilling fluid and hence increasing the volume to be disposed. A higher efficiency solids
control system will remove a greater volume of cuttings from the circulating drilling fluid, thus decreasing
the need for dilution as well as the volume of waste drilling fluid. In addition, if chemically enhanced
centrifugation (CEC) is part of the solids control system, the volume of waste solids should be slightly
higher than systems not using CEC because the flocculated solids add to the volume discharged by the
centrifuge.
These trends are to be expected, but are not always observed in practice due to site-specific
conditions, inaccuracies in hole volume estimation, and in waste volume tracking and reporting. Data from
the five actual drilling projects listed in Table VII-2 illustrate this point. The cuttings expansion factors
for the two offshore drilling projects are both less than one, suggesting that washout volumes may have
been overestimated and that a significant volume of cuttings may have been included with the discharged
mud volume. Also, the 8,130 barrels of cuttings reported for the last drilling project in this table is known
to include 591 barrels of spent drilling fluid and is believed to include more, particularly because the
cuttings were collected in a barge and there was no other holding vessel dedicated to spent drilling fluid
at the site. Such uncertainties about what is included hi a load of drilling waste and its volume occur
because there are no requirements for keeping waste drilling fluid and cuttings volumes separate when they
are being hauled offsite.
Volumes of waste drilling muds and cuttings generated by operators located in Cook Inlet, Alaska
were reported in responses to the 1993 EPA Coastal Oil and Gas Questionnaire.6 From the data submitted
in the survey and information obtained directly from the operators, an average volume of muds and cuttings
generated was calculated to be 14,354 barrels from an average well of 11,765 feet hi depth. Table VH-3
lists the data used to calculate these averages.5
Based on this estimation and on projected drilling schedules provided by operators in Cook Inlet,
the total volume of drilling wastes generated from drilling activities in Cook Inlet is a total of 632,000 bbls
over the seven years following promulgation of this rule, or 90,000 bbls per year (see Chapter X for
details).
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TABLE VII-3
COOK INLET DRILLING WASTE VOLUMES
Depth
TfliatlVejT
* 4ri*+£it*>$-f*H
•f Cuttings
1,389
8,477
2,029
11,895
1,528
9,325
2,232
13,085
1,256
8,368
2,176
11,800
1,213
8,081
2,101
11,395
1,155
8,642
2,343
12,140
1,361
10,180
2,760
14,300
2,110
7,999
860
10,969
3,313
7,334
1,334
11,981
4,120
5,962
1,478
11,560
Not Available
9,558
1,583
Not Available
4,017
5,745
2,068
11,830
6,065
7,606
2,326
15,997
B
3,823
6,240
2,100
12,163
7,504
8,838
3,024
19,366
AVERAGE
2,553
7,348
1,865
11,765
3,497
8,703
2,194
14,354
Source: EPA, July 19936
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3.3 DEWATERING LIQUID VOLUMES
Estimates of dewatering liquid volumes were obtained from two of the three drilling operations
visited by EPA in 1993.1-2 Referring to Table VH-2, the wells drilled to depths of 12,860 and 14,928 feet
generated estimated volumes of 4,800 and 2,423 barrels of dewatering liquid, respectively. Although a
larger hole volume is generally associated with larger volumes of waste fluids and cuttings, there is no
apparent relationship between we! depth and dewatering liquid volume. As explained in Sections 5.5.5
and 5.5.6, factors affecting the volume and quality of the liquid effluent from a dewatering process are
related to the selected dewatering method and the efficiency of the upstream solids separation equipment
rather than the well depth. The dewatering liquid from these two drilling operations was either recycled
into the active fluid system or hauled off-site for disposal; no dewatering liquid was discharged.
4.0 DRILLING WASTE CHARACTERISTICS
4.1 DRILLING FLUID CHARACTERISTICS
Several broad categories of drilling fluids exist such as water-based fluids (fresh or salt water), low
solids polymer fluids, oil-based fluids, and oil emulsion fluids. This section discusses only water- and oil-
based fluids because they represent the traditional and most widely used drilling fluids. A newer class of
drilling fluids using synthetic materials is discussed later in this chapter (see Section 5.11).
Oil-based drilling fluids are only used for specific drilling conditions because they cannot be
discharged and are more expensive to use than water-based drilling fluids. The discharge of oil-based
drilling fluids and associated cuttings is prohibited under the BPT limitations of "no discharge of free oil."
Industry has indicated that oil-based drilling fluids continue to be the material of choice for certain drilling
conditions.7 These conditions include the need for thermal stability when drilling high-temperature wells,
specific lubricating characteristics when drilling deviated wells, and the ability to reduce stuck pipe or hole
washout problems when drilling thick, water-sensitive shales. A primary concern when using conventional,
oil-based fluid systems is their potential for adverse environmental impact in the event of a spill. Because
of the relatively high toxicily of diesel oU, some mineral oil-based fluid systems have replaced diesel oil-
based fluids, and as discussed in Section 5.11, synthetic-based drilling fluids are being used in applications
previously reliant upon oil-based systems.
Water-based drilling fluids are dense colloidal slurries in a water phase of either fresh or saturated
salt mixtures. Salt water-based drilling fluids may be comprised of seawater, sodium chloride (NaCl),
vn-io
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potassium chloride (KC1), magnesium chloride (MgCy, calcium chloride/bromide (CaCyCaBr^, or zinc
chloride/bromide (ZnClj/ZnBr^. All freshwater fluids contain bentonite (sodium montmorillonite clay)
and caustic soda (NaOH), while saltwater fluids may contain attapulgite clay instead of bentonite. Clays
are a basic component of drilling fluids used to enhance the fluid viscosity. The most common required
drilling fluid properties and the additives used to enhance these properties are discussed below.
Several different formulations of drilling fluids and additives can be created to achieve the required
downhole conditions. The most common properties of the drilling fluid that the mud engineer controls are:
• Rheology (flow properties)
• Density
• Fluid loss control
• Lubricity
• Lost circulation
• Corrosion and scale control
• Solvents
• Low solids polymer fluids
• Bactericides.
Each of these properties can be tailored to specific well and drilling conditions through the addition of
active solids, inactive solids, and chemicals to the base drilling fluid. The EPA Offshore Development
Document discusses each of the above-listed properties, and describes the individual components of drilling
fluids as well as typical drilling fluid compositions.4 A comprehensive list of drilling fluid components and
their applications is provided in Appendix Vn-1.8
Barite, which is used to control the density of drilling fluids, is the primary source of toxic metal
pollutants. The characteristics of raw barite will determine the concentrations of metals found in the spent
drilling fluid system. A statistical analysis of metals concentrations in spent drilling fluids showed a higher
concentration of toxic metal pollutants in drilling fluids formulated with "dirty" barite than in those
formulated with "clean" barite.9
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Based on the results of this analysis, EPA developed a profile of metals concentrations in drilling
fluids formulated with "clean" barite as part of the development of Offshore Guidelines. "Clean" barite
is defined as stock barite that meets the maximum limitations of cadmium of 3 mg/1 and for mercury of
1 mg/1.4 Table VII-4 presents the estimated characteristics of drilling fluids and cuttings tailored
specifically for Cook Inlet since drilling wastes are discharged in this area only. Table VII-4 includes the
offshore metals concentration profile developed from the statistical analysis for "clean" barite. The only
difference to be noted is the concentration of barium, which was reevaluated hi this rulemaking effort
because the average weight of drilling fluid (10 Ib/gal) reported by Cook Inlet operators in the 1993 EPA
Coastal Questionnaire was lower than the average offshore model fluid weight of 11.0 Ib/gal. The revised
barium concentration for coastal regulations was calculated to be 120,000 mg/kg as compared to the
calculated concentration of 359,747 mg/kg estimated for the offshore model well.10
Mineral oil, which is used hi Cook Inlet drilling operations mostly to free stuck pipe, is a drilling
fluid additive that contributes toxic organic pollutants to the drilling fluid system. An operator in Cook
Inlet, Alaska estimated that the amount of mineral oil typically used in water-based drilling fluids is
approximately 0.02 percent.6 The concentrations of organic compounds listed hi Table VIM were
calculated based on this estimate,14 and on the average concentrations of organics in mineral oil as listed
in Table VII-9 hi the Offshore Development Document.4
The TSS attributable to drilling fluids is estimated based on two physical properties of the waste
drilling fluids: the estimated percentage of the fluid that is dry solids (11 %), and the estimated density of
the dry solids (1,025 Ibs/bbl).10 The dry solids content of the drilling fluid was estimated from mud reports
provided by the operator of one of the drill sites visited by EPA.' The density of dry solids was estimated
based on the mud weight of 10.1 Ibs/gal obtained from the mud reports,' and calculated by subtracting the
density of water (in Ibs/gal) from the mud weight.10 Finally, the TSS concentration in drilling fluid was
calculated as follows:
(0.11 bbl dry solids/bbl drilling fluid) x (1,025 Ibs dry solids/bbl dry solids)
= 113 Ibs dry solids/bbl drilling fluid
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TABLE VH-4
COOK INLET DRILLING WASTE CHARACTERISTICS
" Waste Characteristics
Percent of cuttings in waste drilling
fluid
Percent of drilling fluid adhering to
cuttings
Average density of dry cuttings
Average density of waste drilling
fluid
Percent of dry solids in waste
drilling fluid, by volume
Average density of dry solids in
waste drilling fluids
'" ;Valne ' ;
19%
5%
980 pounds per barrel
420 pounds per barrel
11%
1,025 pounds per barrel
Reference ? ''',''
1993 EPA Coastal Oil and Gas Questionnaire6
Ray, 1979"
Estimated12
1993 EPA Coastal Oil and Gas Questionnaire6
and Calculations13
Calculations10
Calculations10
• „--„ -Drilling Fluid Ecllutant Concentration Data , ,,.. ,»,,/„„„/ ,,,-" - ,«.-.; , ,-, ,
Naphthalene
Fluorene
Phenanthrene
Non-ConveatiohaiMetals *
Aluminum
Barium
Iron
Tin
Titanium
Non-Conventional. Grgani.cs '
Alkylated benzenes
Alkylated naphthalenes
Alkylated fluorenes
Alkylated phenanthrenes
Total biphenyls
Total dibenzothiophenes
- ' IbfflUbiofdrilling'fMd
0.0596
113.0
- - mg/kg dry drilling fMd
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
,;^,,,Jbs/bbtofdrffingflwd, ' ';
0.0000035
0.0000563
0.0000084
"' lug/kg-dry drffingifluid ' ^
9,069.9
120,000.0
15,344.3
14.6
87.5
Ibsft>bl of driHragjluid
0.0021017
0.0000344
0.0001218
0.0000143
0.0001360
0.0000004
'- " ' Reference
Estimated14
Estimated10
, , , "'•.'-.- - Reference
Offshore Development Document, Table XI-6"
Reference--- -' - -- <••,"-
Calculated14 from concentrations in Offshore
Development Document, Table VII-94
Reference"" \
Offshore Development Document, Table XI-64;
except for barium, which was estimated.10
; Reference
Calculated14 from concentrations in Offshore
Development Document, Table VTI-94
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4.2 DRILL CUTTINGS CHARACTERISTICS
Drill cuttings themselves are inert solids from the formation. However, drill cuttings discharges
also contain drilling fluids that have adhered to the cuttings. The composition of drill cuttings discharges
is directly dependent upon the fluid used. Cuttings associated with oil-based drilling fluids or from
petroleum bearing formations will contain hydrocarbons which adsorb on the surface of drill solid particles
and resist removal by washing operations. The volume of the fluid adhering to the discharged cuttings can
vary considerably depending on the formation being drilled, the type of drilling fluid being used, the
particle size distribution of the cuttings, and the efficiency of the solids control equipment. A general rule
of thumb is that five percent (5%) drilling fluid by volume is associated with the cuttings." Data from a
drilling project in the Outer Continental Shelf off southern California indicate that the cuttings discharges
from the solids control equipment were comprised of 96 percent cuttings and four percent adhered drilling
fluids,15
For the purpose of estimating pollutant reductions, the total suspended solids (TSS) concentration
attributable to drill cuttings is equivalent to the density of the dry weight of cuttings (980 Ibs/bbl).12 This
density was estimated from Cook Inlet geologic information provided by the industry,16 and the specific
gravities of low- and high-gravity solids,17 as follows:
» The first 500 feet of depth consists of high-gravity solids13 with a specific gravity of 4.5.17
* The depth from 500 to 10,000 feet consists of low-gravity solids13 with a specific gravity
of2.6.17
* 50% of the total cuttings volume is generated during the first 3,000 feet.*
* The average specific gravity for the first 3,000 feet (50 % of the total volume) =
[(4.5 x 500 ft) + (2.6 x 2,500 ft)] / 3,000 ft = 2.92
* The average specific gravity for the remaining depth = 2.6
* The overall specific gravity for drilling cuttings =
(2.92 + 2.6) / 2 = 2.8
• The average density of dry cuttings (using water at standard temperature and pressure as
a reference) =
2.8 x 350 Ibs water/bbl = 980 Ibs/bbl
vn-14
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4.3 DEWATERING LIQUID CHARACTERISTICS
During site visits to three southern Louisiana drilling operations, EPA collected samples of
dewatering centrifuge liquid to determine the quality of this process stream.1-2'3 This process stream
consisted mostly of the water phase of the drilling fluid.
At each drill site, one set of grab samples was collected on two consecutive days from the liquid
discharge from a decanting centrifuge that was part of the solids control system (see also Section 5.5.5).
The major difference between the three solids control systems was that two of them included chemical
treatment of the centrifuge influent to enhance liquid\solid separation, also referred to as chemically
enhanced centrifugation (CEC—see Section 5.5.6). The third system used no additional chemicals upstream
of the centrifuge. The result was that separation of the colloidal solids from the liquid phase was much
more efficient at the two sites using CEC. These samples were relatively free of suspended solids (TSS
ranged from 24 to 520 mg/1), while the untreated sample had to be analyzed as a solid due to its solids
content (23 % to 24.7%), and had the consistency of a drilling fluid.
Table Vtt-5 compares data obtained from the two sites that used CEC to effluent limits established
for this waste stream in a general permit covering drilling waste discharges in the coastal Gulf of Mexico
region (58 FR 49126). The dewatering liquid at these sites was being treated for recycle and not for
surface discharge. In fact, the majority of these waste volumes was hauled to commercial disposal.1-2 The
solids control contractor at one of these sites suggested that further treatment with activated carbon would
produce discharge-quality effluent.2
4.4 COOK INLET DRILLING WASTE CHARACTERISTICS
For the purpose of developing compliance cost and pollutant reduction estimates, particular
characteristics of drilling wastes in Cook Inlet, Alaska were identified. The sources for these data include
the 1993 Coastal Oil and Gas Questionnaire, the EPA Offshore Development Document, direct
correspondence with the operators, and calculations and estimates based on the data from these sources.
Table VTJ-4 lists the characteristics of interest, including densities of cuttings and drilling fluid, percentage
of solids in drilling fluid, and pollutant concentration data.
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TABLE VTI-5
COMPARISON OF ANALYTICAL CHARACTERISTICS OF CENTRIFUGE WATER
EFFLUENT FROM THE GAP ENERGY AND ARCO DRILLING SAMPLING EPISODES TO
THE EPA REGION VI GENERAL PERMIT POLLUTANT LIMITATIONS FOR DRILLING
OPERATIONS
Pollutant
Oil & Grease
TSS
TDS
COD
PH
Chloride
Arsenic
Barium
Cadmium
Chromium
Copper
Lead
Manganese
Mercury
Nickel
Selenium
Silver
Zinc
Units
mg/1
mg/1
mg/1
mg/1
S.U.
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/I
mg/1
mg/1
mg/1
mg/1
General Permit "
< Limitations1'
Texas
15
50
3,000
200
6-9
500
0.1
1.0
0.05-0.1
0.5
0.5
0.5
1.0
0.005
1.0
0.05-0.1
0.05
1.0
Louisiana
15
50
_
'125
6-9
500
—
_
__
0.5
_
_
__
_
_
5.0
< <"•"
11 (jfiAP Energy1
6/16/93
ND(l.O)
24
7,600'
1,040*
6.27
317
0.310
ND(0.018)
ND(0.004)
1.26*
ND(0.012)
ND(0.044)
3.84
ND(0.0002)
ND(0.026)
0.044
ND(0.010)
0.006
60.7193
1.0
35
6,420*
735*
8.95
866*
ND(0.018)
2.32
ND(0.002)
0.069
ND(0.006)
ND(0.022)
ND(0.003)
ND(0.0002)
ND(0.013)
ND(0.0258)
ND(0.005)
0.501
<•
•;
' AfcCQ*
*«
7/21/93
8.0
520*
14,000*
5,370*
7.48
2,050*
0.0766
0.667
ND(0.005)
4.59*
0.23
ND(0.047)
0.442
0.00115
0.0279
ND(0.02)
ND(0.004)
0.083
7/22/93
3.0
440*
15,200*
4,630*
7.4
2,150*
0.0679
0.696
ND(0.005)
4.42*
0.141
ND(0.047)
0.762
0.00075
0.0273
ND(0.02)
• ND(0.004)
0.198
1 58 FR 49126
Samples that exceed General Permit Limitations
vn-16
-------
5.0 CONTROL AND TREATMENT TECHNOLOGIES
This section includes discussions of drilling waste treatment technologies currently employed in
the coastal oil and gas industry. The technologies include the following:
• product substitution to minimize pollutant content
• closed-loop solids control systems to minimize waste stream volume
• reserve pits
• conservation and reuse/recycling.
In addition, EPA investigated the following disposal methods:
• land treatment/disposal
• subsurface injection of drilling fluids
• grinding and subsurface injection of drill cuttings.
5.1 BPT TECHNOLOGY
EPA has developed effluent limitations guidelines for the Coastal subcategory based on Best
Practicable Control Technology Currently Available (BPT), which represented the average of the best
existing technologies at the time of investigation. These standards were published on April 13, 1979 (44
FR 22069). At that time, EPA determined that drilling product substitution, or the use of more
environmentally benign products, combined with onshore disposal was the best practicable control method
available. An example of product substitution is the use of water-based drilling fluid in place of oil-based
drilling fluid such that the drilling fluid (and cuttings) discharged would pass the no-free-oil limit. Effluent
limitations based on this technology allow no discharge of free oil in drilling fluids and drill cuttings. This
limitation was implemented by requiring no oil sheen to be present upon discharge.
5.2 PRODUCT SUBSTITUTION - ACUTE TOXICITY LIMITATIONS
It has been shown that low toxicities can be achieved through the use of water-based drilling fluids
and low toxicity specialty additives.4 Thus, limitations based on acute toxicity would encourage operators
to substitute low toxicity additives in place of high toxicity additives. One BAT/NSPS control option
evaluated for the final rule includes the current offshore limitation of 30,000 ppm in the suspended
vn-i?
-------
participate phase (SPP) (see Chapters X and XDI). At proposal, EPA considered an option that would
have established a toxicity limitation in the range of 100,000 ppm to 1,000,000 ppm in the suspended
particulate phase (SPP). EPA subsequently determined that the data available were not sufficient for
establishing a toxicity limit more stringent than 30,000 ppm (see Chapters X and XIV).
5.3 PRODUCT SUBSTITUTION - CLEAN BARITE
Barite is a major component of drilling fluids which can represent as much as 70 percent of the
weight of a high-density drilling fluid. Barite has been shown to contain varying concentrations of metals
of toxic concern, particularly cadmium and mercury. Barium sulfate, the natural source of barite, has also
been shown to contain varying concentrations of metals depending on the characteristics of the deposit from
where the barite was mined. During the development of the Offshore Guidelines, a statistical analysis of
the API/USEPA Metals Database indicated that there is some correlation between cadmium and mercury
and other trace metals in the barium.9 Thus, regulating the concentration of cadmium and mercury in
barite would indirectly regulate other metals present hi barite (see Section VI.2.4). The Offshore
Development Document includes a detailed discussion of the findings of this analysis.4
5.4 PRODUCT SUBSTITUTION - MINERAL OIL
In addition to using low toxicity drilling fluids, low toxicity lubrication additives can reduce the
overall toxicity of the drilling fluid. For many years, diesel oil was the preferred additive for lubrication
purposes and for spotting jobs. EPA has evaluated other lubricants that have similar properties to diesel
but are less toxic. Mineral oil has become a common substitute for diesel oil as it can be used as a torque-
reducing agent and a spotting fluid.4
An OOC sponsored analysis of organic chemical characterization of diesel and mineral oils used
as drilling fluid additives indicated that there are similar constituents hi both diesel and mineral oils but at
significantly higher concentrations in the diesel.18 The analysis revealed quantitative differences hi the total
aromatic, total sulfur and organic sulfur contents, as well as in the concentrations of individual
polyaromatic hydrocarbons (PAHs, including benzene, naphthalene, biphenyl, fluorene and phenanthrene
alkyl homologue series) and sulfur- and nitrogen-polycyclic aromatic compounds (PAC) (debenxothiophene
and carbazole alkyl homologue series, respectively). Thus, the differences in amounts of these compounds
in mineral and diesel oils accounts for the lower toxicity of mineral oil.
vn-is
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In 1984, industry representatives acknowledged that mineral oil is an adequate substitute for diesel
as a torque-reducing lubricity agent.18 Several industry studies investigated the effectiveness of using diesel
oil versus mineral oil in freeing stuck pipe. The data gathered from these studies indicated mat: mineral
oil was commonly used by operations in the Gulf of Mexico, mineral oil is an available alternative to the
use of diesel oil, and success rates comparable to those with diesel oil can be achieved with mineral oil.
5.5 ENHANCED SOLIDS CONTROL: WASTE MINIMIZATION/POLLUTION PREVENTION
A widely recognized method of minimizing drilling waste volumes is the use of high-efficiency
solids control systems, sometimes referred to as "closed-loop" solids control systems or CLSs. The term
"closed-loop" is somewhat misleading in that it implies a closed system from which only waste cuttings are
removed. The system is not truly closed because, regardless of the system's level of efficiency, some
cuttings are always retained in the drilling fluid and some drilling fluid is always discarded with the
cuttings.19 While no single definition of the term "closed-loop" is available, definitions throughout current
literature generally describe closed-loop technology as the process of minimizing both the amount of waste
produced from an active drilling fluid circulation system and the amount of dilution required by the drilling
fluid.19'20-21 In practice, then, a CLS returns as much drilling fluid to the circulation system as is
economically and practically possible. The drill cuttings removed from the circulation system are
consequently reduced in liquid content and overall volume. While the practical application of solids control
systems cannot be 100 percent "closed," the CLSs currently in use in the coastal oil and gas industry are
measurably more efficient than conventional systems that utilize reserve pits and little or no waste
minimizing technology.
Following is a list of advantages to using CLS technology compiled from current literature:20'21-22
• Reduced dilution and associated displacement of drilling fluid, resulting in reduced drilling
fluid maintenance costs
• Reduced waste volume and disposal cost
• Reduced disposal costs offset increased costs for improved solids control
• Reduced total drilling location waste management costs
• Reduction or elimination of the need for an earthen pit and avoidance of significant site
closure costs at land-based sites
• Increased rate of penetration
vn-19
-------
• Increased drilling efficiency through optimization of drilling fluid solids content and
rheological properties
• Reduced trouble costs
• Minimal environmental impact
• Reduced waste transportation and disposal liability.
It is apparent in both industry literature and industry practices (as observed directly by EPA) (hat
closed-loop solids control technology is achievable using currently available equipment.''2>3>20 A typical
CLS consists of at least some of the following equipment, depending on the drilling program: shale
shakers, a sand trap, a degasser, hydrocyclones (desanders, desilters, microclones), a flocculation chemical
addition manifold, a dewatering centrifuge, and a barite recovery centrifuge if weighted drilling fluid is
used. Closed-loop solids control systems can provide greater than 90 percent solids removal efficiency
when flocculation enhancing chemicals are used.23 Without chemical addition, CLS efficiency ranges
between 72-75 percent.23 The following sections describe these unit processes as they are currently utilized
in closed-loop solids control systems.
5.5.1 Shale Shakers
Shale shakers, also called vibrating screens, are usually the first step in a solids control system.
The function of a shale 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. Variables
involved in shale shaker design include screen cloth characteristics, type of motion, position of screen, and
arrangement of multiple screens.
Screen characteristics are expressed as mesh size (the number of openings in a linear inch), opening
size, percent open area, and wire diameter. Typical mesh sizes range from 30 to 250.24 The type of screen
motion is determined by the eccentric weight or reciprocator (the vibrating device) and the suspension
system. Motion can be circular, elliptical, or straight-line. Screen position depends on the effectiveness
of the vibrating motion to move solids. Ideally, balanced circular or elliptical motion should move the
solids across the screen regardless of screen position. Tilting the screen might be necessary to overcome
problems brought on by unbalanced elliptical motion. Such tilting can cause an increase in drilling fluid
loss with the cuttings. Multiple screens are used when the solids load is too great for a single screen (or
under other problematic drilling conditions), and are used in one of two arrangements: series or parallel.
VII-20
-------
Staged (or "cascaded") screens in series are arranged so that the underflow of the first screen is the feed
to the second, and so that the coarser mesh screen comes first. Parallel arrangements can include multiple
screens on a single deck or side-by-side pairs of shale shakers. Some operators use two sets of shale
shakers in series, wherein the first shakers, referred to as "scalp" shakers, contain coarser mesh to remove
sticks and the largest particles, and the second set of shakers contain finer mesh.23
A term that is used to quantify the portion of solids that remain in the discharge as compared to
the solids that leave with the liquid underflow is the "median cut." This term is used to describe the
performance of all solids separation equipment in addition to shale shakers. The median cut-size particle
for a shale shaker screen is that of which half pass through and half remain on the screen. For a given
shale shaker (or any solids separation unit), a smaller median cut particle size indicates better separation
than a larger median cut particle size. The range of acceptable median cut particle size depends on
multiple factors for any particular unit. Factors that determine what the median cut will be for a given
shale shaker include the screen mesh size, screen opening shape (square or rectangular), the amplitude (or
distance) of the vibration, and the particle shapes. Not all particles smaller than the screen mesh get
through, and likewise, some oversize particles pass through due to their shape.
Common shale shaker problems include solids overloading and screen plugging (called "blinding").
Both problems cause the screen to be bypassed and thus reduce the liquid throughput. Solids overloading,
which may occur at times of increased drilling rate, can be overcome by adding a screen, either hi series
or in parallel. Blinding may be due either to a film of small particles that adheres to the screen and reduces
the effective open area or to near-size particles plugging the screen. The former case may be corrected
with a coarser mesh screen, and the latter might require a smaller mesh. Some shale shakers are equipped
with a spray bar that showers water over the cuttings on the screen to enhance mud/cuttings separation.
However, one source recommends that only temporary spray bars be used to apply a "mist" to sticky clay
cuttings and other problematic solids.25
Current innovative screening device designs include fine mesh (up to 400) screens capable of
processing drilling fluid through an effective area of up to 600 square feet per second under a slight
vacuum. Advantages of such designs include improved degassing capability and reduced free liquid on
the discarded solids.26
vn-2i
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5.5.2 Sand Traps
A sand trap is a settling tank positioned to receive the liquid underflow from the shale shakers.
This tank serves to "trap" sand and other large particles that bypass the shale shaker screens, either by
design or due to a problem with the shakers (e.g., torn screen, blinded screen, solids overload). This
settling protects the downstream equipment from wear due to abrasion. A properly designed sand trap is
not stirred (as are other tanks in the active fluid system), removes solids only through a bottom-opening
dump valve, and discharges mud over a retaining weir. Because large amounts of barite could settle out
in this quiescent tank, weighted fluids should bypass the sand trap, unless there are problems with the
shakers.27-28
5.5.3 Degassers
The purpose of a degasser is to remove gas and air from the drilling fluid which, due to its
compressibility, can have detrimental effects on the drilling fluid. In addition, centrifugal pumps used to
feed downstream equipment, as well as hydrocyclones, do not operate efficiently with gas-cut fluid.
Therefore, in a well designed system, a degasser is positioned after the sand trap and before the
hydrocyclone pumps.
Two basic designs of degassers include atmospheric and vacuum. Atmospheric degassers use
turbulence to separate bubbles from the drilling fluid, and vacuum degassers use a combination of
turbulence, thin film, and vacuum to perform the necessary separation. Available degasser performance
data indicate that atmospheric degassers work satisfactorily on lower-weight, lower-viscosity water-based
fluids as well as oil-based fluids.29 Vacuum degassers perform better than atmospheric degassers on
heavier fluids. However, when the yield point (a theological property) of the drilling fluid is below 10
lb/100 ft,2 shale shakers can remove enough of the gas to make degassing equipment unnecessary.27
5.5.4 Hydrocyclones
The hydrocyclones used in drilling fluid circulation systems are static units that have no moving
internal parts. Thrilling fluid is fed tangentially into a hydrocyclone under pressure. Separation of the solid
particles from the liquid occurs in these units by means of centrifugal forces imposed on the influent as it
spirals down the inside of the cone, which causes the heavier particles to move radially to the outer edge
of the stream. The underflow solid particles exit through the bottom of the conical housing and the liquid
overflow passes upward near the center and out through the top. Figure Vn-1 illustrates the flow patterns
VH-22
-------
OVERELOWLIQUID
DISCHARGE
FEED INLET
VORTEX HNDER
VORTEX
SOLIDS
UNDERFLOW
DISCHARGE
Figure VH-1
Hydrocyclone Mow Patterns
-------
within a properly operating hydrocyclone, as well as the nomenclature associated with hydrocyclone
technology.
Hydrocyclones are typically referred to as "desanders" and "desilters," depending on the size
particle they are intended to remove from the drilling fluid. Desanders are designed to remove particles
down to 40 microns in size, desilters remove down to 20 microns, and specially designed "microclones"
remove down to 10 microns (55 FR 23348). As a point of reference, human hair ranges hi size from 30
to 200 microns. Particles less than two microns are referred to as "clay," particles from two to 74 microns
are "silt,11 and particles greater than 74 microns are "sand."27 While there is no industry standard for the
distinction, desander cones generally range in size from six to 12 niches hi diameter, and desilter cones
range from two to five inches.30 The two-inch desilters are referred to as "microclones."
The cones of a desander are often arranged in two parallel rows of three each, for a total of six
cones. The liquid overflow from each cone enters a header which returns the combined overflows to the
next tank in the active drilling fluid system. Desilters often consist of two rows of six cones each. The
number of cones required depends on the size of each cone and the type of solids being handled. Cones
can also be arranged hi a circle around a common header.
The problems experienced by hydrocyclones include clogged inlet or exit flow holes and improper
flow adjustment. When the underflow opening is blocked, solids will exit the cone through the top with
the liquid overflow and return to the active drilling fluid system. When the feed stream is blocked, the
absence of the upward liquid flow can cause liquid overflow from adjacent cones to enter the cone from
the overflow header and be lost through the underflow opening. If the flow rate is improperly adjusted,
the hydrocyclone can become overloaded with solids, thus causing solid particles to exit with the overflow.
"Mud cleaners" were initially developed for weighted fluid systems for the purpose of capturing
solids that exit through the hydrocyclone underflow, thus allowing the weighting agents existing with the
solids to be returned to the system. A mud cleaner is a combination hydrocyclone-shale shaker designed
to remove sand-sized particles while returning medium and fine silt as well as clay-sized material to
theactive drilling fluid system. One source states that the purpose of this separation step is to reduce the
amount of barite make-up required by returning some solids that would otherwise be discarded by the
hydrocyclone.27 However, the return of the clay-bearing liquid should be stopped if viscosity becomes a
problem. Another source states that the purpose of the mud cleaner is to remove any API sand (between
VH-24
-------
74 and 178 microns) that is not removed by the primary shale shakers, and offers guidelines for proper
operation.29 With recent improvements in shale shaker screens and hydrocyclone performance, the need
for mud cleaners must be determined on a case-by-case basis.
5.5.5 Centrifuges
/
Centrifuges are used in solids separation systems to enhance the solids removal efficiency. For
example, use of centrifuges with standard rig equipment only, can boost a system's removal efficiency from
30 to 40 percent.31 Two centrifuge designs are currently in use in the solids separation systems: decanting
centrifuges and perforated rotor centrifuges (also called "RMS" for rotary mud separator).
Both the decanting centrifuge and the RMS can be used as "barite-recovery" units from which the
barite-laden solids are returned to the active drilling fluid system while the liquid (dewatering effluent) is
discharged or disposed. However, only the decanting centrifuge is used as a solids dewatering device,
from which relatively dry solids (fine cuttings) exit to a waste pile and the liquid may be returned to the
active drilling fluid system. The RMS is not capable of removing enough liquid from the solids fraction
to be used as a dewatering step in a closed-loop solids control system.23 Additional discussion regarding
the applications of these units is included in the next section.
The decanting centrifuge, illustrated in Figure VII-2, is equipped with a spiral conveyor housed
within a conical- or cylindrical-shaped bowl, both of which rotate hi the same direction. The conveyor
rotates at a slower speed than that of the bowl and the relative rotation between the two dictates the solids
conveying speed. Bowl rotation speeds range from 1,500 to 3,500 rpm, and the conveyor speed is
determined by the gear ratio, which may be controlled.
A typical gear ratio is 80:1 where the conveyor loses one revolution per 80 revolutions of the bowl,
such that a bowl speed of 1,500 rpm will correspond to a conveyor speed of 1,481 rpm and a relative
conveying speed of 18.75 rpm. Retention time within the unit ranges between 10 and 80 seconds.26
The performance of a decanting centrifuge is measured by the feed rate capacity, the solids
discharge capacity, and the liquid discharge capacity. The feed rate depends on the solids content of the
feed, such that a feed with a high solids content will be limited by the solids discharge capacity, and a feed
with a low solids content will be limited by the liquid discharge capacity. The solids discharge capacity
depends on the rates at which solids are conveyed and discharged through the openings. The liquid
VH-25
-------
I LIQUID/
DISCHARGES
DISCHARGE
LIQUID
[SOLIDS
Figure VII-2
Decanting Centrifuge24
-------
discharge capacity depends on the capacity of the openings to discharge liquid of a certain depth within the
bowl. A major development in decanter bowl design occurred in the early 1970's when a cylindrical or
"contour" bowl was introduced. With this design, the increased bowl volume allows for a higher feed rate
with the same separation achieved by a conical design. Due to their additional cost, contour bowl
decanting centrifuges are typically used to dewater waste solids and recycle liquid back to the active
system, rather than for barite recovery.27
The advantage of the RMS over the decanting centrifuge is that of portability. Because the solids-
laden underflow is liquid, it exits the unit through a pipe, thus allowing the unit to be positioned anywhere
in relation to the mud tanks. In contrast, a decanting centrifuge must be placed so that the solids fall
directly into the receiving vessel (either the mud tanks or a waste container) or onto a solids conveyor.
Figure VII-3 illustrates the operation of a RMS. The feed enters the unit through an opening in
the outer housing. The perforated rotor is the only part that rotates, causing the heavier particles to move
radially toward the wall of the outer housing. The liquid overflow enters the rotor through the perforations
and exits the unit through a pipe attached to the end of the rotor. The solids-laden underflow exits through
a pipe located in the outer housing located at the opposite end from the feed inlet. The rate at which the
underflow discharges is regulated by a choke valve in the discharge pipe. This choke also controls the
amount of liquid exiting through the overflow discharge. Normal operation with a water-based fluid
requires a dilution of ten parts feed mud to seven parts dilution water. This water must be compatible with
the active drilling fluid. Disadvantages to the RMS, as compared to a decanting centrifuge, include a
slightly higher barite loss, a high demand for dilution water, and a high rate of overflow discharge
requiring disposal.26 However, the smaller RMS is applicable in situations over water where there is no
room to move a decanter around the mud tanks.
5.5.6 Chemically Enhanced Centrifugation
Chemically enhanced centrifugation (CEC) is a term used to describe the addition of coagulation
and flocculation chemicals to enhance the effectiveness of a decanting centrifuge. CEC is also referred to
as "dewatering" because its purpose is to remove as much of the liquid phase from the feed to a decanting
centrifuge as is economically practical. The use of CEC systems is cited throughout current literature21-32'33
and has been observed recently by EPA.1-2 The CEC step is typically located where it can process the
discharge from other solids separation equipment such as desilters, desanders, and barite-recovery
VH-27
-------
. Rotor (rotating
perforated cylinder)
Stationary case
• Rotor shaft—perforated
Effluent
Underflow barite slurry
High density solids
HgnreVII-3
Rotary Mud Separator (RMS) Centrifug^4
-------
centrifuges. The products of this dewatering step are a damp solid discharge and a clarified liquid
discharge.
A CEC step is included in a CLS when it is necessary to remove colloidal particles (less than 5
microns) from the active drilling fluid system. If excess drill solids are not removed from a CLS, each pass
through the system causes the particles to degrade to smaller sizes making them increasingly difficult to
remove. The mechanical action of centrifugal pumps and shale shakers contribute to particle degradation.
An undesirable increase in drilling fluid weight and viscosity can occur when drill solids degrade, due to
the increased surface area of the smaller particles.33 Increased surface area causes increased water
consumption. Drill solids degradation can be controlled through the choice of drilling fluid and additives,
which can consequently increase the efficiency of the mechanical solids control equipment. Additionally,
removing colloidal solids with a CEC step prevents returning detrimental particles to the active drilling
fluid system.
Chemical treatment is needed to remove low-gravity particles (below 5 microns in size) which are
not removed by centrifugation alone.33 These small particles must first be treated with coagulant to reduce
the radius of their electric charge (called "zeta potential") which repels them from particles of like charge.
Flocculent is then added to allow the coagulated particles to come together (or "bridge") into larger groups
of particles that can be removed by a decanting centrifuge. High molecular weight polyacrylamides are
commonly used for flocculation.34
The degree to which the discharged liquid is clarified depends on its intended disposition, either
as recycle back to the active drilling fluid system, or as waste to be disposed in some manner (including
annular injection, surface discharge, or off-site disposal). The solids discharged from a CEC unit are
typically 35 to 75 percent water by volume.21 If the discharged liquid is to be returned to the active drilling
fluid system, it must be compatible with the drilling fluid.
Finally, it is important to note that onsite dewatering of spent drilling fluid is typically practiced
only when an economical onsite method of disposal or reuse is available for either the dewatering liquid
or the dewatered solids. Such methods include onsite land disposal of the solids and injection of the liquid
into either the annulus of the well being drilled or an available disposal well. When an economical means
of disposing or reusing the products of dewatering is not available, the least expensive method of handling
these wastes is to remove the dewatering step and haul the spent drilling fluid to an offsite disposal facility.
VH-29
-------
5.5.7 Closed-Loop Solids Control System Design
To better understand the design of a closed-loop solids control system, it is important to discuss
the basic applications of each unit in relation to the active drilling fluid circulation system. Table VII-6
describes various applications of solids separation equipment used with unweighted and weighted drilling
fluid systems.27 The distinction between whether a separation step is primary or secondary is determined
by the origin of the feed stream to a particular unit: a primary separation step is fed directly from the active
drilling fluid circulation system, and a secondary step is fed from a primary step. Also of concern is
whether a separation unit is designed to handle a flow rate equal to the total drilling fluid circulation rate
("full" flow) or a fraction thereof ("partial" flow).
As shown in Table VE-6, the location of a centrifuge within a solids control system varies
depending on its application. Both decanting and RMS centrifuges can be located as primary separation
units when used to recover barite from a weighted drilling fluid. In this primary application, the centrifuge
processes the entire volume of recycled drilling fluid. A decanting centrifuge, the only centrifuge useful
for dewatering purposes, may be located in a secondary position to receive either desilter underflow or
barite recovery centrifuge overflow. This secondary separation step processes only a fraction of the total
drilling fluids system volume.
Figure VII-4 illustrates a system in which the shale shakers, degasser, desander, and desilter, are
operated in primary full-flow, and the decanting centrifuge is operated as secondary separation of the
hydrocyclone underflow. This example is an unweighted drilling fluid application. The system
arrangement illustrated in this figure is typical of CLSs used to minimize solid waste volume and to recycle
water back into the active drilling fluid system. Table Vn-6 demonstrates that there is often more than one
piece of equipment capable of performing a given separation task. The choice of equipment is usually the
result of an analysis weighing the drilling program operating parameters and conditions against overall cost.
Current literature cites the fact that poor choices of solids separation equipment were prevalent in the 1980s
due to a general misunderstanding of the operating principles of each unit.25'27 However, it is apparent that
more operators are taking a closer and more careful look at solids separation technology as a means of
reducing drilling fluid make up costs as well as drilling waste generation and costs.
. CLS systems change with operating conditions, even during the same drilling operation. For
example, a CLS might consist of multiple shale shakers, hydrocyclones, and a dewatering centrifuge during
the drilling of the surface interval of the hole where an unweighted water-base fluid is used and the rate
vn-so
-------
TABLE VII-6
SOLIDS SEPARATION EQUIPMENT APPLICATIONS"
Bear-
1
2
3
4
5
6
7
8
9
*' ^Tjrge.ofBuiipnjenl /
Shale shaker screens
Desanding hydrocyclones
Desilting hydrocyclones
Decanting centrifuges
Perforated rotor centrifuges
Special barite cyclones
Decanting centrifuges
Decanting centrifuges
Special screens
'Separation-
Primary
Primary
Primary
Primary
Primary
Primary
Secondary
Secondary
Secondary
,/ Typ&of'FlojJ ,-,
Full
Full
Full
Partial
Partial
Partial
(Desilter underflow)
(Barite recovery
overflow)
(Desilter underflow)
'Chat^cjer of ihe Discard ,
Wet to damp
Wet
Very wet
Low-volume liquid
Medium-volume liquid
High volume liquid
Damp
Damp
Wet to damp
, f/^ * ',, "" , " Application^) * '„ , „' ,-•-,,,
Remove coarsest particles (cuttings) and protect downstream separation
units. Use with both unweighted and weighted fluids.
Remove sand-size particles (down to approx. 40 microns). Use with both
unweighted and weighted fluids. With oil-base fluids, use only when
followed by items 7 or 8.
Remove silt-size particles (down to approx. 20 microns). Use with both
unweighted and weighted fluids.
Remove clays and soluble materials (in free liquid overflow) for viscosity
control in a weighted water-base fluid. This application is often called a
"barite-recovery" centrifuge. Mis-application if used on unweighted fluid
or on oil-based fluids."
Remove clays and soluble materials (in free liquid overflow) for viscosity
control in a weighted water-base fluid. This application is often called a
"barite-recovery" centrifuge. Mis-application if used on unweighted fluid
or on oil-based fluid."
Remove clays and soluble materials (in free liquid overflow) for viscosity
control in a weighted fluid. With oil-base fluids, use only when followed
by items 7 or 8. Mis-application if used on unweighted fluid.
Dewater solids from hydrocyclone underflow and return free liquid
overflow to the drilling fluid system. Useful in areas where 1) water is
expensive, or 2) solid waste minimization is necessary. Mis-application if
used on weighted fluid.
Dewater solids from barite recovery overflow and return free liquid
overflow to the drilling fluid system. Useful in areas where 1) water is
expensive, or 2) solid waste minimization is necessary.
Remove selective solids from hydrocyclone underflow and return free
liquid overflow to the fluid system.. This application is called a "mud
cleaner" when used on a weighted fluid, and is intended to reduce barite
usage. Usually a mis-application if used on an unweighted fluid.
a Adapted from Ormsby, 1983."
b Another industry source reports using barite-recovery centrifuges on weighted mud regardless of whether it is water base or oil base."
-------
Drilling Fluid and Cutting!
from Wellbore
Cascaded
Shale Shaken
Course Solids
to Disposal
Drilling Fluid
Return to •<-
Wellbore
« .»'.*•••.'. ..'.•«.
Hydrocyclone Underflow
Figure VlI-4
Example Closed-Loop Solids Control System
(Unweighted Drilling Fluid Application)
/
-f-
Clay-Bearing
Liquid Recycled
T
Dewatered Solids
to Disposal
-------
of drill cuttings production is greatest. Then as the fluid is weighted up and the rate of penetration
decreases, one of the shale shakers might be removed and a barite-recovery centrifuge might replace the
desilter. If a formation of reactive clay is reached, flocculation chemicals and associated equipment might
be added at that point. Examples of these and other CLS design considerations are cited in current
literature.36
As part of the Costal guidelines development, EPA visited three drill sites in southern Louisiana,
each of which utilized closed-loop solids control technology.Ii2'3 Figures VH-5, VH-6, and VH-7 depict
the solids control systems used at the three sites.
The CLS used at the GAP Energy drill site (Figure VH-5) included a CEC step to separate water
from spent drilling fluid for recycle back into the active drilling fluid system. A unique feature of the GAP
site is that in addition to the solids control equipment provided with the drilling rig, another suite of solids
control equipment was brought onsite by the solids control contractor. Depending on the requirements of
the drilling program, it is not uncommon for the solids control contractor to substitute part or all of the rig-
supplied equipment. The ARCO drill site (Figure VH-6) included a barite recovery centrifuge and a CEC
step to separate and recycle water from the barite recovery centrifuge overflow. Chemical addition was
minimized at ARCO to keep fluid treatment chemicals in the recycle water. Thus, the water samples
obtained from the dewatering centrifuge at the ARCO site were significantly darker than the water samples
obtained at the GAP site. Based on visual inspection, samples from both sites were free of setdeable solids.
The CLS system used at the UNOCAL site (Figure vn-7) was similar to the ARCO system, except that
no chemicals were added to the feed to the dewatering centrifuge. By comparison, then, the water sample
from the UNOCAL site was considerably more turbid than the samples obtained at the other sites,
containing total solids ranging from 23 % to 24.7% .3
5.5.8 Solids Control System Efficiency
Table Vn-7 lists solids control system efficiencies from various literature sources. These numbers
are not statistically comparable due to the lack of information available regarding the methods by which
they were calculated. However, it is interesting to observe that efficiency increases dramatically for
systems using chemically enhanced centrifugation over those relying only on mechanical means.
The difference in CLS efficiencies with and without chemical addition was apparent from the
systems observed during EPA's three drill site visits. All efficiencies reported by the solids control
VH-33
-------
Mud -Cam in Ua
Pumpt' or 1
Heppvr
W«a Bora
Ptlmmtf
SoSd*
Central
Systtrn
Soldi
Central
System
Figure YII-5
GAP Energy Mini Redrculation and Solids Control System
VH-34
-------
No) In UK on
Diy QEB of Sampling
Figure VII-6
ARCO Mud Recirculation and Solids Control System
-------
Wei
c
Cuttings ____
l_
Ibore
-^ Mid
J*
-— 1 3 Parallel
Shale Shaker:
1 ' 140 -250 Mesh
Degasscr
Mud (Optional)
t I
Sand Degasser . Mud
Trap Pit Tank
,.1- A
JL '» .Mud
Desilter W W
V
Cuttings ^J-— ~1 Linear Motion
1 1 Shaker
1 250 Mesh
/'"V
- R
r><
R
Mud
Pumps Mud
/ / (
*& Mud ^ Mud ST Mud 'i
Tank Tank Tank
j > ^
Barite
^_ Solids ._
Barile _
Mud^ R,rnvr,» * DeCalUl
'" Centrifuge Cenlrilu
Mud
Solids
. Sample
Point
— i Liquid
1E Overflow
«e
\ Shale Barge I
Figure VII-7
UNOCAL Mud Recirculation and Solids Contol
for 11.700 ft to 13.500 ft
-------
TABLE Vn-7
CLOSED-LOOP SOLIDS CONTROL SYSTEM EFFICIENCIES
. - , v, - -t - Source- „ ,
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Finke, Aug. 18, 199325
Finke, Aug. 18, 199325
Wojtanowicz, 198837
Wojtanowicz, 198837
^ Equipment Used* \ ;
1
2
1
3
3
1
2
4
5
6
6
* ^ " " Vv,-. - -
Reported Efficiency -
^ 90
99.967b
99.945b
Classes of equipment:
1: Rig shale shakers, desander, and desilter only.
2: Rig equipment plus rental mud cleaner and centrifuge.
3: Unitized system: 2-4 parallel shale shakers, desander mud cleaner, desilter mud cleaner, microclone, low-speed
centrifuge, and high-speed centrifuge.
4: Unitized system: two sets of shale shakers (in series), desander mud cleaner, desilter mud cleaner, and dewatering
centrifuge.
5: Same as 4 plus flocculation chemicals and finer hydrocyclones.
6: Dewatering centrifuge and flocculation chemical addition only
Wojtanowicz studied different sizes of dewatering centrifuges with flocculation chemical addition and reported the best
two efficiencies observed as measured by weight % of the solids in the centrifuge liquid effluent compared to the centrifuge
feed.
contractors at these sites are general values for the equipment used, as illustrated hi Figures VII-5, VII-6,
and VII-7. None of the efficiencies were directly measured on-site. The solids control contractors at both
the GAP and ARCO sites reported efficiencies of approximately 90% when chemical flocculation was
used.1-2 The contractor at the ARCO site estimated efficiencies of 72-75% for the same equipment when
chemicals are not added.2 Similarly, an efficiency of 75% was reported for the system used at the
UNOCAL site, where chemical flocculation was waived due to the availability of annular injection of the
VH-37
-------
decanting centrifuge overflow.2 By comparison, Cook Inlet operators reported in the 1993 Coastal Oil and
Gas Questionnaire an average efficiency of 69 percent for the closed-loop solids control systems.6
5.6 RESERVE PITS
Although their use has been phased out in Alaska and is being phased out in much of the coastal
Gulf of Mexico region, reserve pits are still employed within the coastal subcategory. A reserve pit is an
earthen pit (lined or unlined) that is used to contain drilling fluids and wastes such as drill cuttings,
discharges from solids control equipment, location drainage, drilling fluid, excess cement, equipment wash-
down water, and completion/workover fluids. In addition, the pit contents can be used as reserve fluids
in the event that the drilling fluids in the active system are lost to the formation.21-38 Different types of
earthen pits (lined or unlined) are used at land-based drilling sites to manage both solid and liquid materials
and wastes.
Pit construction is based on the volume of waste to be placed in the pit. Industry sources suggest
that, when sizing the pit, the smallest practical volume be used.39 This minimizes the size of a land-based
drilling location. In addition to drilling wastes, the reserve pit also accumulates precipitation, thus a
smaller pit will accumulate less over the course of drilling operations. An industry source indicated that
the pit should be designed using the assumption that two barrels of drilling waste will be generated for
every foot of hole drilled.39
Reserve pits are designed to prevent migration of pit contents. This is achieved through the use
of adequate berm (levee) height to maintain freeboard in the pit to prevent overflow of pit contents.
Louisiana regulations specify that a minimum two feet of freeboard be maintained in the pit at all times
(Louisiana Administrative Code, Statewide Order 29-B). In addition, low-permeability soils or synthetic
liners are used to prevent the pit contents from leaching during the course of drilling operations.
In terms of site layout, two types of approaches to reserve pit construction are documented in
current literature. The following sections discuss conventional reserve pits, which are the historically
traditional approach to land-based drilling waste management, and "managed" reserve pit systems, which
reflect current industry efforts to segregate and minimize wastes at the drill site.
VH-38
-------
5.6.1 Conventional Reserve Pits
In a conventional reserve pit system, one pit is used to contain all of the drilling wastes at the
drilling location. These wastes may include drill cuttings, spent drilling fluid, location drainage, excess
cement, equipment wash water, and completion/workover fluids. A footprint area of 200 feet by 300 feet
would normally be required for a conventional reserve pit at a drilling location with an approximate well
depth of 14,000 to 18,000 feet.40 Assuming a levee ten feet wide encloses the pit, the actual surface
dimensions of the pit would be 180 feet by 280 feet. Pit construction companies indicate that the average
conventional reserve pit is 200 feet by 200 feet.41-42 The pit is generally five to six feet deep but depths of
eight and ten feet are also used.42 The depth is limited by the height of the water table. Figure VII-8 is
a layout of a typical drilling location where a conventional reserve pit has been used to manage drilling
fluids and wastes. Pit construction companies also indicate that they are frequently asked to segment or
partition the conventional reserve pits.41-42
5.6.2 Managed Reserve Pits
The following text is adapted from a paper presented by EPA at the SPE/EPA Exploration and
Production Environmental Conference held hi San Antonio, Texas hi March 1993.43
A managed reserve pit is a waste segregation system that uses two or more pits to prevent
contaminated wastes from coming in contact with uncontaminated materials. This can occur when using
a conventional reserve pit while drilling into salt formations, if the well experiences a salt-water kick, or
if oil-based fluid or fluid containing barite is used for drilling.44 The number and size of the individual pits
or cells depend on the number and volume of distinct waste streams expected to be generated during
drilling operations. For instance, one cell would be sized and constructed as the reserve pit to
accommodate the volume of drilling fluid required for the operation plus an adequate freeboard. A second
cell would be constructed to manage cuttings, a third cell for rainwater runoff which may also be used for
rig wash and drilling fluid make-up water. An important design consideration of the managed reserve pit
system is to ensure that natural communication between the cells is prevented. The transfer of material
between pits is handled using a dragline or manually controlled pumps.
The entire managed reserve pit system can be constructed in an area that would be occupied by
a conventional reserve pit.40 Thus, while the overall footprint of the managed pit system is comparable to
that of a conventional reserve pit, a benefit is derived from keeping contaminated waste separated from
waste that might be recycled, reused, or disposed of at a lower cost.
VH-39
-------
Pit Levee Wall
Waar
Rt
Reserve Pit
Solids Control
Equipment Discharges
Location
Dniruge
Sump
Ring Levee Ditch
Figure VII-8
Layout of a Prilling Location Utilizing a Conventional Reserve Pit
Location
Drainage
Sump
vn-40
-------
The operation of a managed reserve pit system is summarized as follows.40 Solids and residual
drilling fluids are discharged to the shaker pit from the solids control equipment. Solids from the shaker
pit are transferred to the storage pit and fluids are transferred to the settling pit along with rain water and
equipment wash water. Following settling, the water is transferred to the treatment pit. Reserve pit
treatment often includes lime addition to raise the pH, followed by aeration by mixing the pit contents.
Such treatment clarifies the water by causing the solids to settle out. From the treatment pit, water is
recycled for continued use in the drilling operations or discarded as waste. The status of the managed pit
system is evaluated on a daily basis and consists of assessing the volume of wastes in the system and the
distribution of these wastes among the pits in the system.
5.6.3 Pit Closure and Site Restoration
The regulations in the States of Louisiana and Texas specify requirements for pit closure and
approved disposal methods for pit contents (Louisiana Statewide Rule 29-B; Texas Statewide Rule 8). The
closure and disposal requirements (applicable to conventional and managed reserve pits) include:
• Dewatering and backfilling
• Solidification
• Landfarming and backfilling
• Injection (liquids)
• Burial on-site (solids)
• Treatment and discharge (liquids)
• Off-site commercial disposal.
In locations where discharge is prohibited, disposal of drilling wastes can be accomplished via on-
site annular injection, on-site landfarming or burial,21'41 injection into a dedicated UIC Class n disposal well
(either on- or off-site) or hauling off-site for land application at either a centralized commercial facility or
a non-commercial site.
Following disposal of pit contents by any of the methods mentioned above, the reserve pit(s) is
backfilled with the earthen levee material and/or stockpiled soil from initial excavation of the pit(s). The
area may then be graded and restored to predrilling conditions.40-45
-------
5.6.4 Reserve Pits on the North Slope
Reserve pits were initially the drilling fluids and cuttings disposal method of choice on the North
Slope. A discussion of the use of reserve pits and other land disposal methods unique to Alaska is included
in. the document entitled "Oil and Gas Exploration and Production Wastes Handling Methods in Coastal
Alaska".46 However, the North Slope operators have ceased using reserve pits and now rely on a grinding
and injection system for drilling waste, described in detail in Section 5.10. The unused reserve pits are
in the process of being closed out in accordance with requirements issued by the state of Alaska.47 See also
Section 2.3 for a discussion of the applicability of reserve pit wastes to the final coastal guidelines.
5,7 CONSERVATION AND REUSE/RECYCLING
The emergence of the closed-loop solids control system has provided operators with one of the best
means of reducing wastes generated and increasing recycling opportunities. Additionally, reuse and
recycle is particularly desirable for fluids that have a hydrocarbon (diesel or mineral oil) liquid base or
synthetic-based material because they cannot be discharged or are expensive. Economically attractive reuse
practices for spent oil-based and synthetic-based drilling fluids are:
* Drilling fluid company buys back the used drilling fluid which is hauled to shore,
processed, and reused.
* The spent drilling fluid is treated with additional solids-suspending agents and used as a
packer fluid.
5.8 LAND TREATMENT AND DISPOSAL
This section discusses land-based treatment and disposal methods for drilling wastes at onsite and
centralized commercial land treatment and disposal facilities. In addition, this section discusses current
land disposal methods in Cook Inlet, Alaska.
5,8.1 Onsite Landfarming
Onsite landfarming of drilling wastes' is a potential option in cases where there is adequate space,
the soil conditions are suitable, and the oil company is the land owner or has permission from the land
owner to landfarm.
VH-42
-------
The landfarming process consists of spreading a thin layer of the drilling waste over the landfarm
area. After spreading the drilling waste, the top soil and humus layer that was stripped in the preparation
phase of the drill site is spread over the drilling waste with a nitrogen fertilizer. The drilling waste, topsoil,
and fertilizer are mixed through cultivation with a set of disks or a tractor-mounted tiller. The
cultivation/fertilizer cycle is repeated about twice a year for two or three years. The time period is
dependent on the quantity and the concentration of the drilling waste applied to the soil and the size of the
application area.48 The area can be successfully re-vegetated once the hydrocarbon content hi the soil is
less than one percent and the chloride content in the soil is less than 1,000 ppm.48 Seed germination studies
have revealed that landfarming operations can be re-vegetated within 180 days.49
Microbial decomposition is the major cause of hydrocarbon reduction in landfarming, although
evaporation and volatilization of the light-end hydrocarbons is probably significant.49 To maximize
microbial decomposition, the most important aspects of landfarming are to maximize the surface contact
between the drilling waste and soil bacteria, to aerate the soil/drilling waste mix to promote aerobic
decomposition, and to boost the soil microbe count by providing additional nutrients hi the form of high
nitrogen fertilizer. The two commonly used fertilizers are 34-0-0 and 11-51-0 (nitrogen-phosphorous-
potassium ratio). Fertilizer application rates are typically on the order of 1,000 pounds per acre.48
In one study, metals were analyzed hi samples of waste/soil mixtures treated by landfarming and
hi leachate collected from under plots of treated mixture.49 The total metals measured in the treated
waste/soil mixture did not exceed guidelines for limiting constituents for land application. In the leachate,
lead was measured at levels exceeding drinking water standards, and selenium was measured equal to
drinking water standards. While the study made no general conclusions regarding the effectiveness of
landfarming on metals, it was observed that49:
• flyash is more effective than native soil hi reducing the rate of leaching of soluble salts,
• adsorption of barium on clay particles may remove it from solution,
• the presence of high levels of chlorides can increase the solubility of barium,
• arsenic hi drilling fluids is not an environmental threat if the pH is maintained between 3
and 12.
vn-43
-------
EPA's costing analysis of drilling waste disposal (Chapter X) did not include onsite landfarming,
but rather assumed that all wastes would be either injected onsite (see Section 5.10) or sent to commercial
disposal facilities (see below).
5.8.2 Centralized Commercial Land Treatment and Disposal Facilities
Centralized commercial facilities are treatment and disposal and/or processing facilities that are
located offsite from the drilling operation and are generally not operated by an oil and gas operator. In
Louisiana, the Department of Natural Resources permits non-hazardous oil field wastes (NOW) facilities,
and in Texas, the Railroad Commission of Texas permits NOW facilities.
Centralized commercial treatment facilities receive drilling wastes in vacuum trucks, dump trucks,
cuttings boxes or barges. la Louisiana, the transportation of drilling wastes in barges is common because
of the high frequency of drilling projects occurring hi coastal waters. Coastal treatment facilities also
receive barged drilling wastes from offshore drilling operations. One major commercial waste treatment
facility in Louisiana has treatment facilities with barge access and several transfer stations with barge
access.50
Most of these facilities employ a landfarming technique whereby the wastes are spread over small
areas and are allowed to biodegrade until they become claylike substances that can be stockpiled outside
of the landfarming area. Another common practice at centralized commercial facilities is the processing
of drilling waste into a reusable construction material. This process consists of dewatering the drilling
waste and mixing the solids with binding and solidification agents. The oil and metals are stabilized within
the solids matrix and cannot leach from the solids. The resulting solids are then used as daily cover at a
Class I municipal landfill. Other potential uses for the stabilized material include use as a sub-base for road
construction and levee maintenance.51
The treatment process most often employed at land treatment facilities consists of a cycle which
includes application, treatment, certification, and excavation. The treatment phase is designed to address
heavy metals, sodium imbalances hi the waste, chloride concentrations in excess of the state regulatory
limits, oil and grease concentrations in excess of the regulatory limits and moisture contents. Commercial
landfarming facilities typically treat waste in cells designed for a particular amount of waste. When the
maximum amount of waste has been applied to a cell, the treatment process begins.52
vn-44
-------
The landfarming treatment process for one commercial NOW facility located in southeast Louisiana
is described in the following paragraphs.50-52
The treatment cells at this facility range in size from 1.5 to 6 acres and consist of above-ground-
level structures surrounded by berms built up to a height of 6 to 8 feet. Topsoil is removed prior to cell
construction. Clay deposits under the topsoil serve as natural barriers to groundwater contamination. The
clay acts to prevent cell leachate drainage to groundwater and to prevent groundwater infiltration into cells
where there is a high natural water table.
The application phase of treatment consists of filling the cell with incoming drilling waste. The
maximum application that the state of Louisiana allows is 15,000 barrels per acre over a three month
period. Approximately 20 tons per acre of gypsum or calcium sulfate is spread and mechanically mixed
with the waste. Through a classic ion exchange chemical reaction, the calcium from gypsum or calcium
sulfate replaces the sodium on the soil particles. This step is necessary in reducing the exchangeable
sodium percentage (ESP) of the soil. The ESP is a measure of the number of exchange sites on the soil
particles which are occupied by sodium ions. The Louisiana regulations for landfarming limit the ESP
concentration to 25 percent.
The next step of the treatment phase is flooding of the cell to remove the soluble salts from the soil-
waste matrix. Approximately 6 to 12 inches of water is pumped onto the cell and mixed with the waste
with mechanical equipment. The higher salt concentrations in the waste drive the concentrations up in the
fresh water, thereby lowering the concentrations in the waste. Once the chloride concentrations reach an
equilibrium and the water ceases to absorb more salts (at approximately 1,500-2,000 ppm), the solids are
allowed to settle out of the water and the water is pumped out of the cell into a surface impoundment prior
to injection. The salt removal step is an important step in maximizing the biodegradation process because
many microorganisms do not function well in a high salt environment. The treatment process has taken
about four to six months at this point.
The next step of the landfarming process consists of treatment of the oil and grease content of the
waste. The oil and grease content is lowered by mixing the waste with the soil and through biodegradation.
This treatment step consists of cultivation of the soil/waste mixture to improve exposure to the sun and air
which maximizes biodegradation. The matrix in the cell is cultivated twice a month for a period of six to
eight months.
VH-45
-------
Once all the material in the cell is treated and all the analyses are below the state-required
limitations, the "cleaned" clay-like product is transferred from the cell to a stockpile area onsite. This
material is used to maintain or construct new berms around the cells.
EPA determined that existing land disposal facilities in the areas accessible to the Gulf of Mexico
offshore and coastal oil and gas subcategories have 5.5 million barrels annual capacity available for oil and
gas field wastes.4 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.4
5.8.3 Cook Inlet Land Disposal
There are currently no commercial land disposal facilities permitted in Cook Inlet. There are,
however, two non-commercial land disposal facilities in Cook Inlet. These are: Marathon/UNOCAL
Landfill at Kustatan (west side of Cook Inlet), and UNOCAL Beaver Creek Landfill on the Kenai
Peninsula. Marathon and UNOCAL jointly operate the disposal site at Kustatan, located 3 miles north of
the Trading Bay facility. The Beaver Creek landfill is limited to accepting drilling wastes generated only
at the Beaver Creek Production facility.53 Other operators do not have access to land disposal facilities in
the Cook Inlet region and would have to transport drilling wastes to land disposal facilities located in other
states. One operator responding to the 1993 Coastal Oil and Gas Questionnaire reported transporting
drilling wastes to a landfill located hi Idaho.6 Another available landfill is located in Oregon (see
Chapter X).
The site at Kustatan is a landfill that has been used for the disposal of a limited volume of drilling
wastes and tank bottoms. This facility is authorized to receive wastes from the same platforms as do
Trading Bay and Granite Point facilities.53 The landfill consists of lined cells into which wastes are placed
and stabilized. The size of the landfill is 16 modules, each module containing 4 lined cells, for a total size
of 64 cells. Each cell can hold approximately 2,000 cubic yards or 9,620 bbl of material, for a total
capacity of 615,680 bbl. Once a cell has reached full capacity, it is covered and closed. When one module
reaches capacity, a new module is developed.53 To date, only 19,240 bbl of wastes have been disposed
at Kustatan.54 This facility is only accessible and operated in the summer months because of its location
and the harsh climate conditions in Cook Inlet. Due to the shallow waters on the west side of Cook Inlet,
only barges can be used to transport the wastes to the west side of Cook Inlet for disposal.
VH-46
-------
5.9 SUBSURFACE INJECTION OF DRILLING FLUIDS
Subsurface injection of spent drilling fluids is an established oil field practice, although its
availability is limited to those areas with access to viable receiving formations. If the solids control system
at a well includes a dewatering step, the resulting liquid stream may also be injected if it is not being
recycled into the drilling fluid system. Subsurface injection can be either through the annulus of an existing
casing system, as shown in Figure VII-9, or into a UIC Class n injection well. The process consists of
pumping the fluid down hole into a receiving formation. Prior to injection, drilling fluids are typically
screened using a shale shaker to remove any large particles. The typical drilling fluid injection system
consists of a shale shaker, mud tank, and pump. Triplex (three-plunger) pumps are commonly used as
injection pumps. Maintenance of all flow rates, pressures, and injection zones is the responsibility of the
oil company hi accordance with the requirements of the permit.
5.10 GRINDING AND SUBSURFACE INJECTION OF DRILLING WASTE
The process of grinding and injection of drilling muds and cuttings was developed by operators on
the North Slope Alaska in mid-1980's. This process is currently being used on the North Slope for the
injection of spent drilling fluids and cuttings. EPA has learned that several similar projects have also
occurred or are planned in coastal areas hi the Gulf of Mexico and California,55 and in the North Sea56 for
the injection of drilling fluids and cuttings. The following sections discuss these projects.
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 hi the following sections.
5.10.1 Cuttings Processing System and Injection
The cuttings grinding system consists of three separate unit processes: screening, grinding, and
slurrification. On the North Slope, cuttings are first conveyed to a large triple-deck classifier where the
cuttings are washed with high pressure water to remove residual drilling fluid and are sorted according to
size. The underflow from the classifier, which contains particles smaller than 74 microns, and the
washwater are sent to the injection slurry pit. The overflow, which contains particles larger than 74
microns, are further processed hi a ball mill grinding unit.57
VH-47
-------
Ground
Surface
0 ft
69 ft
2,530 ft
**£»£!£
m
y:M
Drilling Muds
7,000 ft
Drilling Muds
and Cuttings to
Surface
«w
s£
:••••"•
Approximate
Drilled Depth
at End of
Sampling
11,990 ft
16 in. dia. Conductor Pipe
Driven from 0 to 69 ft
13.5 in. Drill Bit
10.75 in. Casing
Set from 0 to 2,530 ft
Annular Injection
Actual Total Depth 12,860 ft
Zone where
Annular Injection
of Drilling Waste
May Occur
,-i *»*<*•.
^ 1^^
;ii ^
*' ^v;^*
:-"" "?*'"i*
J.-ft
fp
**^»
Jc*1"
||y : Muds and Cuttings
M? : Cemented Zones
Not to Scale
Drill Bit
Figure VH-9
Annular Injection During Drilling
vn-48
-------
The grinding unit is a 30-inch by 34 inch chamber that contains 3,000 Ib of 1.5-inch forged steel
balls. The cuttings are fed into this chamber for size reduction. In order to achieve the required particle
size, the chamber is vibrated at 1,200 cycles with an amplitude of 3/4 inch.57 After size reduction in the
ball mill, cuttings are pumped to a hydrocyclone for further classification. Particles larger than 74 microns
are returned to the ball mill for repeated grinding, while particles smaller than 74 microns are sent to the
injection pit.
The injection pit has a capacity of 500 barrels and is mechanically agitated to maintain a
homogeneous slurry. Chemicals such as bentonite and extenders are added to the pit to increase the solids
carrying property, or viscosity of the injection fluid. The injection fluid is typically maintained at a funnel
viscosity of 100 seconds per quart.57
The final step of this process is the injection system. Ground and slurried cuttings are pumped
from the injection pit to the injection pump(s) by hard chrome-lined centrifugal pumps.57 The centrifugal
pumps have a pumping capacity of 500 gallons per minute (gpm). One operator uses a pair of positive
displacement piston injection pumps, each with a pumping capacity of 210 gpm. These are 165-
horsepower (hp) triplex pumps driven by a 150 hp electric motor through a four-speed gearbox. The
injection pressure varies between 600 to 1,000 psi depending on the weight of the fluid being injected.
Typically, the density of the injection fluid is maintained within 10 to 11 pounds per gallon (ppg) with a
solids content of 25 to 30%.57
Successful grinding and injection projects in the Gulf of Mexico coastal region were cited by one
company licensed to perform this technology.58 Drill cuttings generated from drilling operations in the
coastal Gulf of Mexico region often consist of bentonitic shale formations which break up easily when
hydrated and subjected to high shear pressures. Because of these cuttings properties, the grinding and
injection systems employed hi the Gulf of Mexico coastal projects take advantage of the transfer pumps'
shear force for size reduction.59 Freshwater or seawater are added to the cuttings stream before and after
size reduction. After size reduction, the cuttings slurry is further mixed with freshwater or seawater so
that the injectable fluid has a funnel viscosity of 70 to 90 seconds per quart and a density of 11 to 12 ppg.58
Similar grinding and injection processes were successfully tested on other drilling fluid systems,
mainly on oil-based fluids and cuttings.56'60'61 With the new grinding and injection technology available and
proven on oil-based fluids and cuttings, the use of oil-based fluids followed by grinding and injection may
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prove in some cases to be more economical than land disposal, thus further reducing the overall well cost.
The cuttings processing systems employed on these projects are similar to the system used on the North
Slope. Variations of this process consist of the type of screens used, elimination of cuttings washing
systems, and the type of grinding equipment used. Rotating ball mills instead of vibrating ball mills have
been successfully used on offshore platforms. Although rotating ball mills are high maintenance pieces of
equipment, they are usually employed on offshore platforms for grinding large and relatively high density
material. Vibrating ball mills are not typically used on offshore platforms because of the possible structural
impact of the weight and of vibration.16-56
5.10.2 Receiving Formation Evaluation—North Slope Operations
The injection mechanism for solids-laden fluids differs from that used for solids-free liquids such
as produced water. Produced water is injected at a pressure that does not fracture the receiving formation.
On the North Slope, successful cuttings injection operations demand that a fracture be created in the
receiving formation before injection of the cuttings slurry can occur. Without a fracture, the solids in the
slurry would quickly plug up the pore spaces in the formation.62
Therefore, the success of the grinding and injection technology depends on the proper selection
of the receiving formation. In general, the desired characteristics of the receiving formation are to be
unconsolidated, of high porosity (typically 20%), high permeability (typically 0.5 Darcy) material of
sufficient thickness (typically 33 feet) and at a sufficient depth not to affect the surrounding environment.
The specific values, however, change for different drilling locations.63
Injection of a homogeneous cuttings slurry can be achieved through a dedicated wellbore or
through the annular space between a string of casing and the exposed formation. The slurry is pumped at
a specified rate into the wellbore or the annulus. When the downhole pressure of the fluid exceeds the
formation pressure, the formation fractures and the cuttings slurry flows into the fissure. The pumping
operation continues until all slurry is injected into the formation.
The optimum injection pressure depends on the characteristics of the receiving formation, and
should be continuously monitored. The mechanisms of inducing a fissure in the formation, such as its
mode of propagation, its size, its containment, and its impact on nearby wellbores, should be well
understood before injecting the cuttings slurry. Fracture modeling can be used to estimate the size and
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shape of the injection fracture. A new 3-dimensional model has been developed to optimize the design of
hydraulic fractures and to simulate drill cuttings injection.64
Subsurface geology of the North Slope is uniform throughout the area, making disposal of drilling
wastes by injection an attractive alternative to land disposal. North Slope geologic stratification is more
suited to injection because of the shale and sandstone formations, and because of the permafrost which
underlies most of the North Slope.
Shale, which is composed entirely of clays, is a relatively plastic and low permeability rock. These
properties make it a good confining zone. The fracture gradient for shale ranges from 0.8-0.9 psi/ft. For
comparison purposes, sandstone (a rock composed of sand sized rock and mineral fragments) has a fracture
gradient of 0.55-0.65 psi/ft.65 The lower the fracture gradient, the easier the formation will fracture.
Therefore, sandstone is a better receiving formation than shale because it fractures more easily, while shale
is a better confining formation.
Of importance to the oil and gas operations on the North Slope is the continuous permafrost which
descends from the surface to depths between 1,000 and 2,000 ft.57 The permafrost provides a low
permeability barrier so that the injected wastes do not migrate upward towards the surface.
5.10.3 Availability of Subsurface Injection
As stated above, the uniformity of the underlying geology of the North Slope makes injection of
drilling wastes a viable disposal method throughout in that area. In the coastal Gulf of Mexico area, a
statistical analysis of the responses to the 1993 Coastal Oil and Gas Questionnaire indicates that 122 new
production drilling projects, or 65% of the 187 new production wells drilled in 1992,6 utilized annular
injection for disposal of drilling wastes.66
While injection has been demonstrated in other parts of the U.S., injection has not been
demonstrated in Cook Inlet. EPA believes that the ability to inject is related to the subsurface conditions
of the receiving formations. While the geology of the formations in areas other than Cook Inlet have been
favorable to injection of drilling fluids and drill cuttings, the record indicates that geology amenable to
grinding and injection does not appear to occur throughout Cook Met.
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Drilling fluids and drill cuttings can not be injected into producing formations, as is sometimes the
case for produced water, because they would interfere with hydrocarbon recovery. Thus, operators must
have available different formation zones with appropriate characteristics (e.g., porosity and permeability)
for injection of drilling fluids and drill cuttings. Unlike the coastal region along the Gulf of Mexico or the
North Slope of Alaska, where the subsurface geology is relatively porous and formations for injection are
readily available, the geology in Cook Inlet is highly fragmented and information ha the record indicates
that formations amenable to injection may not be available throughout Cook Inlet. EPA reviewed
information where attempts to grind and inject drilling fluids and drill cuttings failed in the Cook Inlet
area.68 For example, one operator attempted to operate a grinding and injection well in the Kenai gas field
that failed due to downhole mechanical failure of the injection well (1992/1993). There, the well
experienced abnormal pressure on the well annulus, necessitating shutdown of the disposal operation.46 The
operator also attempted annular pumping of drilling fluids and drill cuttings hi two production wells hi the
Ivan River Field (onshore on the west side of Cook Inlet) where the annuli of both wells plugged during
injection. Another operator, attempting to pump drilling waste into the annuli of exploration wells, lost
the integrity of the well.16 In view of these difficulties encountered hi injecting drilling wastes and the
limited data available to date, EPA is unable to estimate the degree to which injection would be available
in Cook Inlet and beh'eves that the information hi the record indicates that certain sites hi Cook Inlet may
not be able to inject sufficient volumes of drilling wastes to enable compliance with zero discharge.
5.10.4 Cuttings Washing and Reuse on the North Slope
On Alaska's North Slope, while all drilling fluids and most drill cuttings are injected, some cuttings
are cleaned and used as fill material hi the construction of drill pads.57 These fill materials require a fill
permit issued pursuant to section 404 of the Clean Water Act. According to the North Slope operators,
shallow drill cuttings generated from the first 3,500 feet of drilling are very similar hi composition to
gravel that is used as a foundation material for roads and oil field facilities. Based on an agreement with
the Alaska Department of Environmental Conservation (ADEC), North Slope operators are allowed to
clean and reuse these cuttings as gravel as long as the cuttings meet certain criteria. The operators
developed the "Drill Cuttings Reclamation Program" to minimize the volume of larger cuttings requiring
grinding and injection and to reduce the need for gravel mining.67
The CC2A facility, located in the Prudhoe Bay oil field, processes all drilling wastes generated in
the Prudhoe Bay area oil fields. This facility contains impactors to handle larger gravels, ball mills for
further particle-size reduction as needed, and pumps for injection into the CC2A Class II disposal well.
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As of June, 1995, the CC2A facility has disposed of about 70,000 cubic yards of solids from drilling
wastes.68 At this facility, the gravel is washed and classified utilizing a shale shaker, water spray bars,
mixing tanks and pumps. Cuttings are sprayed with high-pressure water to remove drilling muds and fine
clay-sized particles. Washed cuttings larger than 1/8 of an inch in diameter are stored pending chemical
analysis and approval for reuse.69
Approval for reuse is contingent on meeting a set of reuse criteria established by ADEC. The
reclaimed gravel must be greater than 1/8 inches in diameter, generated within the first 3,500 feet, and be
drilled with water-based mud systems (lists of drilling mud additives must be supplied to and approved by
ADEC prior to reuse should these conditions not be met), and must meet the following standards:
Arsenic 22 mg/kg
Barium 790 mg/kg
Lead 20 mg/kg
Total Petroleum Hydrocarbons 200 mg/kg
(Diesel Range Organics - EPA method 8100M)
Particle Sizes 74fj. or less < 5 %
If the arsenic standard is violated, a secondary analytical procedure may be performed. In this
case, a sample of the gravel is subjected to a leachability test, and the extract may contain no more than
0.016 mg/L arsenic.70
5.11 SYNTHETIC-BASED DRILLING FLUIDS
Synthetic-based drilling fluids or synthetic-based muds (SBM) represent a new technology which
was developed in response to the oil-based drilling fluids discharge ban in the North Sea. They were first
used in the North Sea in 1990, and the first well drilled in the Gulf of Mexico using SBM was completed
in June 1992.71 Compared to the discharge of water-based muds (WBM) and cuttings and barging/hauling
of cuttings from oil-based muds (OEM), the use of the synthetics and on-site discharge of associated
cuttings is claimed to present a pollution prevention opportunity. From 1992 to mid-1996, roughly 250
to 300 wells in the Gulf of Mexico had been drilled with SBM, and for the most part the cuttings have been
discharged on site. The cuttings are typically coated with 7-12 percent synthetic material.72'73
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An SBM has a synthetic material as its continuous phase and water as the dispersed phase. The
types of synthetic material which have been used include vegetable esters, poly (alpha olefins), linear alpha
olefins, internal olefins, and ethers. Of the 250-300 estimated SBM wells drilled in the Gulf of Mexico,
approximately 47 percent were internal olefin-based, 34 percent were poly (alpha olefin)-based, and 19
percent were vegetable ester-based. More recently internal olefin-based SBMs have been almost
exclusively used. The synthetic materials are produced by the reaction of specific chemical feedstock,
resulting in products of defined and narrow molecular composition and structure. They are differentiated
from the traditional oil base fluids such as diesel and mineral oil which are derived from crude oil solely
through physical separation processes and minor chemical reactions such as cracking and hydroprocessing.
This physical separation results hi products having a broad range of hydrocarbons as opposed to the
specific products resulting from the chemical synthesis reactions to form the synthetic materials.
Since the cuttings wastestream from SBM was nonexistent during the start of this Coastal
rulemaking, no specific limitations for SBM have been set and they are covered by the same set of
requirements as the other drilling fluids hi this rule. EPA recognizes the potential pollution prevention
opportunities presented by this new technology. EPA is encouraging their further development and use
by providing definitions for "synthetic-based drilling fluid" and the "synthetic material" which comprises
the SBM, and is providing interim guidance for current SBM discharges in areas not covered by a zero
discharge of drilling fluids and cuttings. Because of concerns over the appropriateness of the sheen and
toxicity tests as applied to the discharge of cuttings associated with SBM, EPA is suggesting the use of
additional tests to allow discharge where zero discharge requirements are not in effect and for possible use
in evaluating environmental impacts. Tests of interest include determining impacts of the synthetic-
contaminated cuttings pile on the seafloor through the evaluation of benthic toxicity, bioaccumulation
potential, and rate of recovery of the seafloor by measurement of biodegradation rate. Such tests are
already applied for SBM cuttings discharges in the North Sea.72 Impacts due to the discharge of WBM and
associated cuttings fall into two main categories: water column and seafloor. The 30,000 mysid shrimp
LCjo toxicity limitation as it is applied to WBM can measure effects on both the water column and seafloor
since the discharged material does disperse into the aqueous phase during testing. However, for SBM a
much more distinct separation occurs during toxicity testing and very little if any of the synthetic material
is present in the aqueous phase. Consequently, hi order to properly compare the discharge of muds and
cuttings of WBM versus SBM the seafloor effects should be considered as well as the water column effects.
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SBMs are reported to perform as well as or better than OEMs in terms of rate of penetration,
borehole stability, and shale inhibition. Due to decreased washout (erosion), drilling of narrower gage
holes, and lack of dispersion of the cuttings hi the SBM, compared to WBM the quantities of muds and
cuttings waste generated is reduced, reportedly hi some cases by as much as 70 percent.74-75 The greatest
reduction seen is for the drilling fluids. The SBM offer the opportunity for high recycle rates because
unlike the WBM the cuttings do not disperse in the fluid and so less dilution and additives are required to
keep the necessary mud characteristics. In general the only SBM discharged is the amount adhered to the
cuttings, which ranges from 7 to 12 percent based on dry cuttings weight.73 When WBM is used, the mud
discharged is often 5 or 6 times greater than that discharged when drilling a similar hole with SBM. If the
engineering aspects of the effectiveness of a drilling fluid are considered as a technology to reduce the
levels of pollution, then SBM may be viewed as a control technology for conventional pollutants.75
When WBM and cuttings are discharged they disperse in the water and create muddy-looking
water, and the particles settle according to size and density. Conversely, since the synthetic materials are
hydrophobic and the mud is weighted, when cuttings coated with SBM are discharged minimal dispersion
in the water column is observed, the water hi general stays clear, and the cuttings rapidly sink to the
seafloor. Thus water column effects are greatly reduced and the seafloor effects are of a different nature
due to the adhered synthetic material loading.
Concerning the water column effects, comparisons can be made between the mysid shrimp LC50
suspended particulate phase (SPP) for the WBMs versus the SBMs. The toxicity of WBMs is dependent
on their formulation and addition of toxic components added for drilling performance. Acute toxicity tests
of eight generic WBM gave LG;0 values ranging from 27,000 ppm to over 1,000,000 ppm.4 Data collected
hi 1985 and 1986, before the 30,000 parts per million LQo limitation was promulgated, found that
approximately 42 percent of the used drilling fluids tested for toxicity were below (more toxic than) the
30,000 ppm value.4 In choosing the 30,000 ppm limitation EPA considered the many available
formulation possibilities and determined that the toxicity limitation of 30,000 ppm was achievable and
would significantly reduce the discharges of toxic muds without significantly affecting drilling activity.
Thus the WBMs are typically formulated to meet the 30,000 ppm limitation plus a safety factor. The
SBMs, on the other hand, typically report mysid shrimp LC50 values of greater than 1,000,000 ppm, in
other words, greater than 50 percent survival in 100 percent suspended particulate phase. In addition,
unlike with the use of WBMs, toxic additives are not generally needed in SBMs to enhance performance.
However, when compared to WBM, this reduction hi aquatic toxicity may be due to the lack of the
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synthetic material dispersion and dissolution in the aqueous or SPP phase which reduces exposure to the
mysid shrimp, as well as decreased inherent toxicity.76 In general, evidence shows that use of SBM in
place of WBM will reduce adverse environmental impact in the water column because of a) reduction in
volume discharged, b) less dispersion hi water, and c) lower aquatic toxicity.
Seafloor effects can be separated into two types: short-term burial effects and long-term toxic
effects.76 The adverse impact caused by burial can be assumed to be directly proportional to the quantity
of solids discharged, and will also depend on the dispersion of the settling solids. As discussed earlier the
use of SBMs has shown to create a lower volume of drilling wastes. Also, the cuttings which are coated
with 7-12 percent of the synthetic material, tend to sink without drifting hi the water column unlike the
particulate matter of the WBM which tends to disperse and stay suspended longer. Therefore as compared
to WBM the burial footprint from SBM cuttings discharge is expected to be smaller and have less solids.
This diminished dispersion of the SBM has been shown by relating barium concentrations on the
seafloor.71-77
Therefore, compared to WBM the SBM are believed to have lower aquatic toxicity and cause less
seafloor burial. The other impact of concern is the toxic effect of the cuttings pile as indicated by the rate
of recovery of the benthic organisms hi the pile. One research article details the history of a cuttings pile
generated with a poly (alpha olefin) SBM and compared the recovery with a cuttings pile associated with
an oil-based mud (OBM).71 The organic loading from the oil based mud caused alterations hi the benthic
community, and the area of contamination was observed to remain nearly constant since discharge during
the five year test period. Meanwhile the zone of contamination of the SBM was observed to reduce about
86 percent during the first eight months after discharge, but then remained constant during the next 16
months. The zone of impact to the benthic community for the OBM was described as encompassing 98,178
square meters after five years, whereas mat for the SBM was said to be affecting an area of only 589
square meters after just two years. Thus this study shows that changing the toxicity, degradability, and
bioaccumulation of the oily or hydrophobic constituent of the cuttings can have a large affect on the
recovery of the benthic community. Each synthetic material is expected to exhibit a unique set of benthic
toxicity, biodegradation, and water column toxicity, and there are likely to be tradeoffs. For instance,
compared to the poly (alpha olefin) of the referenced study, internal olefins are reported to exhibit higher
toxicity, but they degrade faster.73 Thus the rate of recovery with the internal olefins may be faster than
that found for the poly (alpha olefin), and may be more comparable to recovery with WBM.
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A separate investigation in the North Sea sampled the seafloor two days after and one year after
the discharge of 749 tons of cuttings contaminated with 97 tons of a vegetable ester.78 The presence of the
polychaete (worm) Capilella capitata in the cuttings pile two days after drilling ceased was cited as an
indication that the recolonization process had started. Reportedly, the recolonization of OEM cuttings piles
starts only several weeks after discharge. In one year the vegetable ester cuttings pile was found to be in
a natural state with a normal diversity and number of benthic organisms, except at one station where there
was a dominant population of the opportunistic polychaete Capitella capitata. The vegetable ester
concentrations had been greatly reduced, and the sediment grain size distribution had returned to normal.
A conclusion of the study was that the seafloor environmental impact due to discharge of the vegetable
ester contaminated cuttings was of comparable magnitude to that of benign water based muds.
A study performed in the Gulf of Mexico at well sites where WBMs and cuttings were discharged
found that due to the drilling activity concentrations of metals in the area were of such concentrations to
potentially cause long-term adverse effects.79 Since there is a great reduction in the muds and cuttings
discharged with SBMs, one can infer that there would also be a reduction in metals discharged and so this
adverse impact would be reduced.
Most germane is a comparison of the recolonization of WBM cuttings piles compared to that of
SBM cuttings piles. While WBM cuttings piles are said to recover "quickly" in the literature, data have
not been found in any source which defines just how quickly to compare with the SBM recovery, which
itself has only been detailed in the two above mentioned instances. Just recently detailed monitoring at
several sites in the North Sea has begun to evaluate several different mud systems and to compare the
actual seafloor determinations with the laboratory determinations.72 While evaluations in the Gulf of
Mexico may prove to be different from those in the North Sea due to the differences in physical parameters
and sea life, EPA will be following these seafloor evaluations closely for early indications of appropriate
laboratory and field evaluation methods.
In summary, there is conclusive evidence showing that discharge of SBM cuttings, as compared
to discharge of WBM spent mud and cuttings, reduces adverse water column effects and seafloor physical
burial effects. At the same time, within the smaller footprint, on the seafloor, adverse toxic or chemical
effects may or may not be increased due to the organic loading of the synthetic materials and concurrently
decreased due to reduced toxic metals loading. Site specific factors of ocean currents, water and sediment
physical parameters, and local benthic species, may also affect the predominance and extent of any short
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term or long term toxic effect. Investigations are now under way in the North Sea, and the EPA
recommends similar investigations in the Gulf of Mexico, to quantify the difference in the rate of benflric
recovery between WBMs and the various viable SBMs. In this way the environmental benefits of SBM
can be appropriately weighed against purported environmental liabilities.
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February 23-25, 1993.
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61. Crawford, H.R., and Lescarboura, J.A., "Drill Cuttings Reinjection for Heidrun: A Study," SPE
26382, Presented at the 68th Technical Conference SPE in Houston, TX, October 3-6, 1993.
62. Andersen, E.E., Louviere, R.J., and Witt, D.E. "Guidelines for Designing Safe, Environmentally
Acceptable Downhole Injection Operations." SPE 25964. Presented at the SPE/EPA Exploration
& Production Environmental Conference, San Antonio, TX., March 7-10, 1993.
63. Dusseault, M.B., and Bilak, R.A. "Disposal of Produced Fluids by Slurry Fracture Injection."
Geomechanics Group Publication. Presented at the 4th Petroleum Conference of the South
Saskatchewan Section, October 18-20, 1993.
64. Van den Hoek, P. J. "New 3D Model for Optimized Design of Hydraulic Fractures and Simulation
of Drill-Cutting Reinjection." SPE 26679. Presented at the Offshore European Conference in
Aberdeen, September 7-10, 1993.
65. AOGCC (Alaska Oil and Gas Conservation Commission). Letter to Manuela Erickson, SAIC,
regarding "disposal injection of UIC Class n waste within the State of Alaska." October 27, 1993.
66. Henderson, Scott. SAIC. Memorandum to Jamie Mclntyre, SAIC, regarding the "Estimated
Number of Wells using Annular Injection" from the 1993 Coastal Oil and Gas Questionnaire.
December 20, 1994.
67. Jordan, R., U.S. EPA, Teleconference with Laurie Mann, EPA Region 10, and Joe Sautner, Jim
Chatham, and Judd Peterson, Alaska Department of Environmental Conservation, regarding "Drill
Cuttings Reclamation Program," April 2, 1996.
68. Alaska Oil and Gas Association, "Comments On U.S. Environmental Protection Agency 40 CFR
435 Effluent Limitations Guidelines, Pretreatment Standards, and New Source Performance
Standards: Oil and Gas Extraction Point Source Category, Coastal Subcategory; Proposed Rule,"
June, 1995.
69. Peterson, J., Pad CC2A Cutting Recycle and Class n InjectioiLEacility BP Exploration. Western
Operating Area. March 6, 1996. Attachment to April 2, 1996 letter from Laura Ogar, ADEC, to
Ron Jordan, U.S. EPA.
70. Horstman, J., Avanti, Memorandum to Ron Jordan, U.S. EPA, regarding "North Slope Drill
Cuttings Reclamation Program," August 12, 1996.
71. Candler, J. E. et ah, "Seafloor Monitoring for Synthetic-Based Mud Discharged hi the Western
Gulf of Mexico," SPE 29694 presented at the SPE/EPA Exploration & Production Environmental
Conference held hi Houston, TX, March 27-29, 1995.
72. Davies, J.M., "Advising on the Control of Discharges of Synthetic Muds," SOAEFD Marine
Laboratory, 1995.
73. Friedheim, J.E., and H.L. Conn, "Second Generation Synthetic Fluids in the North Sea: Are
They Better?," SPE 35061 presented at IADC/SPE Drilling Conference held in New Orleans, LA,
March 12-15, 1996.
VH-63
-------
74. Burk, CJ. and J.A. Veil, "Potential Environmental Benefits from Regulatory Consideration of
Synthetic Drilling Muds," Argonne National Laboratory Technical Memorandum ANL/EAD/TM-
43, February 1995.
75. Candler, I.E., A.J.J. Leuterman, and J.H. Rushing, "Synthetic-Based Mud Systems Offer
Environmental Benefits Over Traditional Mud Systems," SPE 25993 presented at SPE/EPA
Exploration & Production Environmental Conference held in San Antonio, TX, March 7-10, 1993.
76. Rushing, J.H., M.A. Churan, and F.V. Jones, "Bioaccumulation From Mineral Oil-Wet and
Synthetic Liquid-Wet Cuttings in an Estuarine Fish, Fundulus grandis," SPE 23350 presented at
the First International Conference on Health, Safety and Environment held in The Hague, The
Netherlands, November 10-14, 1991.
77. Booth, P.N., and B J. Presley, "Trends in Sediment Trace Element Concentrations Around Six
Petroleum Drilling Platforms in the Northwestern Gulf of Mexico," Drilling Wastes. F.R.
Engelhardt, J.P. Ray, and A.H. Gillam (eds.), Elsevier (1989). (Offshore Rulemaking Record
Volume 183)
78. Smith, J. and SJ. May, Ula Wellsite 7/12-9 Environmental Survey 1991, Field Studies Council
Research Centre, Fort Popton, Angle, Pembroke, Dyfed, U.K., November 1991.
79. Kennicutt, n, M.C., ed. 1995. Gulf of Mexico Offshore Operations Monitoring Experiment,
Phase I: Sublethal Responses to Contaminant Exposure. Final Report. OCS Study MMS 95-0045.
U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico OCS Region,
New Orleans, Louisiana. 709 pp.
VH-64
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CHAPTER VIII
PRODUCED WATER-
CHARACTERIZATION, CONTROL AND TREATMENT TECHNOLOGIES
1.0 INTRODUCTION
The first three parts of this section describe the sources, volumes, and characteristics of produced
water from coastal oil and gas production activities. The final part of this section describes the treatment
technologies available to reduce the quantities of pollutants in produced water discharged to surface water.
2.0 PRODUCED WATER SOURCES
Produced water is the water (brine) brought up from the hydrocarbon-bearing strata during the
production of oil and gas. Produced water includes: the formation water brought to surface with the oil
and gas, the injection water used for secondary oil recovery that has broken through the formation, and
various well treatment chemicals added during production and the oil/water separation process.
Formation water, which comprises the bulk of produced water, is found in the same rock formation
as is the crude oil and gas. Formation water is classified as meteoric, connate, or mixed. Meteoric water
comes from rainwater that percolates through bedding planes and permeable layers. Connate water
(seawater in which marine sediments were originally deposited) contains chlorides, mainly sodium chloride
(Nad), and dissolved solids in concentrations many times greater than common seawater. Mixed water
is characterized by both a high chloride and sulfate-carbonate-bicarbonate content, which suggests multiple
origins.
3.0 PRODUCED WATER VOLUMES
Produced water is the highest volume waste source in the coastal oil and gas industry. The total
volume of produced water being discharged by the coastal oil and gas industry is 119.2 million bpy (or
326,577 bpd). The volume of wastewater generated by the oil and gas industry is somewhat unique in
comparison with industries in which wastewater generation is directly related to the quantity or quality of
raw materials processed. By contrast, produced water can constitute from 2 percent to 98 percent of the
gross hydrocarbon fluid production at a given well or production facility. In general, the percent of
Vffl-1
-------
produced water volume to oil and gas is small during the initial production phase when hydrocarbon
production is the greatest, and increases as the formation approaches hydrocarbon depletion. Produced
water volumes are generally greater for facilities producing oil or a combination of both oil and gas as
compared to gas-only facilities. The volume of produced water at a given facility is a site-specific
phenomenon. In some instances, no formation water is encountered while in others there is an excessive
amount of formation water encountered at the start of production.
As discussed in Chapter IV, the entire volume of produced water generated in the North Slope
region of Alaska and the coastal region of California is injected for waterflooding, and therefore will not
be discussed in this chapter. In addition, in the Gulf of Mexico states of Florida and Alabama, all coastal
facilities inject their produced water, primarily for disposal, and therefore, are not discussed in this chapter.
Also, a significant number of facilities in Texas and Louisiana coastal areas are currently injecting their
produced water, or are required to do so by January 1997. Produced water characteristics for those coastal
areas discharging it (i.e., Cook Inlet, Alaska and Texas and Louisiana) are discussed below.
3.1 GULF OF MEXICO
For the Gulf of Mexico region, the three sources of data that are available for produced water
volumes are: the 1993 Coastal Oil and Gas Questionnaire database, the Gulf of Mexico state discharge file
information and the 1992 EPA 10 production facility data. These three data sources are discussed in detail
in Chapter V. Because the Coastal 308 Questionnaire was not a census, the data concerning produced
water volumes and other parameters from the survey were statistically extrapolated as estimated industry-
wide averages. The Gulf of Mexico state discharge file information contains comprehensive facility-
specific data, but only includes facilities that are discharging. The 1992 EPA 10 production facility study
contains data from 10 selected facilities that primarily inject produced water. The following is a summary
of the produced water flow data from these three sources.
According to the statistical analysis of the EPA 1993 Coastal Oil and Gas Questionnaire, hereafter
referred to as the coastal questionnaire statistical results, the average produced water generation rate from
a coastal facility was 1,923 barrels per day (bpd) for facilities that inject produced water and 2,069 bpd
for facilities that surface discharge produced water.1
Table Vni-1 presents the produced water volumes, treatment systems information, and
hydrocarbon production from the production facilities sampled in EPA's 10-facility study. Details of this
vra-2
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TABLE Vin-1
CHARACTERISTICS OF THE 10 PRODUCTION FACILITIES SAMPLED BY EPA3
;\';;;0^to^^fAf;
- ', ">* '•-!;"> "C~ > -; ; ;; ,» ^ ' '"
Greenhill Petroleum
Oryx Energy
Exxon Corporation
Oryx Energy
Texaco
Texaco
Arco
Texaco
Badger Oil Corp.
Texaco
Average
-T^iv^*' -•;>
f-f ' ? ,* *W$
-• '•••><;-.>•>.••.•',*..&
Bully Camp
Chacahoula
Clam Lake
Caplen
Sour Lake
Port Neches
Bayou Sale
Bayou Sale
Larose
Lake Salvador
-
••*, *,* ' '*;" "^ ^ ^'"-A
'LV'^MSf:,,!
1,050
213
518
186
300
210
1,485
2,381
200
950
749
' J'%f&*'^-
11
24
0
35-50
0
0
62.2
29.4
0
25
19.4
.£<%..,*. s ' "i-11
^Brjta^ ••••
c'«W.i
8,000
3,000
7,500
3,559
11,500
4,000
6,150
6,462
2,500
7,000
5,967
<- '•• - k • \ ' ^rea^neat -f eeftnofopes' * * Cs ' ^
^y:* ;Up)io|^|^lcti«feit^/:;< -
Settling Tanks, Cartridge Filters
Settling Tanks
Settling Tanks
Settling Tanks
Settling Tanks
Settling Tanks
Settling Tanks, Parallel Plate Coalescer
Settling Tanks, Cartridge Filters
Settling Tank, Screen Filter
Setting Tanks, Cartridge Filters
-
No injection at this site.
-------
study are discussed in Chapter V. All of these facilities, except for Texaco Port Neches, disposed of their
produced water via subsurface injection. As can be seen from this table, no correlation is apparent between
oil or gas production and produced water volumes.
Table IV-2 in Chapter IV presents the list of coastal discharging facilities in the Gulf of Mexico
current requirements baseline. As can be seen from these data, produced water volumes for discharging
facilities range from 291 bpd to 153,895 bpd. The average produced water volume for discharging
facilities is 23,912 bpd. The total volume of produced water discharged in the Gulf of Mexico is
191,292 bpd.
3.2 ALASKA
Table VDI-2 presents the produced water volume and treatment data for Cook Met. As noted in
Chapter IV, there are five platforms that discharge directly into Cook Inlet while the remaining nine pipe
their combined production fluids (hydrocarbon and water) to one of three shore-based separation/treatment
facilities. The total volume of produced water discharged from platforms in Cook Inlet is 5,188 bpd, and
the overall total including the three shore-based facilities is 135,285 bpd. The three shore-based facilities
discharge approximately 96 percent of the Cook Inlet produced water, not including the Dillon platform
discharges.
3.3 ALTERNATIVE BASELINE FACILITIES
As discussed in Chapter IV, the Alternative Baseline includes Gulf of Mexico facilities that are
additional to those in the baseline Gulf of Mexico analysis. The total produced water volume contributed
by these additional facilities is 397,578 barrels per day (see Section XI.5 for details regarding these
facilities). The total produced water volume for the Alternative Baseline population (which is the sum of
the baseline "Gulf of Mexico fecilities, Cook Inlet facilities, and additional Gulf of Mexico facilities) is
724,155 barrels per day or 264.3 million barrels per year.
4.0 PRODUCED WATER COMPOSITION
Since the 1979 promulgation of the Coastal Oil and Gas BPT Effluent Limitations Guidelines, EPA
has conducted several produced water characterization studies. A number of these studies were used in
the development of the 1993 Offshore Guidelines. These studies are the 30 Platform Study, the California
Sampling Program, and the Alaska Sampling Program, and are described in detail in the Offshore
vm-4
-------
TABLE Vm-2
PRODUCED WATER VOLUMES FOR
OIL AND GAS PRODUCTION FACILITIES IN COOK INLET REGION4
'WOsSOyWisii.* '
Dillon
Bruce
Anna
Baker
Tyonek "A"
Granite Point
Trading Bay
E. Foreland
TOTAL
Operator
I
Unocal
Unocal
Unocal
Unocal
Phillips
SHORE BASI
Unocal
Marathon
Shell
Western
&& Brad. Wafer
;r vol. <&j»!B} ^ *
HSCHARGING FLAT
3,116
199
919
924
30
3) TREATMENT/DIS
929
127,468
1,700
135,285
PW ^
Disch. Location
TORMS
Platform
Platform
Platform
Platform
Platform
POSAL FACILITE
Spark Platform
Outfall
Outfall
-
Treatment
•" Technologies. "*%
Skim Tanks
Skim Tanks
Skim Tanks
Skim Tanks
Skim Tanks, Gas
Flotation
ES
Skim Tanks
Skim Tanks, Gas
Flotation, Settling
Pits
Skim Tanks,
Corrugated
Separators
-
Development Document.2 Therefore, data from these studies will not be presented individually in this
document. In some cases, data summarized in the Offshore Development Document have been used in the
tables presented in this section, particularly with respect to certain treatment system performance data and
the composition of produced water in Cook Met. For the Gulf of Mexico region, the EPA 10 Production
Facility Study is the source of produced water composition data. Separate discussions on the characteristics
of produced water and the databases used are presented for both the Gulf of Mexico and Cook Inlet
regions.
4.1 COMPOSITION OF PRODUCED WATER FOR THE GULF OF MEXICO
The 1992 EPA 10 Production Facility Study characterizes BPT-level produced water effluent for
the coastal region of the Gulf of Mexico. EPA excluded data from three facilities that were not meeting
vm-s
-------
BPT limits. Although samples were collected at a number of locations within each facility, samples
collected at the effluent of the settling tanks were most representative of BPT level treatment.
Table Vm-3 presents the overall summary of occurrence of the organic pollutants detected in at
least 25 percent of the 14 samples of settling tank effluents that were collected. As can be seen from this
table, only benzene and toluene were detected in 100 percent of the samples. An additional 18 organic
pollutants were detected in greater than 25 percent of the samples. Out of a total of 232 priority and non-
conventional organics analyzed, 212 were either not detected, detected in less than 25 percent of the
samples, or were removed from consideration because they are not expected to be characteristic of
wastewater pollutants discharged in produced water.5
Table Vm-4 presents summary analytical data of the settling tank effluents from the 1992 EPA 10
Production Facility Study. Only pollutants that were detected in at least 25 percent of samples are listed.
Any non-detected sample results were given the value of one-half the detection limit value in the derivation
of the overall mean values. These data were used as BPT-level effluent concentrations for the Gulf of
Mexico region in the development of the Coastal Guidelines.
4.2 COMPOSITION OF PRODUCED WATER FOR COOK INLET
Table VTJI-5 presents the summary data obtained from several sampling programs that are
considered to be representative of the composition of produced water in Cook Inlet. The primary source,
a comprehensive Cook Inlet Discharge Monitoring Study was conducted by EPA Region 10 to investigate
oil and gas extraction point source discharges.8 In this study, produced water discharges from production
facilities in Cook Inlet (coastal subcategory) were sampled and analyzed for one year, from September
1988 through August 1989. Samples were collected from two oil platforms and one natural gas platform,
all of which discharge to the surface waters, and also from three shore-based central treatment facilities.
How-weighted averages were then calculated using the mean concentrations from each discharge hi this
study. This study, however, only provided data for 10 organic pollutants and zinc. Concentrations for
the other pollutants included in Table Vin-5 were taken from the BPT-level effluent data from the Offshore
Development Document.2 EPA determined it appropriate to apply effluent data for offshore platforms to
these in Cook Inlet because of the similarities in operation. The data for radium 226 and 228 presented
in Table Vm-6 are from the Alaska Oil and Gas Association's comments on the offshore rulemaking.9
vm-e
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TABLE Vm-3
PERCENT OCCURRENCE OF ORGANICS FOR BFT LEVEL TREATMENT
EFFLUENT SAMPLES FROM THE 1992 EPA 10 PRODUCTION FACILITY STUDY6
- *- Yl'Ntak* v :./ "'
Benzene
Toluene
o+p Xylene
Ethylbenzene
Benzole Acid
m-Xylene
Phenol
n-Hexadecane
Naphthalene
o-Cresol
Hexanoic Acid
n-Tetradecane
p-Cresol
n-Decane
n-Dodecane
2,4-Dimethylphenol
n-Octadecane
n-Eicosane
2-Hexanone
2-Methylnaphthalene
a"-- s 3»nWT!»er«f> ' -
:. Independent Samples
14
14
14
14
14
14
14
14
14
14
14
14
14
14
14
14
14
14
14
14
' SSEuHiber of Independent ,,,
Samples W/ Detects
14
14
12
9
9
8
8
7
8
8
8
6
7
6
7
8
6
6
4
6
f * i f ^ •.*
Percent Detects ,
100.0
100.0
85.7
64.3
64.3
57.1
57.1
50.0
57.1
57.1
57.1
42.9
50.0
42.9
50.0
57.1
42.9
42.9
28.6
42.9
5.0 CONTROL AND TREATMENT TECHNOLOGIES
Treatment processes for produced water are primarily designed to control oil and grease, priority
pollutants, and total suspended solids. Currently, most state and NPDES permits that allow the discharge
of coastal produced water to surface water bodies with limits only for the oil and grease content (BPT
limitation) in the produced water.
5.1 BPT TECHNOLOGY
BPT effluent limitations restrict the oil and grease concentrations of produced water to a maximum
of 72 mg/1 for any one day, and to a thirty-day average of 48 mg/1. BPT end-of-pipe treatment that can
achieve this level of effluent quality consists of some, or all of the following technologies:
• Equalization (surge tank, skimmer tank)
• Chemical addition (feed pumps)
vm-7
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TABLE Vm-4
SUMMARY POLLUTANT CONCENTRATIONS FOR BPT LEVEL
EFFLUENT FROM THE 1992 EPA 10 PRODUCTION FACILITY STUDY6
Pollutant
":, Settling Efftaent
Cfcncen^af^ji^g/l}' t
CONVENTIONAL AND NON-CONVENTIONAL
POLLUTANTS
Total Recoverable Oil and
Grease
Total Suspended Solids
Ammonia
Chlorides
Total Dissolved Solids
Total Phenols
26,600
141,000
41,900
57,400,000
77,500,000
2,430
PRIORITY POLLUTANT METALS
Cadmium
Chromium
Copper
Lead
Nickel
Silver
Zinc
31.50
180
236
726
151
359
462
OTHER METALS
Aluminum
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
1,410
52,800
22,800
2,490,000
117
17,000
601,000
1,680
121
287,000
12,200
430
43.80
135
35.30
\
•* Pollutant
Settling Effluent
Concentration 0»g/l)
PRIORITY POLLUTANT VOLATILE
ORGANICS
Benzene
Ethylbenzene
Toluene
5,200
110
4,310
OTHER VOLATILE ORGANICS
m-Xyiene
o+p Xylene
2-Hexanone
147
110
34.50
PRIORITY POLLUTANT SEMI-VOLATILE ORGANICS
Naphthalene
Phenol
184
723
OTHER SEMI-VOLATILE ORGANICS
Benzoic Acid
Hexanoic Acid
n-Decane
n-Dodecane
n-Eicosane
n-Hexadecane
n-Octadecane
n-Tetradecane
o-Cresol
p-Cresol
2-Methylnaphthalene
2,4-Dimethylphenol
5,360
1,110
152
288
78.80
316
78.80
119
152
164
77.70
148
RADIONUCLIDES
Gross alpha (pCi/1)
Gross beta (pCi/1)
Lead 210 (pCi/1)
Radium 226 (pCi/1)
Radium 228 (pCi/1)
675
367
41.30
189
264
Oil and/or solids removal
Gravity separators
Flotation
Filters
Plate coalescers
Filtration (used prior to subsurface disposal)
Subsurface disposal (injection).
vm-8
-------
TABLE Vm-5
PRODUCED WATER POLLUTANT
CHARACTERIZATION FOR COOK INLET, ALASKA
Pollutant Parameter ";
cowmww>tMS-~. !- - -, -5
Ofl & Grease)
TSS
M»3flRBFYMM'jULS I :
Cadmium
Copper
Lead
Nickel
Zinc
HRlOmfTO3M5AKIC§_ : ;
2,4-Dimethyl phenol
Anthracene
Benzene
Benzo(a)pyrene
Ethyl benzene
Naphthalene
Phenol
Toluene
i mn**}QmmmGM&l& ''" ,
n-Alkanes
Steranes
Triterpanes
Total Xylenes
Aluminum
Barium
Boron
Iron
Manganese
Titanium
Radium 226
Radium 228
„ Concentration (pgtl) !
5 * *
35,400"
67,500"
"' " 5
22.62"
444.66"
195.09b
1,705.46"
44.77"
s
514.70"
25.25"
3,386.12'
10.56"
157.73"
933.541
431.49"
1,507.43"
,. •- -.-. % -. ^ ff>f
1,641.5"
77.5"
78"
542.47"
78.01b
55,563.80"
25,740.25"
4,915.87"
115.87"
7.00"
2.65e-06°
3.0e-08c
Source - Envirosphere, 1989*
* Source - EPA, January 19932
c Source - AOGA, 1991; Tbs values shown were converted from pCi/1 to /tg/1 using the conversion factors 1 x l(r*
/tg/pCi for radium 226 and 3.7 x 10'' /tg/pCi for radium 228'
Oil is present in produced water in a range of particle sizes from molecular to droplet. Reducing
the oil content of produced water involves removing three basic forms of oil: (1) large droplets of
coalesceble oil, (2) small droplets of emulsified oil, and (3) dissolved oil. The removal efficiency and
resultant effluent quality achieved by the treatment unit is a function of, among other factors, the influent
flow, the influent concentrations of oil and grease and suspended solids, and the other types of compounds
in the produced water.
vm-9
-------
TABLE Vm-6
COOK INLET PRODUCED WATER RADIOACTIVITY DATA'
,, *""'"' f
. * V4,OUfe2*i-'
, ^UMrtgSg
RADIUM 226
Sample 1 (SWEPI East Foreland)
Sample 1 (Unocal Anna)
Sample 2 (Unocal Baker)
Sample 3 (Unocal Bruce)
Sample 4 (Unocal Dillon)
Sample 1 (Marathon Trading Bay)
Sample 2 (Marathon Trading Bay)
Sample 3 (Marathon Trading Bay)
RADIUM 228
Sample 1 (SWEPI East Foreland)
Sample 1 (Unocal Anna)
Sample 2 (Unocal Baker)
Sample 3 (Unocal Bruce)
Sample 4 (Unocal Dillon)
Sample 1 (Marathon Trading Bay)
Sample 2 (Marathon Trading Bay)
Sample 3 (Marathon Trading Bay)
** * niTwrkArrpr
;' •> * ;• .••'.•
^lS&
1.1±0.9
ND (1.9)
ND (1.9)
ND (1.9)
4.2±1.9
ND (0.4)
ND (0.4)
ND (0.4)
ND (3.9)
ND (2.9)
ND(2.9)
9.7±2.1
ND (2.9)
ND (2.9)
5.3 ±2.0
ND (2.9)
xmrrtr / fi'in.
VlJJjf \J>Cl/l|";,™ * >• * v.
'.. ^ <
"• s ;-f '" ^
1.2±0.9
-
-
-
-
-
-
-
ND (3.9)
-
-
-
-
-
-
-
ND — Not Detected (value in parentheses is the lower limit of detection).
Smaller oil droplets are formed by the shear forces encountered in pumps, chokes, valves, and high
flow rate pipelines. These droplets are stabilized (maintained as small droplets) by surface active agents,
fine solids, and high static charges on the droplets.10 Any operational change mat promotes the formation
of smaller droplets or the stabilization of small droplets can make oil and water separation more difficult.
Operational changes affecting the performance of the produced water treatment system, referred to as upset
vm-io
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conditions, can be caused by detergent washdowns in deck drainage entering the treatment unit, high flow
volumes caused by heavy rainfall (where deck drainage is commingled and treated with produced water),
and equipment failures.
End-of-pipe control technology for treating produced water from coastal oil and gas production
consists of physical and/or chemical methods. The type of treatment system selected for a particular
facility is dependent upon availability of space, waste characteristics, volumes, existing discharge
limitations, and other site specific factors. Oil skimming with gravity separation and/or chemical treatment
using settling tanks historically has been widely used in the coastal industry to meet BPT effluent limitations
because the support structure is relatively inexpensive (compared to offshore platforms where more
compact technologies are installed) and maintenance costs are low compared to more sophisticated
technologies. A description of the unit processes that may be used in the treatment scheme for produced
water is presented in the following sections.
5.1.1 Equalization
Equalization dampens flow and pollutant concentration variation of wastewater prior to subsequent
downstream treatment. By reducing the variability of the raw waste loading, equalization can significantly
improve the performance of downstream unit processes by providing uniform hydraulic, organic, and solids
loading rates. Increased treatment efficiency reduces effluent variability associated with slug raw waste
loadings. Equalization is accomplished hi a holding tank. To be effective, the tank should be designed
with sufficient retention time to dilute the effects of variable flow and concentrations on the treatment plant
performance. Some oil and water separation will also take place in the equalization tank.
5.1.2 Solids Removal
The fluids produced with oil and gas may contain small amounts of sand or scale particles from
the piping which must be removed from lines and vessels. Removal of these solids can be accomplished
by blowdown, by cyclone separators (desanders), or during equipment cleanout. Desanders are not
typically used in coastal operations to remove sand (and other particles) from produced water. The most
common method of removing produced solids from the process equipment is during cleanout of the gravity
separators which accumulate solids. Equipment cleanouts typically occur every three to five years.
Additional information on produced sand generation rates and disposal practices is presented in Chapter IX.
vra-n
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5.1.3 Gravity Separation
The simplest form of produced water treatment is gravity separation in horizontally or vertically
configured tanks or pressure vessels. Gravity separators are sometimes called skim tanks, skim vessels,
or water clarifiers. Gravity separators are designed with enough storage capacity to provide sufficient
residence time for the oil and water to separate. Performance of these systems depends upon the
characteristics of the oil and produced water, flow rates, and retention time. Gravity separation systems
with large residence times are typical for coastal operations, however on the Cook Inlet platforms that do
not pipe produced water to onshore facilities, gravity separation systems have limited residence times
because of space and weight limitations. While a treatment system relying exclusively on gravity
separation requires large tanks with long retention times, any treatment can benefit from even short periods
of quiescent retention to allow for some oil and water separation and dampen surges in flow rate and oil
loadings. Many coastal operations configure two or more gravity separators hi series with the first
separator acting as both an equalization tank and as a gravity separator.
Offshore type platforms such as those in Cook Inlet, Alaska use a device called a skim pile as the
final gravity separation treatment step. A skim pile is a large diameter pipe attached to the platform
extending below the surface of the water. Skim piles are vertical gravity separators that remove the portion
of oil which quickly and easily separates from water. Figure VEI-1 presents a diagram of a skhn pile.
During the period of no flow, oil will rise to the quiescent areas below the underside of inclined
baffle plates where it coalesces. Due to the difference in specific gravity, oil floats upward through oil
risers from baffle to baffle. The oil is collected at the surface and removed by a submerged pump. The
pump operates intermittently and removes the separated liquid to a sMmming vessel for further treatment.
5.1.4 Parallel Plate Coalescers
Parallel plate coalescers are gravity separators which contain a pack of parallel, tilted plates
arranged so that oil droplets passing through the pack need only rise a short distance before striking the
underside of the plates. Guided by the tilted plate, the droplet then rises, coalescing with other droplets
until it reaches the top of the pack where channels are provided to carry the oil away. In their overall
operation, parallel plate coalescers are similar to API gravity oil-water separators. The pack of parallel
plates reduces the distance that oil droplets must rise in order to be separated; thus the unit is much more
compact than an API separator. Suspended particles, which tend to sink, move down a short distance when
they strike the upper surface of the plate; then they move down along the plate to the bottom of the unit
vm-12
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Inlet
Oil Risers— >
Quiescent Zone
Rowing Zone
Discharge to Surface Water
- Oil
- Oil and Water
Figure VJH-1
Typical Skim Pile
-------
where they are deposited as sludge and can be periodically removed. Particles may become attached
(scale) to the plates* surfaces requiring periodic removal and cleaning of the plate pack.
5.1.5 Gas Flotation
Although gas flotation may be used for BPT treatment (and served as the technology basis for BPT
limitations established in 1979), it is currently used at only a small proportion of coastal facilities in Hie
Gulf of Mexico and Cook Met, Alaska regions. Results of the 1993 Coastal Oil and Gas Questionnaire
show mat the majority of coastal operators are using gravity separation instead of gas flotation to comply
with current BPT limitations. The questionnaire results showed that only 20 facilities out of the 224 that
were surveyed in the coastal Gulf of Mexico area reported using gas flotation.' Only two of the eight Cook
Inlet locations that treat produced water currently have gas flotation units in place (see Chapter XI for
details regarding current Cook Inlet produced water management practices). However, improved gas
flotation was investigated as a BAT technology for the coastal subcategory and is discussed as such in
Section 5.2. L
Gas flotation units introduce small gas bubbles into the body of wastewater to be treated. As the
bubbles rise through the liquid, they attach themselves to any particle (e.g., oil droplet) in their path, and
the gas and oil rise to the surface where they are skimmed off as a froth. Gas flotation may also aid in the
removal of oil-wet solids, finely divided solids and solids with low specific gravity. These solids become
entrained in, and exit the system with the oily from.
The gas flotation methods currently available are generally divided into two groups: (1) dissolved-
gas flotation (DGF) and (2) induced-gas flotation (IGF). The major difference between these methods are
the techniques used to generate the gas bubbles and the size of the gas bubbles produced. In dissolved-gas
flotation, the gas bubbles are generated by the precipitation of air (gas) from a super-saturated solution.
In induced-gas flotation, gas bubbles are generated by mechanical shear or propellers, diffusion of gas
through a porous media, or homogenization of a gas and liquid stream.11
Dissolved-gas flotation processes were at one time extensively used for the final treatment of
produced oil field water hi offshore operations.12 Currently, the majority of the offshore oil production
facilities use induced-gas flotation systems for treating their produced water prior to discharge. Induced-
gas flotation requires less space than dissolved gas systems, and thus IGF is the system of choice in the
WI-14
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offshore industry. However, space requirements at most coastal facilities are not as limited and therefore
coastal operators may elect to install DGF.
5. 7.5. 7 Dissolved-gas Flotation
In dissolved-gas flotation, the produced wastewater is first saturated with air (gas) either under
atmospheric or elevated pressures, then air is evolved from the solution by either applying a vacuum
(referred to as vacuum flotation) or an instantaneous reduction in system pressure (referred to as pressure
flotation). Under the reduced air pressure, the air evolves in the form of air bubbles which interact with
the dispersed material (oil and solid particles) and carry them to the surface of the liquid. Often the oil and
solid particles act as nuclei for the growing gas bubbles. Mechanical flight scrapers are then used to
remove the floated material.
Since the solubility of air at atmospheric conditions is low and efficiency of the flotation process
is a function of the volume of gas released from solution within the flotation cell, the use of vacuum
flotation is extremely limited. With the pressure flotation method, higher gas solubilities are possible
because of the higher system pressures involved. As a result, larger volumes of gas are released within
the flotation units following a drop in the system pressure resulting in greater overall process efficiency.
In the following discussion, the term "gas flotation" refers to the process of pressure flotation.11-13
The major components of a conventional gas flotation unit include a centrifugal pump, a retention
tank, and a flotation cell.12-14 As the first step in the gas flotation process, gas is introduced into the influent
stream at the suction end of a centrifugal pump discharging into a small pressurized retention tank. During
this process, the gas is sheared into finely dispersed bubbles which remain in the solution for a short period
of time (1 to 3 minutes retention time) in the retention tank. At this point the excess gas (undissolved air)
is purged from the tank. From the retention tank, the pressurized saturated water passes through a
backpressure regulator before entering the flotation unit. This regulator facilitates the necessary instant
pressure drop in the system and creates turbulence for proper dispersion of super-saturated water. Floe,
which forms as air bubbles and particles in the fluid interact, is lifted to the surface of the flotation cell,
where it is removed by mechanical skimmers. Higher density suspended material which is not amenable
to flotation is settled, concentrated and removed from the bottom of the flotation cell. Effluent is
discharged from the lower part of the cell where there is less turbulence.
vra-is
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5.1.5.2 Induced-gas Flotation
In a basic induced-gas flotation system (also referred to as dispersed-gas flotation), gas is drawn
into the flotation cell either mechanically (mechanical-type) by an impeller or hydraulically (hydraulic-type)
by an eductor into a cell containing the water. The introduced gas is then sheared into finely dispersed
bubbles by a disperse! or a rotating impeller. The dispersed gas interacts with the suspended solid and oil
particles and floats them to the surface as an oily froth which is removed by a skimmer system.
'v
The more advanced induced-gas flotation units are generally multi-cell in design. This feature
provides these systems with improved hydraulic characteristics due to reduced short-circuiting (as
compared to a single-cell design) and sequential contaminant removal. For example, if each cell in a four-
cell unit removes 60 percent of its receiving waste load, the overall removal performance is 97.5 percent;
at 70 percent per unit, the overall efficiency of greater than 99 percent is achieved.11
Studies have shown that induced-gas systems produce bubbles that can reach 1,000 microns (1mm)
in diameter. Bubbles from dissolved-gas flotation average between 70 to 90 microns in diameter and can
get as small as 30 microns.15 Larger gas bubbles can cause turbulence in the solution which could lead to
breakdown of the floe, thus reducing the overall system efficiency. This type of problem can be remedied
by proper modifications to existing systems or consideration in the new designs. Such consideration may
include repositioning the diffuser nozzles so that the air is released in the vertical direction for maximum
efficiency and minimum turbulence in the flotation tank.13iIS
Some of the main advantages of IGF include: less stringent operation and maintenance
requirements, lower comparative power requirements, and less costly adaptability to existing facilities.
In addition, because of the larger bubbles produced in this type of unit, interactions are much faster
resulting in shorter required retention time and smaller units. Hence, less capital cost and space are
required.11'13-14
Figure Vin-2 presents a schematic drawing of a mechanical-type induced-air gas flotation unit.16
Mechanical-Type Induced Gas Flotation Systems - In this type of gas flotation system, a rotor
with several blades rotates in the produced water creating a vortex. This creates a negative pressure which
draws gas from the freeboard down a standpipe for dispersion hi liquid. The gas is then sheared into
minute bubbles as it passes through a disperser and therefore creates a mixture of liquid and bubbles. The
vm-ie
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Outlet
Pad Gas
Discharge
Compartment
Skim Trough
Butterfly Valve To
Control Gas Intake
Inlet ~ / l<0*- htet Section
Drain
(Breaks Gas
Into Minute
Bubbles)
Upper Portion Of Rotor Draws
Gas Doom Standpip* For
Dispersion In Liquid
Skimmer Paddles
Launder
Rotor (Lower Portion Of
' Rotor Draws Solids Upward
Through Rotor)
Source: Arnold, 1987 **
Figure VOT-2
Dispersed Gas Floatation Unit
-------
rotating action of the rotors also causes liquid and solids to circulate upward from the bottom of the cell
and allows it to mix with the incoming waste stream and gas bubbles. The interaction of oil droplets and
gas bubbles occurs in the flotation region of the tank.
A dispenser hood provides a baffling effect which maintains the skim region in a quiescent state.
The rising of bubbles creates a surface flow towards the cell walls, where skimmer paddles are located.
Skim rate is generally a function of foam characteristics and unit size. Suspended solids that are amendable
to flotation are also removed along with the oil.13-16
The action of the rotor and dispenser generates relatively large bubbles (up to about 1000 microns
in diameter). Since the size of the bubbles is larger than in dissolved-gas flotation units, greater gas flow
is required by this type of unit to maintain a sufficient bubble population.13
Hydraulic-Type Induced Gas Flotation Systems - Hydraulic-type induced gas flotation units
consist of a feedbox, a series of cells separated by underflow baffles, and a discharge box. A gas eductor
is installed in each cell in a standpipe through which part of the cleaned discharge water is recycled back
to the unit. Gas is drawn into this stand pipe as the result of the venturi effect created by the flow of the
recycled water. The mixing of gas with the recycled water generates small bubbles which diffuse and
interact with the dispersed oil droplets in the water. Eductors are often installed at an angle to create a
surface flow to the side where the skimmers and the skim trough are located. The flotation and skimming
processes are similar to those in mechanical-type systems.13
The rate at which gas flows into an eductor is a function of recycle rate (eductor pressure), gas inlet
orifice size, and any valve that may have been installed in the gas feed pipe. The gas flow rate and energy
dissipation are the major'factors in determining the size of bubbles produced. The recycle flow rate is
generally controlled manually through control valves installed in the recycle line and between the recycle
header and each eductor. The recycle rate is the most important control parameter for optimizing the
performance of hydraulic-type systems. For example, as recycle rate increases, the gas rate increases,
resulting in a decrease in the initial residence time. This allows for only partial treatment of the influent
water and could result in short circuiting of the system.13
Hydraulic type units are generally less expensive, are lower, in overall operating cost, and
experience less downtime than other types of gas flotation systems. However, because the gas transfer per
vm-is
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unit volume of water in this type of unit is significantly lower than in mechanical-type units, hydraulic-type
units typically achieve lower removal efficiency than mechanical-type units.13-17
5.1.6 Chemical Treatment
The addition of chemicals to the wastewater stream is an effective means of increasing the
efficiency of treatment systems. Chemicals are used to improve removal efficiencies in gravity separation
systems, plate coalescers, and flotation units. The three basic types of chemicals that are used to enhance
equipment removal efficiencies in wastewater treatment are:
Surfactants: Surfactants, also known as surface-active agents or foaming agents, are large organic
molecules that are slightly soluble in water and cause foaming in wastewater treatment plants and in the
surface waters into which the waste effluent is discharged. Surfactants are sometimes used to treat oil-wet
solids. Oil-wet solids tend to settle poorly because the combined lower density of the oil and higher density
of the solids results in particles that have neutral buoyancy in water. Surfactants break apart the oil and
solids so that they can more readily separate from the water.
Coagulants: Coagulating agents assist the formation of a floe and improve the settling
characteristics of the suspended matter. The most common coagulating agents are aluminum sulfate (alum)
and ferrous sulfate.
Polyelectrolytes: These chemicals are long chain, high molecular weight polymers used to bring
about particle aggregation. Polyelectrolytes act as coagulants to lower the charge of the wastewater
particles, and aid in the formation of interparticle bridging and aggregation of particles. Depending on
whether their charge, when placed in water, is negative, positive, or neutral, these polyelectrolytes are
classified as anionic, cationic, and nonionic, respectively.
Surface active agents and polyelectrolytes are the most commonly used chemicals in wastewater
treatment processes. The chemicals are usually injected into the wastewater in the piping upstream of the
treatment unit without pre-mixing. Serpentine pipes, existing piping arrangements, etc., induce enough
turbulence to disperse these chemicals into the water stream.
vra-19
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5.1.7 Subsurface Injection and Filtration
Subsurface disposal is sometimes used to comply with BPT limits and is the technology used in
coastal areas to comply with zero discharge limits in NPDES permits. Injection is also used for
waterflooding to enhance production. At some facilities injection is preceded by a filtration process to
protect the formation face from becoming fouled with solids. Subsurface injection in combination with
filtration is the BAT technology basis for complying with zero discharge for produced water and is
discussed in detail in Section 5.2.2.
5.2 ADDITIONAL TECHNOLOGIES EVALUATED FOR BAT AND NSPS CONTROL
Several produced water treatment technologies were considered as add-on technologies to the
existing BPT technologies to achieve BAT and NSPS limitations. In particular, EPA evaluated the
following technologies for BAT and NSPS level of control: gas flotation, subsurface injection, cartridge
filtration, granular filtration, crossflow membrane filtration, and activated carbon adsorption. The
following sections describe these technologies in detail.
5.2.1 Improved Performance of Gas Flotation Technology
During the development of the offshore rule, EPA evaluated the costs and feasibility of improved
performance of gas flotation treatment systems to determine whether more stringent effluent limitations
based on improved performance of gas flotation would be appropriate. Specific mechanisms to improve
the performance of gas flotation systems include proper sizing of the gas flotation unit to improve hydraulic
loading (water flow rate through the equipment), adjustment and closer monitoring of engineering
parameters such as recycle rate and shear forces that can affect oil droplet size (the larger the oil droplet,
the easier the removal), additional maintenance of process equipment, and the addition of chemicals to the
gas flotation unit to enhance pollutant removals. Since most coastal facilities do not currently use this
technology, it is reasonable to conclude that for most coastal facilities the improvements can be designed
into any newly installed systems. The performance data for this technology has been adopted from the
offshore rule. Table VTH-7 presents summary data for improved gas flotation effluent as compared to
settling effluent data which characterize BPT-level treatment.
The performance of a gas flotation process is highly dependent on the bubble-particle interaction.
The mechanisms of this interaction include: (1) precipitation of the bubbles on the particle surface,
(2) collision between a bubble and a particle, (3) agglomeration of individual particles or a floe structure
VTH-20
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TABLE Vm-7
PRODUCED WATER EFFLUENT CONCENTRATIONS
FOR THE GULF OF MEXICO
f •:
s - Poltotani Parameter "
Ofl and Grease
TSS
Priority Organic Pollutants
2,4-Dimethylphenol
Benzene
Ethylbenzene
Naphthalene
Phenol
Toluene
Priority Metal Pollutants
Cadmium
Chromium
Copper
Lead
Nickel
Silver
Zinc
Non-Conventional Pollutants
Aluminum
Ammonia
Barium
Benzoic acid
Boron
Calcium
Chlorides
Cobalt
Hexanoic Acid
2-Hexanone
Iron
Magnesium
Manganese
2-MethyInaphthalene
Molybdenum
n-Decane
n-Dodecane
n-Eicosane
n-Hexadecane
n-Octadecane
n-Tetradecane
o-Cresol
p-Cresol
Strontium
Sulfur
Tin
Titanium
m-Xylene
o+p-Xylene
Vanadium
Yttrium
Lead 210
Radium 226
Radium 228
, '• •• ••"-•v ,™; " , Concentration (ug/J> * " -
-&to£*to&'-'<.
26,600
141,000
148
5,200
110
184
723
4,310
31.50
180
236
726
151
359
462
1,410
41,900
52,800
5,360
22,800
2,490,000
57,400,000
117
1,110
34.50
17,000
601,000
1,680
77.70
121
152
288
78.80
316
78.80
119
152
164
287,000
12,200
430
43.80
147
110
135
35.30
5.49e-07
1.916-04
9.77e-07
'""; improved Gas dotation EfSuentb
23,500
30,000
148'
1,226
62.18
92.02
536
827.80
14.47
180°
236°
124.86
151 '
359'
133.85
49.93
41,900 '
35,561
5,360'
16,473
2,490,000 °
57,400,000 '
117°
1,110'
34.50 '
3,146
601,000'
74.16
77.70'
121°
152°
288°
78.80 °
316'
78.80 '
119'
152°
164'
287,000°
12,200 °
430'
4.48
147'
110°
135°
35.30'
5.496-07 '
1. 91e-04
9. 77e-07 °
Source: SAIC, 1996.18
Concentrations in this column are from the Offshore Development Document unless otherwise noted.2
For the purpose of regulatory analysis, these concentrations are substituted using the settling effluent concentrations either
because no data were available in the Offshore Development Document or because die offshore gas flotation value was
greater than the settling effluent value.
vm-21
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as the bubbles rise, and (4) absorption of the bubbles into a floe structure as it forms. These mechanisms
indicate that surface chemistry aspects of flotation play a critical role in improving the performance of gas
flotation. Chemicals that enhance the bubble-particle interaction will increase pollutant removal. In fact,
chemicals have been an integral part of the flotation process for some time.11
Chemicals are commonly used to aid the flotation process. Chemicals function to create a surface
or a structure that can easily absorb or entrap air bubbles. Three basic types of chemicals, which are
previously discussed in Section 5.1.6, are generally utilized to improve the efficiency of the gas flotation
units used for treatment of produced water; these chemicals are surface active agents, coagulating agents,
and polyelectrolytes. Polyelectrolytes and coagulants increase pollutant reductions for gas flotation systems
by facilitating interparticle bridging or aggregation of particles. This "particle growth" results in structures
(floes) that more easily entrap other particles (even at the molecular level) and the gas bubbles in the
produced water (through absorption or adsorption). Surfactants and polyelectrolytes enhance the particle
interaction by altering surface tension or particle eletrical charge, thus increasing the chance the gas bubble
will interact with the pollutant and float it to the surface for removal. Inorganic chemicals, such as the
aluminum or ferric salts and activated silica, can be used as coagulating agents to bind the participate
matter and to create a structure that can easily entrap air bubbles. Various surface active organic chemicals
can be used to change the nature of either the air-liquid interface or the solid-liquid interface, or both.
These compounds usually collect on the interface to bring about the desired changes.
Researchers have demonstrated that the addition of chemicals to the water stream is an effective
means of increasing the efficiencies of gas flotation treatment systems. 10'13>19>20'21'22'23 Pearson, 1976,
reported that the use of coagulants can drastically increase the oil removal efficiency of dissolved-gas
flotation units.14 The addition of alum plus polyelectrolyte to a flotation cell treating refinery wastewater
increased the unit efficiency from 40 percent to 90 percent. Luthy, et al., 1978, also demonstrated the
effectiveness of polyelectrolytes for improving the effluent quality of dissolved-gas flotation units treating
refinery wastewater.2*
Factors related to engineering or mechanical design aspects of the gas flotation systems which
could also affect process performance include:
• Type of gas available or used
• Pressure supplied and temperature (DGF)
• Type and condition of eductor (IGF)
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• Rotor speed and submergence (IGF)
• Percent recycle (DGF) or rate of recycle (IGF)
• Influent characteristics, concentration, and fluctuations
• Hydraulic and mass loadings
• Chemical conditioning
• Type and operation of skimmer
• Air-to-solids ratio
• Hydraulic retention time
• pH
• Chemical addition (i.e., frequency and dosage rate)
• Surface area of unit
• Retention time of floated material.
A review of the design parameters for 32 gas flotation units surveyed by EPA in 1975 revealed that
these units were designed for maximum expected hydraulic loadings. However, none were designed to
handle mass overload conditions which may occur during start-up, process malfunctions, or poor operating
practices. The survey also indicated that those systems that were properly designed, maintained, and
operated had excellent performance. Produced water effluent oil concentrations from these systems
averaged less than 25 mg/1.21
For those few coastal facilities that already have gas flotation in place most modifications to
improve gas flotation are simple and could be done by using the existing tankage and equipment with
minimal costs. For example, according to a case study conducted by Rochford, 1986, an inadequately
designed induced gas flotation system operating in North Sea was successfully modified to operate as a
dissolved gas flotation with minimal capital cost.25 The IGF unit was not designed to treat produced water
with very small oil droplets (5 to 40 microns), thus achieving only 30 percent removal efficiency. The
modified system simplified the equipment required for conventional DGF systems by utilizing the existing
tanks and the dissolved gas already present in the produced water. The new system efficiency ranged
between 70 to 80 percent.
In general, gas flotation systems may have oil and grease removal efficiencies of 90 to 95 percent.15
With proper operation, chemical addition, and low suspended solids concentration, a mechanical-type IGF
system can consistently achieve oil removal efficiencies greater than 90 percent, even when operating at
capacities beyond the design flowrates. Some older and larger size hydraulic-type IGF systems using one
eductor per cell have not demonstrated the capability to consistently exceed 90 percent oil removal
efficiency at one minute residence time per cell. However, the newer designs which have employed
vm-23
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multiple eductors in each cell, more cells for the same volume, a means of ensuring smaller bubbles, and
superior baffle design give comparable performance to mechanical-type units. As a general design rule,
gas flotation units used for treating oily water should have a large drain piping system, at least 4-inches
in diameter, to prevent foam plugging. Also, adequate surge capacity is necessary upstream of IGF units
to protect the system from oil "slugs," eliminate flowrate surges, and to remove suspended solids.13
5.2.2 Subsurface Injection
Disposal of produced water by injection into a subsurface geological formation can serve the
following purposes:
• Provide zero discharge of wastewater pollutants to surface waters.
• Increase hydrocarbon recovery by flooding or pressurizing the oil bearing strata (waterilooding).
• Stabilize (support) geologic formations which settle during oil and gas extraction (a significant
problem for older, i.e onshore and coastal, more depleted reserves).
Coastal and onshore produced water injection is a well-established practice for disposal of produced
water. With the exception of Cook Inlet, injection of produced water is widely practiced by facilities hi
the coastal subcategory. Independent of this rule, all coastal facilities in Alabama, California, Florida, and
the North Slope of Alaska are currently practicing zero discharge. EPA estimates that at least 80% to
99.9% of all coastal facilities in Louisiana and Texas will be practicing zero discharge by January 1, 1997.
The 80% estimate is based on subtracting the sum of the 6 facilities discharging into a major deltaic pass
of the Mississippi, the 82 facilities discharging to Louisiana open bays, and the 82 facilities associated with
individual permit applicants in Texas from the 853 total coastal facilities estimated to exist hi Louisiana and
Texas. The 99.9% estimate is based on subtracting the number of facilities discharging into a major deltaic
pass of the Mississippi from the total number of coastal facilities in Louisiana and Texas. Additionally,
using data from the Coastal Oil and Gas Questionnaire and other information regarding facilities known
to be discharging in 1992, EPA estimated that 62% of coastal facilities along the Gulf of Mexico were
practicing zero discharge in 1992. For the onshore subcategory, injection is the predominant technology
used to comply with the zero discharge BPT limitation promulgated in 1979. Additionally, some facilities
have been subject to consent decrees requiring zero discharge hi citizen suits filed by environmental
groups. For the onshore subcategory, injection is the predominant technology used to comply with the zero
discharge BPT limitation promulgated hi 1979.
VHI-24
-------
As part of the offshore rulemaking process, and in response to industry concerns about the
feasibility of injection due to the receiving formation characteristics, EPA evaluated the technical feasibility
of implementing this technology at both existing and new offshore facilities.26 The study showed that
injection is generally technologically feasible in all offshore areas, i.e., suitable formations and conditions
are available for disposal operations. The same is generally true for the coastal regions in that the
geologies of the North Slope and the Gulf Coast consist of formations which can readily accept injected
produced water. EPA has no information in the record that would indicate that other coastal regions, other
than Cook Inlet, Alaska, would be unable to inject produced water.
The following sections present information on the injection technology as a means to control
produced water discharges.
5.2.2.1 Industrial Practices by Location
Most of the produced water generated in the coastal and offshore areas of California is presently
injected for waterflooding to enable recovery of the heavy crude oil that is typically produced in that part
of the country. Coastal facilities in Florida, Alabama, and Mississippi are currently practicing zero
discharge of produced water. In the western Gulf of Mexico, produced water generated in the coastal
region has been either treated to the BPT limitations and discharged to the surface waters or it is injected
for disposal under the Region 6 general permits (60 FR 2387) published January 9, 1995. Coastal injection
experiences in Texas and Louisiana have shown that the characteristics of the regional geology make it
possible to inject produced water in the Gulf Coast region.27 However, in Cook Inlet, because of the highly
fractured and compartment geology present, there are no formations onshore directly beneath the treatment
facilities to accept the large volumes of produced waters treated, making injection onsite infeasible.28
The data in Table IV-1 show that EPA estimates that there were 853 production facilities hi Texas
and Louisiana in 1992 and of those, 325 were discharging produced water to surface waters. The Coastal
Oil and Gas Questionnaire Summary Statistics showed that of the production facilities in the Gulf of
Mexico, an estimated 62 percent were injecting produced water in 1992.' The majority of the 528
production facilities not discharging in 1992 were disposing of produced water by subsurface injection.
As shown in Table IV-1, EPA estimates that by January 1, 1997, only 6 coastal facilities in the Gulf of
Mexico will be discharging produced water (see Chapter HI for details regarding current regulatory
requirements).
vm-25
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All of the coastal operations in the North Slope region of Alaska inject all of their produced water,
primarily for waterflooding. In Cook Inlet, Alaska, produced water is surface discharged after BPT
treatment. However, waterflooding is being performed using seawater.
5.2.2.2 Well Selection and Availability
There are a number of considerations in the planning, design, and operation of a produced water
injection system. These include important design considerations such as selection of a receiving formation,
preparation of an injection well, and choice of equipment and materials. Significant operational parameters
include scaling, corrosion, incompatibility with the receiving stratum, and bacterial fouling.
5.2.2.2.1 Formation Characteristics
Selection of the receiving formation should be based on geologic as well as hydrologic factors.
These factors determine the injection capacity of the formation and the chemical compatibility of the
injected produced water with the water within the formation. The most important regional geologic
characteristics of a disposal formation are areal extent and thickness, continuity, and lithological character.
This information can be obtained or estimated from core analysis, examination of bit cuttings, drill stem
test data, well logs, driller's logs, and injection tests.
The desirable characteristics for a produced water injection formation are: an injection zone with
adequate permeability, porosity, and thickness; an areal extent sufficient to provide liquid-storage at safe
injection pressures; and an injection zone that is confined by an overlying consolidated layer which is
essentially impermeable to water. There are two common types of intraformation openings:
(1) intergranular and (2) solution vugs and fracture channels. Formations with intergranular openings are
usually made up of sandstone, limestone, and dolomite formations and often have vugulur or cavity-type
porosity. Limestone, dolomite, and shale formations may be naturally fractured. Formations with fracture
channels are often preferable for produced water disposal because fracture channels are relatively large in
comparison to intergranular openings. These larger channels may allow for fluids with higher
concentrations of suspended solids to be injected into the receiving formation under minimum pumping
pressure and minimal pretreatment. •
A formation with a large areal extent is desirable for disposal purposes because the fluids within
the disposal formation must be displaced to make room for the incoming fluids. An estimate of the areal
extent of a formation is best made through a subsurface geological study of the area. If it is possible to
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inject water into the aquifer of some oil- or gas-producing formation, the size of the disposal formation is
not critically important. Under these circumstances, the injected water would displace water from the
aquifer into the producing reservoir from which fluids are being produced. Thus, the pressure in the
aquifer would only increase in proportion to the amount that water injection exceeds fluid withdrawals.
Pressure-depleted aquifers of older producing reservoirs are highly desirable as disposal formations,
provided the disposal practice will not adversely affect the producing reservoir.
Formations capped or sandwiched by impervious strata generally will assure that fluids pumped
into the formation will remain hi place and not migrate to another location.29 Abandoned producing
formations are ideal for disposal because the original fluids were trapped in the formation. Fluids injected
into those formations also will be trapped and will not migrate into other areas.
5.2.2.2.2 Proper Location of Disposal Wells
Faulting in an area should be evaluated critically before locating a disposal well, particularly if the
disposal formation is other than an active or abandoned oil or gas producing formation.26 Depending upon
local stratigraphy and the type and amount of fault displacement, one of three possible conditions can
occur. Displacement along the fault may either: (1) limit the area available for disposal; (2) place a
different permeable formation opposite the disposal formation which could allow fluids to migrate to
unintended locations; or (3) the fault itself may act as a conduit, allowing injected fluids to flow along the
fault plane either back to the surface or to permeable formations at a shallower depth than the disposal
formation.
Another concern associated with faulting is that fluids entering the fault or fault zone may cause
a reduction in friction along the fault plane, thus allowing additional, and perhaps unwanted, displacement
to occur.26 Such movement can create seismic activity in the area. The city of Denver, Colorado placed
a disposal well near the Rocky Mountain Arsenal and pumped city waste water down the well. The well
bottom was in the vicinity of a fault. Subsequent analysis showed a direct correlation between the number
of microseisms in the Denver area and well pumping times and rates. Increased pumping caused a
corresponding increase in the number of microseisms.
5.2.2.2.3 New Versus Converted Wells
Whether the objective is enhanced ("secondary") recovery or disposal, a primary requirement for
the proper design of a injection well is that the produced water be delivered to the receiving formation
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without leaking or contaminating fresh water or other mineral bearing formations. The injection well may
be installed by either drilling a new hole or by converting an existing well. The types of existing wells
which may be converted include: marginal oil producing wells, plugged and abandoned wells, and wells
that were never completed (dry holes). If an existing well is not available for conversion, a new well must
be drilled. Moreover, for injection from platforms supported on pilings, adequate equipment and storage
space must be provided at the facilities.
The drilling of a new injection well is very similar in practice to the drilling of production wells
except that injection wells may not need to be drilled as deep as the production wells they serve, if
shallower disposal formations are available. The advantages of drilling a new well specifically for
produced water injection include the following:
• Location can be selected to minimize surface piping.
• Location can be selected to utilize optimal geologic formations.
• Casing and long string can be sized to handle designed produced water flowrates.
• Casing can be properly cemented to meet regulatory requirements.
• Desired casing grades and weights may be used.
The disadvantages of drilling new injection wells are:
• Costs are higher than converting an existing well.
• Geology and downhole conditions may not be known prior to drilling.
Figure VM-3 presents a schematic of a typical well drilled for subsurface injection. EPA's field
investigations found that the conversion of existing production wells to injection wells is the most common
practice in the coastal Gulf of Mexico region primarily due to availability and costs.3 Conversions are most
commonly performed on depleted production wells using wells whose hydrocarbon production rates have
or soon will diminish to the point where they are no longer economical to operate as production wells (i.e.,
depleted wells). Such depleted wells are included in the bases for the Gulf of Mexico compliance cost
estimates presented hi Chapter XI. Wells that were never completed (dry holes) and old plugged and
abandoned wells may also be used, but may require more work at greater expense.30
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WeU Head-
Produced Water
Possible Future
Injection Zones
Underground Source
of Drinking Water
Shale
Figure VHI-3
Typical Subsurface Injection Well
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The most common method of conversion involves recompletion of the well at a shallower depth
into a non-hydrocarbon producing formation.3 In such a case the lower portion of the well is cemented.
Conversion operations may include:
• Pulling/fishing of old tubing and equipment.
• Squeeze cementing if casing was not cemented to the lowest underground source of drinking water.
• Cementing of lower portion of the long string.
• Perforation into injection zone.
• Setting of new tubing and packer.
• Stimulation of the well.
• Installation of surface piping valves and gauges.
The advantages of converting an existing well rather than drilling a new well include the following:
• Lower cost since drilling is not required.
• Formation depths, porosity, thickness, and approximate permeabilities are already known.
• Casing and cement is often in satisfactory condition.
The disadvantages of converting an existing well include the following:
• Casing or long string may be too narrow to allow tubing of sufficient size to handle desired
produced water flow rate.
• Location may not be satisfactory.
• Casing may be in poor mechanical condition.
• Casing or long string may not be properly cemented.
Despite these advantages, most facilities will choose to use converted injection wells rather than
drill new ones due to the sayings in cost.31
The report entitled "Evaluation of Class n Regulatory Impacts" estimates that approximately 90
percent of newly installed injection wells will be converted wells and 10 percent will be newly drilled
wells.32 This estimate is based upon API data for existing permits and should be representative of both the
Gulf Coast and California. This estimate corresponds well with information gathered during the 1992
Coastal Oil and Gas sampling effort where eleven injection facilities were visited with two of them being
offsite commercial operations.3 Both of the offsite commercial operations had newly drilled injection wells
because they were not located over an oil field and thus did not own or have access to existing wells. Out
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of the remaining nine injection faculties visited by EPA, eight installed converted wells and one installed
a newly drilled well, or 11.1 percent of the facilities drilled new wells and 88,9 percent converted existing
wells. The total overall number of operating disposal wells for the nine onsite injection facilities consisted
of one newly drilled well and twenty-two converted wells or 4.3 percent newly drilled wells and 95,7
percent converted wells.
5.2,2.2.4 Regional Geological Considerations
California
There is little question about the technical feasibility of injecting produced water at the existing
facilities in the coastal region of California because the current practice of this technology is common. In
the coastal and offshore subcategories for California, most of the produced water is injected for the sole
purpose of enhanced recovery by waterflooding. In fact, at the THUMS facilities in Long Beach Harbor,
additional brine to that of the produced water must be injected to provide sufficient pressure maintenance.
Injection of produced water is not practiced ta areas where there is potential to increase seismic activity.33
The coastal geological conditions and engineering requirements for the injection of brines from new sources
in areas expected to be open for oil and gas development and production, i.e., free of seismic activity, are
expected to be essentially the same as for existing sources. Consistent with the past and present industry
practices, suitable disposal formations with adequate permeability, porosity, thickness, and areal extent are
expected to be available. Similarly, construetability and trouble-free operation of injection wells,
availability of coastal pretreatment technologies, and the transport and onshore disposal of solids and
sludges from new sources pose no additional technical problems beyond those currently encountered due
to the injection of brines from existing sources.
Gulf of Mexico
In the Gulf of Mexico, injection of produced water from existing coastal sources is common (see
Sections 5.2.2 and 5,2.2.1). The two most common disposal practices are either to pretreat and inject or
to treat the produced water to the BPT effluent limitations and discharge. While they do exist, waterflood
projects are not common in the Gulf of Mexico; it is estimated that less than ten facilities in the Gulf of
Mexico inject produced water for pressure maintenance.34 The primary reason that waterflooding is not
common is because, unlike California, extraction of the formation fluids from the reservoirs in the Gulf
of Mexico does not necessarily require the additional water drive provided by waterflooding. An effective
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waterflood program requires several wells, since waterflooding operations often push the oil zone up and
horizontally direct the movement of the zone to the production well.
Injection of brines for disposal from existing and new sources in the coastal Gulf of Mexico region
depends on the availability of an adequate number of suitable disposal formations. In the early stages of
production, mere is little need for injection fluids to enhance recovery and, therefore, the produced water
would be injected only for disposal purposes.. The coastal injection experience in Texas and Louisiana has
shown that injection of produced water is possible. Throughout most of the coastal region of Louisiana
and Texas, the oil and gas producing formations are overlaid with alternating sequences of sand and shale
sediments formed by ancient rivers and oceans and make up a considerable part of the stratigraphic
column.24 The advantages of using these formations for disposal include:
• Formation thicknesses, depths, porosities and permeabilities are usually available from
logs of the production wells and past experience.
• Shallower depths require less drilling and tubing, thereby reducing construction and future
remedial well work costs.
• Production wells can be converted to disposal wells without affecting producing reservoir
dynamics.
Eight of the ten coastal production facilities in the Gulf of Mexico region investigated by EPA in
1992 were injecting produced water into sand formations shallower than the producing formations.3
Several facilities indicated that additional shallower sand formations existed that could be used in the future
by recompleting the disposal wells at a shallower depth. The only disadvantage of using shallower
formations is that the maximum allowable injection pressure will be reduced. This can result in lower
injection pressures and more frequent remedial well work.
Alaska
In the North Slope region of Alaska, all produced water generated is injected with the major
portion being used for waterflooding. Waterflooding is also practiced in Cook Inlet, however, seawater
is used rather than the produced water. The waterflooding occurring in Cook Inlet has reached "parity"
which means that the volume of seawater injected is essentially equal to .the combined volume of oil and
produced water that is brought to the surface.
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An industry study of the technological feasibility and the economic analysis of subsurface disposal
in Cook Inlet was performed for produced water from the Trading Bay Production Facility.28 In this
report, three injection alternatives were considered and evaluated: 1) treatment and injection for
waterflooding at the platform; 2) piping produced water to an onshore facility for treatment and return to
the platform for injection for waterflooding; and 3) piping produced water to an onshore facility for
treatment and injection for disposal. In this study, alternatives 1 and 2 were reported to be technically
feasible, however, several operational problems were identified that could affect the system. These
problems, along with preventative remedial measures are discussed below.
For the third alternative, the study suggests that the available Tyonek sands injection formations
directly beneath the Trading Bay Facility (which discharges 94% of the Cook Inlet produced waters) are
not suitable to accept the large amounts of produced water generated at this facility. Although significant
in gross pore volume, these formations are broken up into numerous smaller reservoirs. Continuous
injection into any one reservoir could cause the reservoir to become overpressurized, threatening to cause
fracturing and migration to shallower potable water aquifers and, according to the study, possibly
triggering seismic activity. In addition, the Tyonek formations contain significant amounts of water-
sensitive clays which, when injected with the relatively fresh produced water from the Trading Bay
Facility, could result in severely or completely restricted permeability.28
5.2.2.3 Technical Issues
Some of the technical issues that may be associated with subsurface injection of produced water
are described below. In general, these issues can be avoided or remedied through engineering and
operational applications such as the use of treatment chemicals. Possible solutions for each are also
discussed.
y
Formation Plugging and Scaling - Scales and sludges that are commonly found in produced water
disposal systems include: calcium carbonate, magnesium carbonate, calcium sulfate, barium sulfate,
strontium sulfate, iron sulfide, iron oxide, and sulfur. These scales and sludges can form in collection and
distribution lines, treating equipment, well tubulars and at the injection formation.35
Scale and sludge differ hi that scale is a deposit formed in place on surfaces hi contact with water,
while sludge may be formed in one place and deposited in another. Sludges may collect in low flow rate
areas of a system such as tanks and vessels, in the bends of lines and on filter surfaces.35
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Scales and sludges are formed from water as the waters adjust to changes in equilibrium. Changes
in equilibrium are caused by temperature changes, pressure changes, chemical changes, changes in pH,
impurities, additives, gas evaporation, and the mixing of two or more stable but incompatible waters.36'37
Scale may form as a result of a chemical reaction between the water, or some impurity in the water, and
the pipe. Corrosion products, such as iron oxide or iron sulfide, may be scales of this type. Other
precipitates, such as sulfur, may form when water with hydrogen sulfide is mixed with water with a high
dissolved oxygen content.35
The solubility of calcium carbonate (a common component of groundwater) is influenced by the
concentration of dissolved carbon dioxide in water. If calcium carbonate is present in an underground
formation and the concentration of dissolved carbon dioxide in the formation water is increased, the amount
of dissolved calcium carbonate will increase. When the dissolved carbon dioxide concentration is reduced,
such as when carbon dioxide-rich produced water comes to the surface where the pressure is lower and
it comes into contact with air, the reverse occurs, and the carbon dioxide is released and calcium carbonate
will precipitate.36 Also, the solubility of most scales decreases with decreasing temperatures.
All of the produced water operations in the 1992 EPA 10 Production Facility Study sampling effort
maintained closed systems that exclude air using gas blankets. When the produced water samples were
cooled and exposed to air, a noticeable increase in turbidity and a color change occurred for most samples.
The turbidity was probably the result of calcium carbonate precipitation and the color change was probably
the result of the oxidation of dissolved iron.
Scale Prevention - Scale formation is normally preventable. Once formed, however, scale
removal is expensive and may cause some permanent damage. Individual waters or mixtures of waters
should be tested prior to the design of the produced water disposal system to determine if scale deposition
will be a problem. The waters that are to be added to an existing system should also be tested prior to
hookup.35
Scale deposition of waters can be predicted with moderate accuracy using conventional water
analysis and the Stiff-Davis method of predicting the approximate solubility of calcium carbonate and
calcium sulfate in produced waters. Compatibility tests will also indicate if scale formation is to be
expected.35
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Depending on the type of scale involved, methods of preventing or removing scale prior to
injection include: maintaining a closed system using gas blankets; use of scale inhibiting chemicals; use
of acid treatment; use of solvents; use of settling tanks with chemical addition; filtration; mechanical
scraping or reaming; and prevention of mixing incompatible waters.37
Properly-operated gas blanketing, in combination with the addition of scale-inhibiting treatment
chemicals is effective in preventing scale formation in produced water. In the report "Coastal Oil And Gas
Production Sampling Summary Report,"3 field observations of aqueous samples were reported for produced
water samples collected from ten oil and gas facilities. Observations were recorded for freshly taken
samples (before prolonged air contact) and after prolonged contact with air (i.e., one hour or greater
exposure). Produced water samples from four facilities exhibited an increase in turbidity after exposure
to air. The report stated that this increase in turbidity may have resulted from precipitates of calcium
carbonate, calcium sulfete, and/or other scale-forming materials. As a result, preventing exposure to air
would have likely reduced or eliminated the formation of these materials and the observed increase in
sample turbidity.
According to the API publication "Subsurface Saltwater Injection Disposal,"38 the presence of
oxygen hi produced water is an important driver for the formation of scale materials. The publication
states that "systems are designed to prevent the introduction of oxygen into the system, thereby minimizing
the amount of oxygen available for scale formation or corrosion reactions."
In the case of calcium carbonate precipitation, a closed system will reduce the loss of dissolved
carbon dioxide and/or hydrogen sulfide from the produced water.39 The calcium carbonate scaling
tendency and the likelihood of precipitating iron compounds from the produced water increases as these
gases escape from solution.. Gas blanketing should therefore substantially alleviate this problem.
In Cook Inlet, Alaska, the operators have expressed concern that the produced water contains a
significant amount of scale-forming ions, primarily calcium carbonate, and that the use of treated produced
water for waterflooding will result in the rapid plugging of the injection wells. One problem associated
with this is that the onshore produced water treatment systems at Trading Bay, Granite Point and East
Forelands do not maintain closed systems with gas blankets throughout the system. Therefore, there is a
greater potential for produced water from these systems to develop calcium carbonate scale. However,
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the use of the remedies discussed above such as gas blankets and chemical treatment should substantially
alleviate this problem.
In addition to scales and sludges, production formation solids such as sands are commonly found
in produced water disposal systems. This is especially true for produced waters from unconsolidated sand
formations which are common in the Gulf Coast region. Formation solids referred to as produced sand
in this report are most commonly removed using settling tanks and filters in the coastal areas of the Gulf
of Mexico.
Formation Swelling - The injection of water with a lower total dissolved solids or salt content than
the injection formation water can cause clay particles embedded in the formation to swell. However, this
is generally not a problem for produced water injection in the Gulf Coast region because produced water
in the Gulf Coast region generally has a total dissolved solids or salt content which is several times that of
seawater. This swelling in turn increases the necessary injection pressure and may decrease the injection
capacity of the injection well. This phenomenon was reported by the Campbell Wells facility at Bourg,
Louisiana which injected a high proportion of relatively fresh washwater (about 73 percent) from their land
treatment operation along with produced water from commercial clients (about 27 percent).40 The result
was that higher injection pressures were necessary but injection was not prevented. In Cook Inlet, the use
of seawater for waterflooding does not appear to have created a swelling problem. This problem can also
occur at facilities that combine a significant quantity of contaminated stormwater with produced water for
disposal.
Corrosion - A more common problem encountered in combining fresh water, such as stormwater,
with produced water for injection is corrosion caused by dissolved oxygen. The corrosion of metals in a
produced water disposal system is usually caused by electrochemical reactions. In this type of reaction an
anode (electron donor) and cathode (electron acceptor) must exist in the presence of an electrolyte (ionic
solution) and an external circuit. Anodes and cathodes can exist at different points on the steel surfaces
with the steel providing the external circuit. A brine solution provides an excellent electrolyte. Thus, an
electric circuit can be set up in the unprotected, produced water-handling pipelines with iron being oxidized
at one portion of the system (cathode) and iron being reduced and corroded away in another portion
(anode).
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Corrosion damage can occur uniformly as a gradual thinning of the anode portion, or it can occur
in the form of pitting where localized electrolytic cells are set up. It can also occur as galvanic corrosion
when two different metals come into contact and form an electrolytic cell.
Dissolved oxygen is a major producer of corrosion. Oxygen-induced corrosion is the result of an
electrochemical reaction between a metal, such as iron, and the oxygen where the oxygen accepts electrons
and the metal donates electrons. While oxygen is normally absent in formation waters, it is unavoidably
absorbed by contact with air in open produced liquid handling systems and can also be introduced with the
addition of contaminated stormwater.
Corrosion Prevention - At three of the ten production facilities that EPA sampled, contaminated
stormwater was periodically added to the produced water for treatment and disposal.3 The dissolved
oxygen in the stormwater can be removed using a chemical (oxygen scavenger) which combines with the
oxygen. In addition, the use of closed systems with gas blankets can prevent the introduction of oxygen
to the system. According to the report "Technical Feasibility of Brine Reinjection for the Offshore Oil and
Gas Industry,"35 a major utility of gas blankets is corrosion inhibition. While oxygen is normally absent
in formation waters, it is unavoidably absorbed by contact with air in open produced water handling
systems. As a result, gas blanket-producing equipment will minimize produced water contact with air, and
consequently minimize the formation of corroded metal particles.
Incompatibility of Injected Produced Waters with Receiving Formation Fluids - In the design
and operation of a produced water injection system, the compatibility of injected produced waters with the
fluids already in the receiving formation is an important consideration. Incompatibility occurs when one
or more of the chemicals in the produced water reacts with chemicals in the existing reservoir fluid to cause
an undesirable effect, such as precipitation of scale. This condition could also occur if incompatible waters
from different reservoirs or surface sources are to be mixed prior to injection. Precipitates that may be
associated with incompatible fluids include calcium carbonate, magnesium carbonate, calcium sulfate,
barium sulfate, and strontium sulfate. Both barium sulfate and strontium sulfate are highly insoluble in
water and are extremely difficult to remove.
It is interesting to note that injection well plugging due to incompatibility between the injected
water and the formation water is considered extremely unlikely.39 However, severe scale formation can
occur after injection water breakthrough (i.e., simultaneous production of the injected water with the
VHI-37
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formation water). While this may not be a problem in a dedicated produced water disposal well,
incompatibility can cause problems in a producing well from which injected and formation waters are
produced simultaneously.
Incompatibility Prevention - Treating produced water to prevent incompatibility consists of
reducing the strength of or removing the reactive element or otherwise altering the nature of the injected
fluid using treatment chemicals. Because scale formation is the primary concern when incompatible waters
are mixed, the scale prevention measures described above are applicable. Also, a buffer zone of a third
water which is compatible with both the injection water and the formation water may be injected to avoid
permeability reduction.39
Bacteria - The presence of bacteria in a system may present a corrosion or plugging problem.
Bacteria in oil field waters may be aerobic (active in presence of oxygen), or anaerobic (active hi the
absence of oxygen).
Iron bacteria are aerobic and are active in removing iron from water and depositing it in the form
of hydrated ferric hydroxide. They are commonly active hi fresh waters but are occasionally found in
produced waters containing oxygen. The removal of oxygen by the bacteria causes an anaerobic condition
to exist under the ferric hydroxide iron deposits on vessel walls where sulfate reducing bacteria can grow
and corrode the vessel walls. Both types of bacteria are easily controlled with bactericides.35
Aerobic bacteria, or slime formers, can grow in sufficient numbers to cause significant well
plugging. Aerobes are indicators of excessive bacterial activity in oxygen-bearing waters and if present
in a closed system indicate that air contamination exists. The slimes that are formed shield the metal
surfaces from oxygen and'prpvide an environment for the growth of sulfate reducing bacteria. Control of
aerobic bacteria is generally accomplished by treatment with an organic biocide.35
Anaerobes are active hi the absence of oxygen but are not killed by the presence of oxygen.
Anaerobes, except sulfate reducers, multiply slowly and normally are found under slime deposits. They
are effectively killed with bactericides. Although chlorine could be used, hi a closed system chlorine is
not used because it is an oxidizing agent.35
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Sulfate reducing bacteria are the most common and economically significant of the bacteria found
in salt water disposal and injection systems. Sulfate bacteria are economically significant due to the
corrosion problems associated with them. Sulfate reducing bacteria are anaerobic and have the ability to
convert sulfate to sulfide. Sulfate reducers are most active in neutral to mildly acidic waters, are frequently
found under slime deposits, and are most prolific under corrosion products, tank bottoms, filters, oil water
interfaces, and dead water areas, such as joints, crevices, and cracks in cement linings. Sulfate reducers
may also exist naturally hi some oil and water producing strata.35
In addition to being corrosive, hydrogen sulfide is highly toxic and can cause embrittlement of
steel. Hydrogen sulfide is sometimes present in significant quantities in the hydrocarbon producing
formations where it was created in the past by sulfate reducing bacteria that were present hi the formation.
When brought to the surface, it separates out with the gas phase. This type of natural gas is referred to
as "sour gas" and is a potential health problem for operators. Thus, its presence requires safety training
of operators and the use of special safety equipment and preventive measures. In addition, the corrosion
and embrittlement problem may require the use of special steel alloys or coatings in the production
equipment. The sour gas must be treated to remove hydrogen sulfide prior to delivery to the pipeline.41
Operators in Cook Inlet have expressed concern that the replacement of seawater with treated
produced water for use in waterflooding will result in the growth of sulfate reducing bacteria.28 If so, the
bacteria will plug the formation and will generate hydrogen sulfide which will return to the surface with
the produced fluids creating corrosion and safety hazards. The reason that this does not currently occur
is that the seawater does not contain the nutrients necessary to promote bacterial growth. However, the
operators claim that the standard treatment chemicals used in processing the produced water contain
nutrients that will promote bacterial growth and that the previous use of seawater for waterflooding has
introduced a substantial quantity of sulfate to the formations.
Bacteria Prevention and Treatment - As noted above, the prevention of bacterial growth is
primarily remedied with the use of bactericides which are injected into the produced water treatment system
influent. In addition, if process treatment chemicals are the source of nutrients that are conducive to
bacterial growth, the substitution of these chemicals with ones that do not contain the nutrients can be an
effective preventive measure.42 Chemical treatment can be continuous, although batch treatment is often
more cost-effective than continuous treatment.. One source states that chemical addition should be as near
the water source as possible, and should be added where good mixing is possible.39 Addition of the
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chemical to the water intake line, down the annulus of the supply well, or downstream of the supply pump
are common locations.
Pigging facilities installed in systems with large diameter pipelines that run for several miles
remove deposits and part of the biofilm built up in the pipe.39 If a batch of biocide follows the line scraper
(or "pig"), the effectiveness of the biocide is increased because the chemical can readily contact the
remaining biofilm. This can result in substantial savings in chemical treatment costs.39
Injection Into Producing Formations - Injection into producing formations is not extensively
practiced in the coastal region of the Gulf of Mexico because of potential problems that waterflooding can
cause by adversely changing the field pressure.26 These pressure changes can cause a production loss from
nearby production wells either by coning at the injection wellbore or, if there is directional permeability
within the reservoir, the rapid return of injected water back to the production wellbore. Increased pressure
can also cause movement of the formation fluid containing the oil and gas away from the production
wellbore. These movements may result in reduced production. Because each production area has its own
unique set of conditions, each site must be individually evaluated for potential problems mat may arise from
injection into a producing formation. Despite these potential problems, waterflooding is practiced in some
locations of the coastal Gulf of Mexico, and extensively in coastal California and Cook Inlet (see Chapter
IV for details regarding the coastal industry profile).
5.2.2.4 Down-Hole Remedial Measures
The text in this subsection is excerpted from the publication entitled "Subsurface Saltwater Injection
and Disposal."38 The information provided in this publication is a generalized overview of injection
operations provided by the largest oil and gas industry association hi the United States, the American
Petroleum Institute.
During the life of an injection system, formation capacity may decrease significantly due to
formation plugging (from suspended solids, precipitation, hydrocarbons, or bacteria) or fouling of flowlines
from scale or biological growth. Should these problems develop, the following remedial measures have
been used to increase and prolong capacity.38
Acidizing - In many cases the receptivity of a formation may be improved or restored by acid
treatments. In carbonate formations, acid will dissolve or etch fluid passageways through the treated area
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of the formation, creating an enlarged effective well bore. In all formations, foreign materials introduced
while drilling, completing, or injecting into a well may block or plug the formation. Acid cleanup
treatments may dissolve, loosen, shrink, or affect these foreign materials so that they may be removed by
swabbing, or dispersed by flushing. A well should never be left shut-in following acid treatments. The
spent acid and residual products should be removed from the well bore immediately after the reaction time
of the acid.38
One of the commercial facilities in the 1992 EPA coastal sampling effort reported that they
routinely added acid to their first equalization tank prior to injection. This was most likely done to reduce
the quantity of scales and sludges present in the incoming water shipments as well as those that may form
as a result of the mixing of water from different sources. Scales and sludges that are effectively treated
with acid include calcium carbonate, magnesium carbonate, iron oxide, and iron sulfide.38
Sand Jetting or Under Reaming - An injection well completed in open hole (without casing) may
cease to take water because of damage or plugging at the formation face. The formation can be
reconditioned by removing the face of the formation with a high velocity jet of sand-laden fluid, or by
cutting away the face of the formation using an underreamer. In cases of insoluble scale damage, these
methods could be more effective than acid treating.38 None of the nine onsite or two commercial offsite
injection facilities in the 1992 EPA Coastal sampling effort reported performing a sand jetting or
underreaming operation on an injection well.31
Backwashing - Periodically, wells can be backflowed to clean the formation face. Backwashing
is performed by sparging gas, usually nitrogen, near the bottom of the injection tubing which creates an
upward flow of injection/formation fluid and solids that are plugging the formation face. This operation
is similar hi principal to backwashing a filter. The fluids and solids are captured in tanks and are hauled
offsite for treatment and disposal. In some cases the fluids and solids are treated onsite, and the treated
fluids are injected. Special strings of tubing are used to facilitate this operation. One practice that is
becoming increasingly more common is the use of coil tubing. Coil tubing refers to a long flexible metal
tube that is stored on a large spool. The tube is inserted down the well production tubing to perform the
backwash. The method is replacing the old method of using rigid threaded pipe sections which takes more
time and manpower to utilize. This operation was the most commonly cited remedial measure conducted
by the facilities in the 1992 EPA Coastal sampling effort.31
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Treating with Solvents, Dispersants, and Other Chemicals - In special cases where injection
v/ells have suffered loss of receptivity from known or identifiable causes, chemical treatments for the
specific cause may be appropriate. Treatments of this type include solvents to remove asphaltines or
paraffins, converter type treatments for the relatively acid-insoluble scales such as calcium sulfate or
barium sulfate, fresh water for the removal of salt blocks, and emulsion breakers for an emulsion
problem.38
5.2.2.5 Pretreatment of Produced Water Prior to Injection
Pretreatment of produced water may be necessary to prevent scaling, corrosion, precipitation, and
fouling from solids and bacterial slimes. Corrosion and scale deposits lead to decreased equipment
performance and to plugging hi the underground formation. One method to overcome this problem is to
increase injection pressures. However, excessive injection pressure may fracture the receiving formation
causing the escape of produced water into freshwater or other mineral bearing formations. Injection well
permits specifically identify the maximum allowable injection pressure which is based on an estimation of
the injection formation fracture pressure. Also, additional energy (fuel) is necessary to obtain the higher
discharge pressures and consequently results in increased air emissions.
Most coastal treatment systems are classified as closed systems which operate in the absence of air.
As stated earlier, all of the production facilities visited by EPA in 1992 used closed systems.31 This
alleviates the problems arising from oxygen induced corrosion, scaling, and chemical precipitation. In a
closed system, a blanket of natural gas is maintained over the produced water hi pipelines and tanks.
Pretreatment for injection can include gravity separation, gas flotation, and/or filtration. At coastal
facilities in the Gulf of Mexico region, the most common form of pretreatment used is gravity separation
(settling) and filtration using cartridge or bag filters. These technologies can be used as treatment prior
to discharge or injection, and are described hi detail hi Section 5.2.3.1. The settling tanks are usually part
of the existing BPT treatment system, whereas the filters are usually installed with the injection system to
prevent the plugging of the injection formation. Filters are used especially at facilities located in water to
minimize the frequency of performing well workovers. Facilities located over land may opt to delete the
filtration step and conduct periodic well workovers instead. Well workovers in water areas are more
expensive (see Section XI.3.2.1.2). Filtration is discussed in more detail in the following section.
vm-42
-------
5.2.3 Filtration
Filtration is widely used for produced water treatment as a polishing step for the removal of
suspended solids following the oil separation processes. Filtration is generally utilized to improve the
injection characteristics of produced water.35 Cartridge filtration is commonly used at coastal facilities in
the Gulf of Mexico as a pretreatment step prior to injection to prevent plugging of the injection formation,
and was included hi the compliance cost estimates for subsurface injection of produced water in the coastal
Gulf of Mexico region (see Chapter XI). Filtration can also be used as a treatment step prior to surface
discharge.
Crossflow membrane filtration was investigated in detail during the development of the Offshore
Effluent Guidelines where it was determined that widespread use is hampered by operational problems.
Therefore, this technology was not selected for consideration in any options for the coastal subcategory.
5.2.3.1 Cartridge Filtration
Cartridge filtration involves the passage of water through disposable filter elements (cartridges) to
remove solids. The cartridges are housed in a filter chamber that can hold from several, and up to 27 or
more cartridges, depending on the flow capacity of the unit. Figure Vni-4 presents a schematic diagram
of a typical cartridge filtration system. The filter element consists of a hollow cylinder of tightly wrapped
twine that is several inches in diameter. The cartridges come in various grades ranging from five
micrometers (ji) nominal pore size to 50ji or greater. The chamber is arranged so that water is forced
tangentially through the fibers of the cartridge to the center and out one end of the cartridge. As solids
build up on the cartridges, the pressure drop across the filter increases. The pressure drop is monitored
by the operator and when the pressure drop exceeds a specified amount, usually between 10 psi and 20 psi,
the filter chamber is taken.out of service and the cartridges are replaced. The frequency of filter changeout
is dependant on the quality and flowrate of the influent and was observed hi the field to range from several
days to a week or more.
A typical arrangement is two sets of filters arranged in parallel, with each set capable of processing
the entire flow so that the flow can be alternated from one set to the other to allow for continuous operation
during filter changeout. In some arrangements, each set of filters consist of two filters in series with finer
grade filters in the downstream position. This arrangement extends the life of the finer filter which will
clog up more quickly without prefiltration.
vra-43
-------
Row Schematic Pictorial Representation
0=5
Influent to
Filtration
\
\
__
/
/
*
*
*
«.«..
1
V
i
1
<3-
-
-e»
__,„
1
¥
1
t
I
i I
*
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*
*
.™™
i
f
1
1
X
___.
f V f
G^ili^
irfft'n!
i M
!
II
Cartridge Filters |
(evenly spaced) I
/ f t- • • ; ; . I '. Ik
tjPf :!**>
kw¥W
Qjz^ffrs
V f\ J
Influent to
Filtration
\
/^~s
r\
A\_
-^ ^_
/
Block Valve
)^f^
irss?m
i !
1 i
u
Jl
. A ,
=(D
Cartridge
Filters
^
RD
\
x^V-Ax x^wyx
\\ Y\ Pressure Quage
_^ \_ ,«0 & A
V
\
T^;,^
\ Bio* Valve ~\
Pressure Guage Effluent to Disposal
Disposal
Figure Vm-4
Cartridge Filter
-------
At the ten production facilities investigated by EPA in 1992, cartridge filtration was used by three
of the four facilities that utilized filtration as a pretreatment step prior to injection (the fourth facility uses
a 200 mesh screen).3 Table Vffl-8 presents a summary of the produced water influent and effluent data
from these three facilities. The cartridge filtration systems used at the three production facilities consisted
of the following: Greenhill Petroleum at Bully Camp used a single stage 40/j. filter; Texaco at Bayou Sale
and Texaco at Lake Salvador used a two-stage filtration system with 25/j. filters followed by 10^ filters.
It should be noted that each of these facilities used gas blanket systems to prevent air from coming into
contact with the produced water. When the samples were collected, the samples developed an increase in
turbidity after contact with air. This turbidity increase was the result of the precipitation of scale particles
such as calcium carbonate that formed when the samples came in contact with air. This resulted in an
increase in TSS. Therefore, the observed TSS concentrations in Table Vin-8 may not be representative
of the actual concentrations as they existed in the closed systems.
Oil and grease reduction averaged 28% across the filters from these three sites. However, one site
realized an 8 % increase in oil and grease concentrations. Of these three sites, only one site employed
chemical addition during water separation and this was a surfactant. Oil and grease reduction across this
filter averaged 30%, however, oil and grease effluent concentrations averaged 78.5 mg/1 (the highest
average oil and grease level of all 3 sites).43
A review of other pollutant reductions across the filters for these three sites does not show notable
reductions. Other parameters including TOC, total phenols, aluminum, lead, benzene, and toluene showed
increases of 1 to 5 %.
A preliminary estimate of oil and grease effluent limitations using these data resulted in a daily
maximum of 65 mg/1 and a monthly average of 40 mg/1.43 The long term average was estimated to be 24
mg/1. As a result of this information, EPA does not consider cartridge filtration as a candidate technology
for BAT or NSPS because not only do pollutant concentrations sometimes increase, but for the pollutants
that are removed, the removal is not as effective as improved gas flotation.
5.2.3.2 Granular Filtration
Granular media filtration involves the passage of water through a bed of filter media to remove
solids. The filter media can be single, dual, or multi-media beds. When the ability of the bed to remove
suspended solids becomes impaired, cleaning through backwashing is necessary to restore operating head
vm-45
-------
TABLE Vm-8
INFLUENT AND EFFLUENT POLLUTANT CONCENTRATION MEANS
FROM CARTRIDGE FILTRATION6
Pollutant
Inflnenf Mean.
: %sE?flHait '
^Jfopujbisffi ^
CONVENTIONAL AND NON-CONVENTIONAL
POLLUTANTS
Total Recoverable Oil
and Grease
Total Suspended Solids
Ammonia as Nitrogen
Chloride
Total Dissolved Solids
Total Phenols
49,904
139,917
75,947
70,753,000
115,377,667
2,363
31,426
136,792
73,937
71,423,083
117,719,167
2,407
PRIORITY POLLUTANT METALS
Cadmium
Chromium
Copper
Lead
Nickel
Silver
Zinc
61
140
146
430
281
560
652
61
135
145
422
274
590
395
OTHER METALS
Aluminum
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Sulfur
Tin
Titanium
Vanadium
Yttrium
1,403
50,338
28,059
2,411,483
228
15,935
485,158
1,431
155
2,150
300
24
324
21
1,426
51,124
28,751
2,413,592
224
15,994
490,460
1,444
154
2,195
312
31
322
44
f v-, ^ ^ ' -*
' Pollutant ' '" "
w feanent
Mean{^g/I)
/- Effluent
Mean&g/l).
PRIORITY POLLUTANT VOLATILE ORGANICS
Benzene
Ethylbenzene
Toluene
6,689
63
5,191
6,721
63
5,227
OTHER VOLATILE ORGANICS
m-Xylene
o+p Xylene
2-Hexanone
193
118
55
HtlOJKlTY JPOLLO'f AJNT SJKJVU-
ORGANICS
Naphthalene
Phenol
222
947
184
112
53
VOLATILE
215
937
OTHER SEMI-VOLATILE GRGAmuS
Benzole Acid
Hexanoic Acid
n-Decane
n-Dodecane
n-Eicosane
n-Hexadecane
n-Octadecane
n-Tetradecane
o-Cresol
p-Cresol
2Methylnaphthalene
2,4-Dimethylphenol
7,638
1,762
210
156
55
222
53
73
107
313
76
184
7,356
2,064
109
253
50
201
49
73
147
258
73
185
•• , ' < ,•• -, /••••.• '
" '";i" ' > ', - ','",',"
vv. v1- :& : •" ;:•.:•.•. \ ::: : -.
' * •:•. V> ••
' 1 t , ' ' ^ ''>,'"•
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, ' ' ' ' """ ' ' f ',„„,.
^- •. * ~- ff * ' '*, Jy " f- ^••5.'
* '• ; v '*•• f '-' "
and effluent quality. There are a number of variations in filter design systems. These include: (1) the
direction of flow: downflow, upflow, or biflow; (2) types of filter beds: single, dual, or multi-media;
(3) the driving force: gravity or pressure; and (4) the method of flow rate control: constant-rate or variable-
declining-rate.35 Figure Vni-5 shows the schematic of a multi-media granular filter.
The Offshore Guidelines three-facility study evaluated granular filtration systems designed to
pretreat produced water following oil separation and prior to injection.44 These particular operations inject
produced water either because of a zero discharge permit requirement or for enhanced oil recovery. The
vm-46
-------
Anthracite
3' 2" No. 3 Sand
Stratified Rock
Figure Vni-5
Multi-Media Granular Filter
Vm-47
-------
three facilities evaluated were: Conoco's Maljamar Oil Field near Hobbs, New Mexico; Shell Western
E&P, Inc. - Beta Complex off Long Beach, California; and the Long Beach Unit -Island Grissom which
is owned by the City of Long Beach, California, and operated by THUMS Long Beach Company.
EPA statistically analyzed the data from these facilities to determine effluent levels achievable from
add-on granular media filtration technology. Table Vffl-9 presents the performance of granular media
filtration for oil and grease and TSS, based on calculated daily composites. Granular filtration has
demonstrated good removals of TSS and oil and grease at the two facilities using chemical coagulants and
flocculants to enhance separation, thus improving filtration performance.
TABLE Mn-9
GRANULAR MEDIA FILTRATION PERFORMANCE44
s«« .i***1 «•*»«„
< ff r f' J
' , * */ '
t *'«
Thums Long Beach
(With Chemical Addition)
Filter Influent
Filter Effluent
% Removal
Conoco, Hobbs
(With Chemical Addition)
Filter Influent
Filter Effluent
% Removal
$" \f -*«-L "HM." A * £•"*«*
£ „ /MB {kUBflOK* v
•X •> Wi? 'CV^ f
43.27
25.65
40.7%
102.84
48.77
53%
Oil and Grease (mg/lf ;
20.75
11.22
46%
34.54
10.90
68%
* TSS concentrations represent flow weighted averages of paired samples for each day of sampling.
* Composite sample concentrations estimated by the arithmetic average of sample concentrations within a day.
5.2.3.3 Crossf/ow Membrane Filtration
Crossflow membrane filtration is an ultrafiltration process. The process operates at low pressures,
less than 100 pounds per square inch (psi). The membrane pore sizes range from 0.03 to 0.8 micrometers.
Crossflow filtration minimizes the accumulation of participates on the surface of the membrane by flowing
vra-48
-------
the feed stream over the surface of the membrane to sweep away part of the accumulated layer on the
membrane. Figure Vm-6 presents the flow dynamics of a crossflow filter. Crossflow filtration requires
recirculation of the process stream that may be several orders of magnitude greater than the rate of
filtration. The advantage of crossflow filtration is that the membrane's life and periods between cleaning
cycles are extended through constant membrane scouring by the particulates hi the produced water.45 In
addition to the high velocities of produced water across the membrane surface to prevent membrane
fouling, some systems utilize a backflow of permeate (i.e., filter effluent) through the membrane to
dislodge any oil or solid particles embedded within the pores of the membrane.
Several types of crossflow membrane filters have been pilot or field tested for the treatment of
produced water. The two common types of membrane materials are an inorganic ceramic material and an
organic polymeric material. Membrane module designs include hollow fiber, spiral wound, and tubular.
Many systems require either pre-filtration or chemical treatment to prevent rapid membrane fouling and
flux degradation. For flux restoration, some systems utilize on-line membrane cleaning, such as
backpulsing, while others require system shutdown and physical cleaning of the membrane. This
technology was investigated during the development of the Offshore Guidelines.
One type of crossflow membrane filtration system is currently being operated on two different
platforms located in the Gulf of Mexico. One is a 5,000 barrel per day full scale unit processing a partial
stream (slip stream) of the produced water for waterflood injection purposes.46 The ceramic membranes
used in these filtration modules are made of porous alumina. The alumina membranes have a pore size
of 0.8 micrometers. The produced water stream is chemically pretreated with ferric chloride. Through
a hydrolysis reaction between the produced water and ferric chloride, a ferric hydroxide floe is formed.
The ferric hydroxide floe develops a precoat layer on the surface of the membrane and serves as a
"dynamic membrane." This, "dynamic membrane" is unique to this system and allows water to permeate
through the ceramic membrane while reducing the rate of accumulation of oil and oil wet solids on the
membrane surface. A backpulse cycle serves to constantly replace the "dynamic membrane" with a fresh
ferric hydroxide floe precoat. However, the "dynamic membrane" does not completely prevent the
membrane from fouling. When backpulsing does not restore the permeate flux rates, shutdown of the
system is necessary for chemical cleaning.47
In 1991, EPA conducted a week long sampling episode of the. full scale unit described in the
preceding paragraphs. Data obtained from this sampling effort indicate that the total oil and grease of the
vm-49
-------
Ultrafiltrate
Membrane
**
Feed in
*
* •
Membrane
* * ••••••••• •••«*
%'• .* -.'•":; • •". % \.*.;. .*.: .%%%•
»• •••••%•«•••%>••••«••%••
i i
i i i i i i
Ultrafiltrate
Boundary
layer
Retentate
out
Boundary
layer
Figure VIH-6
How Dynamics of a Crossflow Filter
-------
effluent can be as low as 3.5 mg/1 with an influent oil and grease concentration of 22 mg/1. The sampling
program also analyzed the filtration process for removal efficiencies and potential concentration of TSS,
organic compounds, metals, and radionuclides. Table VIII-10 presents data obtained from the sampling
program.
Despite the potential of high pollutant removal efficiencies, use of crossflow membrane filtration
for the treatment of produced water has been hampered by operational problems, due to membrane fouling,
experienced by several of the pilot and full scale units, including the unit studied in the 1991 EPA sampling
program. The unit evaluated was being operated at 20 percent of the design capacity due to a barium
sulfate scale build-up on the membrane surface.
The filtration unit was also bypassed several times during the sampling program due to upsets in
the produced water treatment system. The unit was bypassed as a preventative measure to avoid sending
water with a relatively high oil and solids content to the filter. The membrane pores can be easily plugged
during high loadings of oil and solids. If the membrane pores become oil wet or plugged with solids,
significant flux reduction results and shutdown of the filter is necessary for chemical cleaning. The
operator was also experiencing problems with the waste streams generated from the filtration process. The
major waste streams generated by the unit include: the oily float skimmed at the feed tank surface, the
solids concentrate blowdown stream, and the spent acid and caustic used for filter cleaning. The wastes
were being recycled into the produced water treatment system or neutralized and discharged overboard.
The wastes being recycled into the produced water treatment system were creating upsets in the chemical
equilibrium of the system. The operator indicated that a larger filtration unit would generate greater
volumes of waste which would be difficult to recycle into the produced water treatment system without
causing significant upsets and be costly to dispose of onshore.48 A more detailed description of this
technology can be found in the Offshore Development Document.2
No additional data were submitted or gathered as part of this rulemaking on the operation of
crossflow membrane filtration for treatment of produced water at full scale facilities. However, EPA has
maintained an interest in the potential for this technology through work by EPA's Treatment Research
Division, Risk Reduction Engineering Laboratory in Cincinatti, Ohio. This work is being performed by
the University of Colorado and consists of laboratory scale tests performed on oily wastewaters, including
a synthetic produced water, using a novel membrane process which employs rapid backpulsing to reduce
VIII-51
-------
TABLE
MEMBRANE FILTRATION PERFORMANCE
DATA FROM THE MEMBRANE FILTRATION STUDY"
= :;.. ..;-:•' r-Y^-i&g
:.l '; ,':-:•:•. '•:;•' '"f^'iviii-i^.
-., . . :...-_;.;-:•:-:-:;.•••"•:•;;:••
PoUutantl^raineteg^-gl
Oil & Grease
Freon (mg/1)
Hexane (mg/1)
Total Petroleum Hydrocarbon
(ragfl)
TSS (mg/1)
Priority and Non-conventional
Organic Pollutants:
Benzene
Benzoic acid
Biphenyl
Cblorobentene
Bhylbenzene
Hexanoic Acid
Methylene Chloride
Naphabene
o,p-Xylene
Phenol
Toluene
2-Butanone
2-Propanone
Priority and Non-conventional
Metal Pollutants:
Aluminum
Antimony
Arsenic
Barium
Boron
Copper
Iron
Lead
Magnesium (mg/1)
Manganese
Strontium (mg/1)
Titanium
Yttrium
Zinc
Radionuclides:
Gross Beta (pCi/1)
Radium 226 (pCi/1)
Radium 228 (pCi/1)
MsWifesa
sss«MB«Wfiw
••' • >'•*:. •'• l^S ''':';.v:v;:::-v
iinHiii^
16.33
8.0
16.33
67.0
738.38
51
10
10
62.6
10
10
10
34.15
* 10
438.4
180.4
50
875
3
165
92,150
6,950
30
24,300
150
2,280
1,440
181
9
9
24
296.0
381.0
511.8
p^SiSKg«SS£:
(iKgiiftxjciBp^Wni
<:-;'::$;:S:;:;:::::*S;:rv:3:r:r::i*S-
42.67
21.67
42.67
86.0
1,050.32
84.83
557.41
16.5
114.3
14.4
148.3
29.6
83.4
53.4
650.5
1,206.0
1,901.1
2,270
617
211
135,220
8,050
31
28,800
530
2,495
1,965
224
12
14
38
442.5
643.0
863.6
'&&';& i^£&&::ft:;:!tf:V:
^fWi^^j^^
&:^:^-:*x-£^'":^'-;$>v#i$
itliliilliit
19.67
11.0
19.67
82.0
925.35
67.82
10
11.78
90.1
10
83.2
17.8
53.7
10
556.7
282.0
1,004.3
1,660
30
187
130,000
7,620
30
27,500
150
2,450
1,960
218
9
9
25
328.0
484.0
604.3
;®:$;&IitJW§n.tg:
::;:-:;;1:£:::;;v:jSw;*:W:ft:::::::
3
3.0
3.0
86.0
441.5
50.0
10
10
10
10
10
10
31.0
10
445.9
182.1
50
343
30
127
90,250
6,790
30
26,100
150
2,280
1,910
202
9
9
24
296.0
521.0
130.4
S;;f|;::;Kg!iWp;«
;:'i'::^:x:%5:W::S:^-V:-:-;S-
7.67
6.33
7.67
97
958.9
50.4
10
15
77.2
47.2
138.7
21.5
47.3
66.1
607.1
2,610.2
2,686.1
1,351
4,200
256
142,000
7,830
30
28,450
314
2,495
2,325
226
17
17
45
390.5
616
868.3
Bg&gqAfgqJm&&
$:#::^::::;:^;:*:i:S:::;x*:::::
4.67
3.33
4.67
97
860.0
50.0
10
10
61.8
10
10
13.1
35.4
10
517.5
305.8
1,215.2
1,100
264
160
128,000
7,570
30
26,900
212
2,460
2,265
216.5
9
9
28
304
583.0
579.7
* Pollutant Concentration "Minimum Level" Values were Substituted for Non-detect Samples
NR«Not Reported
vm-52
-------
fouling. Results of these tests were very promising with excellent removals of oil while maintaining high
flux rates.49-50
5.2.4 Activated Carbon Adsorption
Activated carbon is a material which selectively removes organic contaminants from wastewater
by adsorption. Activated carbon can be used both as an in-plant process for the recovery of organics and
as an end-of-pipe treatment for the removal of dilute concentrations of organics from wastewater prior to
discharge or recycle. Key design parameters for an activated carbon unit include the quantity and quality
of wastewater to be treated, the required effluent quality, type and quantity of activated carbon, the empty
bed contact time, and the breakthrough capacity before regeneration is necessary.
Generally, activated carbon systems are preceded by treatment systems such as chemical treatment
or filtration to remove the suspended solids and any other materials which might be present in the
wastewater and which interfere with the adsorption phenomenon. Presently, activated carbon is not
generally used in the treatment of produced water from oil and gas wells.
EPA determined that carbon adsorption is not technologically available to implement as a basis for
BAT or NSPS limitations for the treatment of produced water from coastal oil and gas production. This
is because of the lack of treatability information related to the effects of treating large volumes of the brine-
like nature of produced water on the adsorption process, either from literature or from pilot or full-scale
studies.
vm-ss
-------
6.0 REFERENCES
1. SAIC, Statistical Analysis of the Coastal Oil and Gas Questionnaire. Final Report, January 31,
1995.
2. EPA, Development Document for Effluent Limitation Guidelines and New Source Performance
Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category. EPA
821-R-93-003. January 1993.
3. SAIC, Coastal Oil and Gas Production Sampling Summary Report, April 30, 1993.
4. SAIC, "Oil and Gas Exploration and Production Wastes Handling Methods hi Coastal Alaska,"
January 6, 1994
5. Jordan, R., U.S. EPA, Memorandum to the record regarding "Characterization of BPT-Level
Produced Water Effluent for Coastal Subcategory Facilities hi the Gulf of Mexico," August 29,
1996.
6. SAIC, "Statistical Analysis of Effluent from Coastal Oil and Gas Extraction Facilities (Final
Report)", September 30,1994.
7. Mason, T., Avanti, Memorandum to the record regarding pCi/1 to jig/1 Conversion Factors for
Lead 210, Radium 226, and Radium 228, April 23, 1996.
8. Envirosphere Company, Summary Report: Cook Inlet Discharge Monitoring Study: Produced
Water. Discharges Number 016, prepared for the Anchorage Alaska Offices of Amoco Production
Company, ARCO Alaska, Inc., Marathon Oil Company, Phillips Petroleum Company, Shell
Western E&P, Inc., Unocal Corporation, and U.S. Environmental Protection Agency, Region 10,
September 1988 through August 1989. (Offshore Rulemaking Record Volume 120)
9. Alaska Oil and Gas Association (AOGA), "Comments on USEPA 40 CFR Part 435 Oil and Gas
Extraction Point Source Category, Offshore Subcategory, Effluent Limitations Guidelines and New
Source Performance Standards, Proposed Rule," May 13, 1991. (Offshore Rulemaking Record
Volume 138)
10. Ferraro, J.M. and S.M. Fruh, "Study of Pollution Control Technology for Offshore Oil Drilling
and Production Platforms," Prepared for U.S. Environmental Protection Agency. Cincinnati,
1977. (Offshore Rulemaking Record Volume 24)
11. Churchill, R.L., "A Critical Analysis of Flotation Performance," American Institute of Chemical
Engineers, 290-299, 1978. (Offshore Rulemaking Record Volume 168)
12. Sport, M.C., "Design and Operation of Dissolved-Gas Flotation Equipment for the Treatment of
Oilfield Produced Brines," Journal of Petroleum Technology. 918-921, 1970. (Offshore
Rulemaking Record Volume 168)
13. Leech, C.A., "Oil Flotation Processes for Cleaning Oil Field Produced Water," Shell Offshore,
Inc., Bakersfield, Ca., 1987. (Offshore Rulemaking Record Volume 168)
vm-54
-------
14. Pearson, S.C., "Factors Influencing Oil Removal Efficiency in Dissolved Air Rotation Units," 4th
Annual Industrial Pollution Conference, Houston, Texas, 1976. (Offshore Rulemaking Record
Volume 168)
15. Kumar, I.J., "Flotation Processes," Lenox Institute for Research Inc., Lenox, Mass., 1988. NTIS
No. PB 88-180302
16. Arnold, K.E., "Equipment and Systems Used to Separate Oil From Produced Water on Offshore
Platforms," Paragon Engineering Services, Inc., Houston, Texas, 1987. (Offshore Rulemaking
Record Volume 168)
17. Krofta, M., et al., "Development of Low-Cost Flotation technology and systems for Wastewater
Treatment," Proceedings 42nd Industrial Waste Conference, 1987, Purdue University, Lewis
publishers, Chelsea, MI, 1988.
18. SAIC, "Final Report: Statistical Analysis of Settling Effluent from Coastal Oil and Gas Extraction
Facilities," June 27, 1996.
19. Brown and Root, Inc., "Determination of Best Practicable Control Technology Currently Available
to Remove Oil and Gas," prepared for Sheen Technical Subcommittee, Offshore Operators
Committee, New Orleans, March 1974. (Offshore Rulemaking Record Volume 21)
20. Lysyj, I., et al., "Effectiveness of Offshore Produced Water Treatment," API et al., Oil Spill
Prevention, Behavior Control and Clean-up Conference (Atlanta, GA) Proceedings, March 1981.
(Offshore Rulemaking Record Volume 37)
21. Wyer, R.H., et al., "Evaluation of Wastewater Treatment Technology for Offshore Oil Production
Facilities," Offshore Technology Conference, Dallas, Texas, 1975. (Offshore Rulemaking Record
Volume 168)
22. Conoco, Inc., Treating Production Water to Remove Oil. (Offshore Rulemaking Record Volume
143)
23. Chemical Composition Study of Produced Water at Some Offshore Oil Platforms. March 1982.
(Offshore Rulemaking Record Volume 143)
24. Luthy, R.C., "Removal of Emulsified Oil with Organic Coagulants and Dissolved Air Flotation,"
Journal Water Pollution Control Federation. 1978,331-346. (Offshore Rulemaking Record Volume
168)
25. Rochford, D.B., "Oily Water Cleanup Using Gas Flotation," Offshore Technology Conference,
OTC 5247, 1986. (Offshore Rulemaking Record Volume 168)
26. ERCE, "An Evaluation of Technical Exceptions for Brine Reinjection for the Offshore Oil and Gas
Industry," prepared for Industrial Technology Division, U.S. Environmental Protection Agency,
March 1991. (Offshore Rulemaking Record Volume 119)
27. Mclntyre, J., Avanti, Memorandum to the Record regarding "Coastal Gulf of Mexico Production
Facilities Currently at Zero Discharge for Produced Water," September 30, 1996.
vm-55
-------
28. Marathon Oil Company and Unocal Corp., "Zero Discharge Analysis Trading Bay Production
Facility, Cook Inlet, Alaska," March 1994.
29. Walk, Haydel and Associates, Inc., "Potential Impact of Proposed EPA BAT/NSPS Standards for
Produced Water Discharges from Offshore Oil and Gas Extraction Industry," Report to Offshore
Operators Committee, New Orleans, LA, 1984. (Offshore Rulemaking Record Volume 16)
30. American Petroleum Institute. "Subsurface Saltwater Injection and Disposal," 1978.
31. SAIC, "Produced Water Injection Cost Study for the Development of Coastal Oil and Gas Effluent
Limitations Guidelines," January 27, 1995.
32. Cadmus Group, Inc., Evaluation of Class II Regulatory Impacts. Preliminary Draft. July 27,
1992.
33. SAIC, "Oil & Gas Point Source Category: Trip Report of the U.S. EPA's Visit to the THUMS
Island Grissom Facility on February 7, 1992." July 16, 1992. (Offshore Rulemaking Record
Volume 165)
34. Stewart, Maurice, Minerals Management Service, New Orleans Office, Personal communication
with Joe Dawley, SAIC, regarding reinjection of produced water in the Gulf of Mexico. May 8,
1992. (Offshore Rulemaking Record Volume 174)
35. Bums & Roe. Technical Feasibility of Brine Reinjection for the Offshore Oil and Gas Industry,
May 1981. (Offshore Rulemaking Record Volume 2)
36. Wetzel, "Limnology," W.B. Saunders Company, Philadelphia, Pennsylvania, 1975.
37. Ford, W., et al, "Solvent Removes Downhole NORM - Contaminated BaSO4Scale," in Oil & Gas
Journal, April 22,1996.
38. American Petroleum Institute, "Subsurface Saltwater Injection Disposal," October, 1995.
39. Patton, C., "Applied Water Technology," Campbell Petroleum Series, Norman, Oklahoma, June,
1986.
40. U.S. EPA, "Trip Report to Campbell Wells Land Treatment, Bourg Louisiana, March 12, 1992."
May 29, 1992.
41. American Petroleum Institute, "Introduction to Oil and Gas Production," 1983.
42. Dawley J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Technical Feasiblity of
Replacing Seawater with Produced Water for Waterflooding in Cook Inlet, June 21, 1994.
43. Wiedeman, EPA, Memorandum to Marv Rubin, EPA regarding use of cartridge filtration as
technology basis for effluent limitation options, June 16, 1994.
44. SAIC, "Engineering Report on Granular Filtration Based on the Three Facility Study," prepared
for the Engineering and Analysis Division, U.S. Environmental Protection Agency, April 8, 1992.
(Offshore Rulemaking Record Volume 174)
vra-se
-------
45. Schweitzer, Philip A., "Handbook of Separation Techniques for Chemical Engineers," Second
Edition, McGraw-Hill Book Co., New York, Chapter 2, 1988.
46. Yang, J.C., Meyer, J.P., "Industry's Field Experience With Membrane Filtration Technology,"
June, 1991. Submitted as comments to 56" S 10664 by Craig W. Gordy, Marathon Oil Company,
June 10, 1991. Commenter number 50 (Offshore RulemaMng Record, Volume 147).
47. Offshore Operators Committee, "Crossflow Membrane Separation Systems Study," prepared by
Paragon Engineering Services, project No. 90421, December, 1990. Submitted as comments to
56 ER 10664 by C.T. Sawyer, American Petroleum Institute, Volume 2, Tab 1, May 13, 1991.
Commenter number 42 (Offshore RulemaMng Record, Volume 142).
48. SAIC, "Produced Water Pollutant Variability Factors and Filtration Efficacy Assessments from the
Membrane Filtration Oil and Gas Study," prepared for Engineering and Analysis Division, Office
of Science and Technology, U.S. Environmental Protection Agency, January 13, 1993.
49. Davis, Robert H., "Rapid Baekpulsing as an Advanced Membrane Technology for
Recycle/Treatment of Wastewaters," prepared for U.S. EPA, Treatment Research Division, Risk
Reduction Engineering Laboratory, September 1996.
50. Mueller, J., et aL, "Crossflow Microfiltration of Oily Water," University of Colorado, Boulder,
Colorado.
VHI-57
-------
-------
CHAPTER IX
MISCELLANEOUS WASTE-
CHARACTERIZATION, CONTROL AND TREATMENT TECHNOLOGIES
1.0 INTRODUCTION
This section describes the sources, volumes, and characteristics of miscellaneous waste streams
from coastal oil and gas exploration, development, and production activities. The miscellaneous waste
streams considered for regulation are:
Well treatment, workover, and completion fluids
Deck drainage
Produced sand
Domestic wastes
Sanitary wastes.
This section also includes a brief description of the minor waste streams associated with coastal oil
and gas drilling and production and a description of the treatment technologies currently available to reduce
the quantities of pollutants associated with these wastes.
2.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
The definitions for well treatment, workover, and completion fluids (TWC fluids) are as follows:1
Well Treatment Fluids are "any fluids used to restore or improve productivity by chemically
or physically altering hydrocarbon-bearing strata after a well has been drilled."
Workover Fluids are "salt solutions, weighted brines, polymers, or other specialty additives
used hi a producing well to allow safe repair and maintenance or abandonment procedures."
Completion Fluids are "salt solutions, weighted brines, polymers and various additives used
to prevent damage to the wellbore during operations which prepare the drilled well for
hydrocarbon production."
IX-1
-------
Table IX-1 lists the data used in the compliance cost analysis for TWC fluids, presented in
Chapter XH. These data include the number of wells discharging TWC fluids, the average volume
discharged per job, and the total annual discharge volumes. The sources and derivation of these data are
described hi the following section.
TABLE IX-1
DATA USED IN TWC FLUID COMPLIANCE COST ANALYSIS2
Fluid
Workover/Treatment
Completion
TOTAL
«- S "• £, S ">."< ^ •.
" * Number of ** - ^
; Dfecharging'WeBs "
A * "tr f ^K* ^' '-
s * ^ s C, \ """{"i "•
*s . _, "* \ f
350
334
684
- ' Average^ Volume
- Discharged per ,
- ''"&$& r\&
v> ' * v - - '^
587
209
—
; Total Volume
\- Discharged' per
j-, ^ f f f f. f t f fft «i
;""- v^l:;/'?
205,450
69,806
275,256
a Values are for coastal Gulf of Mexico operations only. Since Cook Inlet operators commingle TWC fluids with produced
water for treatment, compliance costs for Cook Inlet TWC fluids are included in the Cook Inlet produced water cost analysis
(see Chapter XQ for details regarding the cost analysis).
2.1 WELL TREATMENT, WORKOVER, AND COMPLETION FLUID VOLUMES
The volume of well treatment, workover, and completion fluids generated will vary depending on
the type of well and the specific operation to be performed. Normally, workover and completion
operations require at least one well volume of fluid since the fluids are contained within the well bore. For
example, a 10,000 foot well with 3.5 inch diameter tubing contains a volume of less than 100 barrels.2
The volume of workover and completion fluids will generally be the same before and after usage. More
than one well volume (usually no more than three) are necessary for well treatment because the fluids may
be lost to the formation. Treatment fluids can react with the formation and the volumes before and after
use are not the same.
Typically, small volume discharges of fluids occur during the course of workover and completion
operations in the same manner as drilling fluid discharges. Most completion and workover fluid discharges
occur as small volume discharges several times during the completion or workover operations (normally
lasting seven to thirty days).3 Workover and completion fluids that return to the surface as a discrete slug
IX-2
-------
represent only a small portion of the fluids discharged during workover and completion operations.1
Discharge volumes for specific workover, completion and well treatment activities are presented in
Table IX-2. This information indicates that discharges can range from 100 to 1,000 barrels.4
TABLE IX-2
TYPICAL VOLUMES FROM WELL TREATMENT, WORKOVER,
AND COMPLETION OPERATIONS4
^ ,, Operation * '
Completion and Workover
Well Treatment
' Type of Material ,
Packer Fluids
Formation Sand
Metal Cuttings
Completion/Workover Fluids
Filtration Solids
Excess Cement
Neutralized spent Acids
Completion/Workover Fluids
Volume Discharges {b&prels)<
100 to 1000
ItoSO
<1
100 to 1000
10 to 50
<10
10 to 500
10 to 200
A statistical analysis of the results of the 1993 Coastal Oil and Gas Questionnaire shows that hi
1992, workover, treatment, and completion operations in the coastal Gulf of Mexico region discharged an
average of 587 barrels of waste workover/treatment fluids and 209 barrels of waste completion fluids.5
Workover and treatment fluids are presented in this document together because they are both used during
production. Completion fluids are generated separately during completion just prior to production. For
the purpose of developing compliance cost estimates, these volumes (presented in the survey as volume per
year) are assumed to be average discharges per job because the survey results also indicate a
workover/treatment fluid discharge frequency of between 0.78 and 1.87 times per year.5 The numbers of
wells discharging TWC fluids were derived from survey results and state Discharge Monitoring Report
(DMR) data. The survey results indicate that in 1992, 219 wells discharged workover/treatment fluids and
209 wells discharged completion fluids.5 A comparison of the number of wells in the survey to the number
of wells for which DMR data are available revealed that the survey count of wells must be increased by
a factor of 1.6 for an accurate count of existing wells.6 Thus, the estimates of 219 wells discharging
workover/treatment fluids and 209 wells discharging completion fluids were increased to 350 and 334,
IX-3
-------
respectively. These well counts were then used to estimate the total annual volume of TWC fluids
currently discharged: 205,450 barrels of workover/treatment fluid and 69,806 barrels of completion fluid,
for a total of 275,256 barrels of TWC fluids discharged per year in the Gulf of Mexico.
Volumes of fluids used for workover, completion, and well treatment operations were collected
for a Cook Inlet Discharge Monitoring Study. Table IX-3 presents the volumes discharged during specific
operations. Volume information was collected for a one year period. Ten discharge events were sampled
during the course of the year. Each of the discharge events was from a single operation (either well
treatment, workover, or completion) but discharges of the fluids may have occurred at several times during
the course of the operations.7 Average discharge of TWC fluids ranged from 80 to 647 barrels per job.
TABLE IX-3
VOLUMES DISCHARGED PER JOB DURING WORKOVER, COMPLETION, AND WELL
TREATMENT OPERATIONS FROM THE COOK INLET DISCHARGE MONITORING STUDY7
Type of Job
Volumes
Discharged
(barrels)
Minimum
Maximum
Average
••
Workover
V"
600
600
400
100
1,111
492
1,200
670
100
1,200
647
?,,^t „" '"»'v
;;^p^leti6n '«
390
75
310
303
50
50
25
75
25
1,295
740
50
25
1,295
282
5 ,Wett-,--
/N TresBhnent ,
178.6
238.1
35.7
71.4
20
93
20
238.1
106
' s;-f -
' ..-Acid-v :
10.8
320.8
25
173
10.8
320.8
132
Clean Out
; ^Tabing':' ':
12
148
12
148
80
The 1993 Coastal Oil and Gas Questionnaire also provided data regarding volumes of TWC fluids
discharged in Cook Inlet, Alaska.8 Volumes of workover/treatment fluids reported in the survey as
discharged ranged from 300 to 18,000 barrels per well per year. These volumes were reported by two of
the 13 active platforms in Cook Inlet. The 18,000-bbl discharge volume was a total of three discharges
rx-4
-------
throughout the year, so the average per-job discharge volume is 3,150 bbls of workover/treatraent fluid.
Discharged completion fluid volumes ranged from 360 to 2,720 barrels per well for the year, and were
reported for four wells on two different platforms. The average per-job discharge volume is 2,243 bbls
of completion fluids. A total annual TWC discharge volume for all platforms in Cook Inlet was calculated
to be 60,496 barrels per year, based on the above per-job volumes and a seven-year schedule for drilling
new wells and recompletions provided by Cook Inlet operators.9 All discharges of TWC fluids to Cook
Inlet reported in the survey were commingled with produced water for treatment prior to discharge.
2.2 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS CHARACTERISTICS
2.2.1 Well Treatment Fluids
In general, well treatment fluids are acid solutions. Acids used include: hydrochloric acid (HC1),
hydrofluoric acid (HF) and acetic acid (Cy^O^. Concentrations of HC1 in water range from 15 to 28
percent. A mixture of hydrochloric and hydrofluoric acid is also used and is referred to as "mud acid."2
Mud acid mixtures are 12 percent HC1 and 3 percent HF in water. Acids are selected based on formation
solubility, reaction time, and reaction products. The acid reactions are temperature dependent and
temperature increases can decrease the depth of acid penetration.10
A well treatment job involves a series of several solutions to be pumped down hole: a pre-flush
solution, the acid solution, and a post-flush or "chaser" solution. The pre-flush solution is generally 3-5
percent ammonium chloride (NH4C1) and forces the hydrocarbons back into the formation to prepare for
stimulation. The acid solution is then pumped downhole. Following the acid solution is a post-flush of
ammonium chloride that forces the acid further into the formation.11 The solutions remain in the formation
for 12 to 24 hours and are then pumped back to the surface.2
Common well treatment fluids include: hydrofluoric acid, hydrochloric acid, ethylene
diaminetetracetic acid (EDTA), ammonium chloride, nitrogen, methanol, xylene, toluene. Well treatment
fluids may include additives such as corrosion inhibitors, demulsifiers, acid neutralizes, diverters,
sequestering agents, and anti-sludging agents.4 Additives include: iron sequestering agents, corrosion
inhibitors, surfactants, viscosifiers, and fluid diverters.I2 The purpose of the additives can be for: reducing
the leak-off rate, increasing the propping agents carried by the fluid, reducing friction, and preventing the
aggregation and deposition of solid particles.11 A corrosion inhibitor is always used during an acid
stimulation job because the acids used are extremely corrosive to the steel piping and equipment.2'13
Table IX-4 lists some of the typical chemicals used during well treatment.
rs-s
-------
TABLE IX-4
WELL TREATMENT CHEMICALS14
Type of Fluid or
Purpose
Fracture or matrix
acidizing agent
Acid stimulation agent
Acidizing fluid
Acid fracturing agent
Self breaking acidizing
emulsion
Acid precursor
Acidizing of siliceous
strata
Sequestering additive for
iron and aluminum in
acid stimulation
Fracturing agent
High temperature
fracturing agent
Acid stimulation
Acid fracturing
v, , <<*.<' f "4~0& ^ 'O
\Y$fofe«ta^?'" \
Acrylamide polymer
Gelling agent
Reducing agent
Acid
Vinyl pyrolidine copolymer
HC1
Water
Oxyalkylated acrylamidoalkane-
sulfonic acid polymer
Dialkyldimethyl-ammonium
chloride polymers in acid solution
Cg-Cjs primary amine
Diethanolamide of C8-Cjg fatty
acid
Kerosene
Acid solution
Carbon tetrachloride
Ammonium fluoride
Levulinic acid
Citric acid
HC1 solution
Hydroxypropyl cellulose
Poly (maleic anhydride) alkyl
vinyl ether
Aluminum salt of phosphate ester
in kerosene
Acetic acid
Acid in oil emulsion
.-- -v ,, ^ -- '','-,, """'
'- \ ' " -* '-f Dose -
0.1 to 1.5% by weight
0.5 to 30% by weight of polymer used
200% of stoichiometric amount of gelling agent
used
10% by weight
1 % by weight
8% by weight
91% by weight
1% by weight in 15 % HC1
0.1 to 1 % by weight polymer, 5 to 15% HC1
solution
0.01 to 0.5% by weight
0.02 to 1.0% by weight
25 to 35% by volume
25 to 38% HC1 solution
10% CC14
90% water
1 to 10% by weight fluoride ion concentration
10 to 400 lb/1000 gallon
10 to 400 lb/1000 gallon
15% HC1 solution
1%
3%
1 % by weight in kerosene
20 to 30%
10 to 28%
2.2.2 Workover and Completion Fluids
Workover and completion fluids are similar in nature and are typically a variety of clear brine.
Packer fluids are workover or completion fluids which are left in the annulus between the well casing and
tubing at the conclusion of the operation.3 Specific fluids are used during completion and workover
EX-6
-------
operations to seal off the producing formation to prevent fluids and solids loss to the formation. The
formation is sealed by the disposition of a thin film of solids over the surface of the formation. These
solids are called bridging agents.14 The bridging agents are oil or acid soluble and dissolve at the cessation
of workover or completion operations to enable oil or gas to be produced from the well.15 Commonly used
bridging agents are: ground calcium carbonate, sodium chloride, oil soluble resins, and calcium
lignosulfonates.16 The fluids are selected to be compatible with the formation to minimize damage to the
formation and should perform the following functions:4-16'17
• Control subsurface pressures
• Maintain hole stability
• Transport solids to the surface
• Installation of packer fluids
• Keep solids in suspension
• Minimize corrosion
• Remain stable at elevated temperatures.
Workover and completion fluids can be divided into two broad classifications: water-based and oil-
based fluids. There are three types of water-based fluids: brine water solutions, modified drilling fluids,
and specially designed drilling fluids.
Brine fluids are comprised of inorganic salts dissolved in water. This combination yields a solids-
free fluid with sufficient density to control sub-surface pressures.16 Brine solutions have a density ranging
from 8.5 pounds per gallon (ppg) for seawater to 19.2 ppg for zinc bromide/calcium bromide fluids.17
Table IX-5 lists some of the more common brine solutions and their densities. Disadvantages of brine
fluids are: expense (which can reach $800/barrel), the generation of precipitates ha the formation at high
pH or when contaminants are present, loss of large volumes of fluid to the formation, limited lifting
capacities, poor suspension properties, and temperature sensitivity.16
Modified drilling fluids contain the necessary additives to achieve the basic functions of a
completion or workover fluid. These fluids are economical to use since they are usually readily available.
The disadvantages of modified drilling fluids is their high solids content (both compressible and
incompressible solids). The high solids content can result in: hydration and/or migration of formation
clays and silts, emulsion or water blocking, and permanent formation damage.
Specially designed fluids consist of inorganic brines with the addition of: polymers, acids, water,
or oil-soluble materials needed to formulate a fluid with the proper viscosity, weight support, and fluid loss
K-7
-------
TABLE IX-5
COMMON BRINE SOLUTIONS IN
WORKOVER AND COMPLETION OPERATIONS1*
' '
^ff^+ vJff-^x.f.^^K.t.llj^s^^^^l^^^^^^^^
Potassium Chloride
Sodium Chloride
Sodium Bromide
Calcium Chloride
Calcium Bromide
Calcium Chloride-Calcium Bromide
Zinc Bromide-Calcium Bromide-Calcium Chloride
<::;:':¥:>*":¥:V:JJR^.:K«:*:)S-!'?:^::
9.7
10.0
12.5
11.6
11.6 to 14.2
11.6 to 15.1
15.1 to 19.2
a Densities given are the maximum density except where a range is provided.
control. These fluids are used where additional cky inhibition is required. Two of the available polymers
used are hydroxyethyl cellulose (HEC) and xanihan gum. Problems associated with specially designed
systems include poor temperature stability, foaming, and corrosivity.16
There are two types of oil-based fluids: true oil fluids and invert emulsion fluids. The advantages
of oil-based fluids include: temperature stability, density range, maximum inhibition, minimum filtrate
invasion, and non-corrosive. Disadvantages include toxicity and the potential to damage environmentally
sensitive areas, change the wettabffity of the formation, cause emulsion blocks, or damage dry gas sands.16
The drilling fluid tanks are used to mix and circulate workover and completion fluids. The fluids
are circulated to remove unwanted materials and to maintain pressure.2 Solids control must be maintained
in workover and completion fluids so that the formation is not irreversibly plugged in the vicinity of the
wellbore.
World Ofl publishes a yearly guide of commercially available drilling, completion and workover
fluids. The guide lists specific additives to the basic fluid and includes the product name, tradename,
description of material, recommended uses, product function and the company from which they may be
obtained. The primary functions of additives in completion and workover fluids are listed hi the guide as
corrosion inhibitors, viscosifiers, and filtration reducers. The corrosion .inhibitors such as hydrated lime
and amine salts are added to the fluid to control corrosion. The viscosifiers are added to increase the
IX-8
-------
viscosity. The filtration reducers are added to reduce fluid loss to the formation and can include bentonite
clays, sodium carboxymethylcellulose, and pregelatinized starch.18 Table IX-6 identifies specific additives
to completion and workover fluids.
TABLE IX-6
ADDITIVES TO COMPLETION AND WORKOVER FLUIDS4
"" f ff \
Type &f Additive ;
Viscosifiers
Fluid Loss Control
Corrosion Inhibitors
-. "" "-. ""'*''•••.
Specific Additives
Guar Gum
Starch
Xanthan Gum
Hydroxyethyl Cellulose
Carboxymethyl Cellulose
Calcium Carbonate
Graded Salt
Oil Soluble Resins
Amines
Quaternary Ammonia Compounds
Several sources indicate that well completion and workover fluids may include hydroxyethyl
cellulose, xanthan gum, hydroxypropyl guar, sodium polyacrylate, filtered seawater, calcium carbonate,
calcium chloride, potassium chloride, and various corrosion inhibitors and biocides, zinc bromide, calcium
bromide, calcium chloride, hydrochloric acid, and hydrofluoric acids.12
2.2.3 Chemical Characterization of Well Treatment, Workover, and Completion Fluids
A comprehensive source of analytical data for TWC fluids is a study of "associated wastes"
conducted by the EPA Office of Solid Waste (OSW), Waste Management Division.19-20 The term
"associated wastes" is used in the OSW study to describe miscellaneous and minor wastes associated with
the exploration, development, and production of oil and gas resources. This study includes data from
samples of TWC fluids collected hi Texas, New Mexico, and Oklahoma during sampling efforts in 1992.
Table IX-7 provides the average concentrations of pollutants found in selected TWC fluid samples from
the OSW study.21 In general, the pollutant characteristics of TWC fluids vary considerably from job to job.
Therefore, the data hi Table IX-7 are listed as ranges as well as averages.
IX-9
-------
Table IX-7
POLLUTANT CONCENTRATIONS IN TREATMENT, WORKOWR, AND
COMPLETION FLUIDS151
-• ;• . '"•;';:.:;;:i^'ii^:''w;
Pollutant Parameter •' •;•;:.;;..;.:?•;; '^^
Convcntionals
Oil St. Grease
Solids, Total Suspended
Priority Pollutant Organics
Benzene
Ethylbenzcne
Methyl Chloride (Chloromethane)
Toluene
Huotene
Naphthalene
Phcnanthrene
Phenol
Priority Pollutant Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
2sr
Nickel
Selenium
Silver
Thallium
Zinc
Other Non-Conventionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Tool
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone (2-Butanone)
M-Xylene
O-+P-Xylene
4-Meihyf-2-Pentanone
Dibenzofuran
Dibcnzothiophene
N-Becane (N-C10)
N-Docosane (N-C22)
N-Dodeeane
-------
Samples of workover, completion and well treatment fluids were collected and analyzed for the
Cook Inlet Discharge Monitoring Study conducted in 1987. The study was a cooperative effort between
the U.S. EPA Region 10 and seven oil and gas companies. The specific objective of the study was to
determine the type, composition and volume of discharges from workover, completion, and well treatment
operations. Samples were collected of fluids during five workover operations (one using weak acid,
EDTA), two completion operations, and three well treatments using acid.7
The samples collected during the Cook Inlet Discharge Monitoring Study were analyzed for pH,
oil and grease, dissolved oxygen, BOD, COD, TOC, salinity, zinc, cadmium, chromium, copper, mercury,
and lead. Table IX-8 summarizes the analytical results from the Cook Inlet Discharge Monitoring Study.
2.3 WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS CONTROL AND TREATMENT
TECHNOLOGIES
2.3.1 BPT Technology
The current BPT requirement for TWC fluids is "no discharge of free oil" to receiving waters.
EPA's general permit limiting the discharges from coastal oil and gas drilling operations in Texas and
Louisiana further prohibits discharges of TWC fluids to freshwater areas (58 FR 49126; September 21,
1993). Methods for treatment and disposal include:
• Treatment and disposal along with the produced water
• Neutralization for pH control and discharge to surface waters
• Reuse
• Onshore disposal and/or treatment.
Treatment and disposal of well treatment, workover, and completion fluids with the produced water
varies depending on how the fluids resurface, their reusability, and their volume in relation to produced
waters they may be commingled with. The fluids are often commingled with the produced water,
especially where the proportion of produced water to TWC fluids is high enough to overcome the
interference the TWC fluids may have on the produced water treatment system. According to one industry
report, TWC fluids can be effectively treated in the produced water treatment system if commingling is
performed in such a manner that the treatment system is not subjected to large concentrated slugs of TWC
fluids.11 Operators in Alaska also treat and dispose of these fluids with their produced water.8>22123 In
California, facilities commingle the workover, completion and well treatment fluids with the produced
water and dispose of the wastes in injection wells.2
IX-11
-------
TABLE IX-8
ANALYTICAL RESULTS FROM THE COOK INLET DISCHARGE MONITORING STUDY7
Units
Workover Fluids
Completion
Fluids
Lab
pH
SU*
6.3
4.1
NA
7.9
6.6
6.7
7.2
6.7
NA
7.5
7.5
7.4
NA
6.8
6.7
6.7
7.2
.7.2
7
7.1
8.6
Field
PH
SU*
6.5
4.1
NA
7.2
6.9
7.1
7
6.9
1.4
7.6
7.5
7.4
1.6
7.2
7.3
7.3
7.2
7
7.1
7.1
8.5
0&6
mg/l
36
. 74
47
21
21
0.34
9.4
21
66
12
14
16
23
13
11
8.1
5.6
2.2
1.9
6.1
0.23
Field
D.O.
ppn>
i
0.2
NA
0.4
0.3
2.6
0.4
2.8
NA
0.1
0.2
0.2
NA
0.2
0.1
0.1
0.4
0.1
0.5
4.7
6.2
BOD
ittg/I
690
460
NA
660
680
3.4
400
51
NA
660
630
720
NA
600
600
560
570
865
645
108
6
COD
mg/l
1,170
1,820
NA
1,130
1,270
236
> 1,500
408
NA
1010
965
1,410
NA
1,080
1,035
1080
1,230
980
1,000
590
865
TOG
mg/I
306
1,700
NA
249
321
23
203
61
NA
289
294
302
NA
350
304
307
115
70
119
90
4
Salinity
PPt
16.7
16.2
NA
22.78
21
17.65
27.81
24.16
NA
30.63
30.63
29
NA
27.36
25.72
25.72
30.01
29.51
29.18
25.76
2.14
Zn
mg/I
NA
NA
2.2
0.13
0.16
NA
NA
NA
0.68
0.015
0.01
0.036
0.175
0.017
0.02
0.012
NA
NA
NA
NA
NA
ca
Wg/l
NA
NA
0.21
ND*
ND*
NA
NA
NA
0.142
ND***
ND***
ND***
0.0063
ND***
ND***
ND**,*
NA;
NA
NA
NA
NA
Cr
>»g/l
NA
NA
3.3
0.12
ND*
NA
NA
NA
ND*
ND*
ND*
ND*
0.04
ND*
ND*
ND*
NA
NA
NA
NA
NA
Cu
mg/l
NA
NA
1.3
ND*
ND*
NA
NA
NA
2.8
ND*
ND*
ND*
0.18
ND*
ND*
ND*
NA
NA
NA
NA
NA
Hg
MIg/l
NA
NA
0.0019
ND**
ND**
NA
NA
NA
0.00044
ND**
ND**
ND**
0.00074
ND**
ND**
ND**
NA
NA
NA
NA
NA
Pb
ittg/I
NA
NA
0.3
ND*
ND*
NA
NA
NA
0.35
ND*
ND*
ND*
0.05
ND*
ND*
ND*
NA
NA
NA
NA
NA
*pH reported in standard units
NA = Not analyzed
ND* = Not detected (detection limit at 0.01)
ND** = Not detected (detection limit at 0.0002)
ND*** = Not detected (detection limit at 0.002)
-------
TWC fluids may be treated separately from the production fluid stream if they resurface as a
discrete slug. It is especially advantageous to separately collect them if they are heavily weighted and can
be reused. Workover and completion fluids can be reused 2 to 3 times depending on the amount of oil and
grease build-up. Inexpensive workover and completion fluids consisting primarily of filtered seawater are
typically not reused. However, treatment fluids are not reused because they react with the formation and
lose their treatment ability.2
2.3.2 Additional Technologies Considered
Additional controls considered for this rulemaking are limitations on oil and grease or zero
discharge. The technology basis for these other controls on TWC fluids is commingling and treating with
produced water or sending the fluids separately to commercial disposal facilities. A detailed discussion
of produced water treatment technology is presented hi Chapter Vni.
A new technology tested for the treatment of TWC fluids is a granular filtration media formulated
to absorb crude oil contamination from wastewater streams at pH levels less than one.24 After phase
separation, the hydrocarbon contaminated fluids are pumped through a vessel loaded with the formulated
media to remove hydrocarbons and additives detected as oil and grease. The cost of the treatment is
$30.00 per barrel of fluids based on an average volume of 587 bbl per well treatment (acid) job. Vendor
data indicate that for a given acid job, the oil and grease removal efficiencies range from 98.25% to
98.97%.M
3.0 DECK DRAINAGE
For coastal operations in the Gulf of Mexico, EPA investigated the deck drainage generated from
drilling operations and production operations separately. Generally, deck drainage generated during
drilling may vary in volume, characteristics, and its method of collection from that generated during
production. Deck drainage from production operations occurs over a long period of time while drilling
operations occur only for a relatively short and finite period of time. However, this distinction can not be
made in Cook Inlet, since both drilling and production operations occur simultaneously on the same
platform.
IX-13
-------
3.1 DECK DRAINAGE SOURCES
Deck drainage includes wastes resulting from deck washings, spillage, rainwater, and runoff from
gutters and drains including drip pans and work areas. Within the definition of deck drainage for the
coastal guidelines, the term rainwater for those facilities located on land is limited to that precipitation
runoff that reasonably has the potential to come into contact with process wastewaters. Runoff not included
in the deck drainage definition is subject to control as storm water under 40 CFR 122.26. For structures
located over water, all runoff is included in the deck drainage definition.
The final rule clarifies the definition of deck drainage to limit its applicability to precipitation runoff
to that runoff which reasonably has the potential to come into contact with process wastewaters associated
with production, field exploration, drilling, well completion, well treatment, or well workover operations.
This clarification to the definition will allow that precipitation runoff which does not come into contact with
process wastewaters to more appropriately be regulated under the provisions for storm water at 40 CFR
122.26. Coastal subcategory structures located on land have greater areal extent than structures located
over water and generally are able to segregate and separately discharge runoff within a facility which has
not become contaminated with (or have a reasonable potential to come into contact with) process
wastewaters and spillage from process equipment. This physical segregation is generally accomplished
through the use of devices such as berms, curbs, and gutters. Another means for accomplishing this
segregation includes enclosing process operations in structures which allow the uncontaminated runoff to
be channelled away from process wastewaters to prevent possibility of contact. On Alaska's North Slope,
the harsh climatelogical conditions have led operators to enclose most process equipment (e.g., production
and injection wellheads, separation equipment, and wastewater treatment systems) in buildings. In this
instance, all wastes from washings and spillage within the building would be included within the definition
of deck drainage. Runoff outside the buildings, if not contaminated with process wastewaters, would be
excluded from the deck drainage definition and would instead be subject to control as storm water under
40 CFR 122.26. For structures located over water, due to the nature of these structures, all runoff is
considered to be contaminated and therefore included in the deck drainage definition.
3.2 DECK DRAINAGE VOLUMES
3.2.1 Total Volumes
Table IX-9 presents the overall total volume of deck drainage disposed by both drilling and
production operations hi the Gulf of Mexico and Cook Inlet.
IX-14
-------
TABLE IX-9
ANNUAL VOLUME OF DECK DRAINAGE DISPOSED
,,», , ,, Region. . ,,„,
•> "• ,
i : s ^; ; -
Gulf of Mexico
Cook Inlet
Total
Drilling Operations
0>P5p
937,286
, ,,* Production , ,
Operations
v te> , , J, ' -
9,932,332
628,475
, , Total - ,
'-.- (bpy)
10,869,618
628,475
11,498,093
3.2.2 Gulf of Mexico-Production Operations
The predominant source of deck drainage at production facilities in the Gulf coastal region is from
rain falling within bermed and diked areas. During the 1992 EPA 10 Production Facility Sampling
Programs, it was observed that deck drainage collection systems can cover areas ranging from several
hundred square feet for small satellite tank batteries to much larger areas covering tens of thousands of
square feet. The New Orleans area receives an average annual rainfall of 53.7 inches of rain compared to
14.7 inches in Anchorage, Alaska.25 The statistical analysis of the 1993 Coastal Oil and Gas Questionnaire
data estimated that the average volume of deck drainage from production facilities is 11,644 bpy.5 By
multiplying this value with the estimated 853 total number of production facilities,6 the result is an
estimated total annual deck drainage volume of 9,932,332 bbls for all production facilities in the Gulf
coastal region. Using the average deck drainage volume of 11,644 bpy and the rainfall reported for the
New Orleans area in 1992 of 60 inches26 the area covered by the average production facility is estimated
to be 9,806 square feet.
EPA estimates that 7,995,527 bbls (80.5%) of the total estimated volume generated by production
operations is being discharged to surface waters. Although no one reported that they injected deck
drainage in Question A42b of the Coastal Oil and Gas Questionnaire, the summary statistics indicate that,
based on the response to Questions A39b, 19.5% of the facilities that reported deck drainage data do not
discharge produced water and at the same time commingle deck drainage along with the produced water
for disposal.
IX-15
-------
3.2.3 Gulf of Mexico-Drilling Operations
Because of the significant differences in the deck drainage collection area covered and the deck
drainage handling equipment, EPA investigated deck drainage from land-based and water-based drilling
operations as separate sources. The two data sources that were investigated to obtain estimates of the
average volumes of deck drainage generated for disposal from land-based and water-based drilling
operations were the 1993 Coastal Oil and Gas Questionnaire data and the three coastal drilling site visits
conducted by EPA in 1992. After a review of the Coastal Oil and Gas Questionnaire and the trip reports,
it was determined that a different method for estimating deck drainage volumes would be necessary for
land-based versus water-based operations. These methods are discussed below.
3.2.3.7 Total Deck Drainage Volumes
Table IX-10 presents the per well and overall total volumes of deck drainage generated by water-
based drilling operations in the Gulf of Mexico region. Tables IX-11 and IX-12 present the per well and
overall total volumes of deck drainage generated by drilling operations in the Gulf of Mexico region based
on the data and assumptions presented below.
3.2.3.2 Estimation of the Proportion of Land-based Versus Water-based Drilling
Operations
It is important to distinguish between land- and water-based drilling operations because land-based
systems cover a larger area. Such systems utilize ring levees which tend to collect more rainwater.
Answers to three questions in the 1993 Coastal Oil and Gas Questionnaire were used to estimate the
proportions of land- and water-based drilling rigs. One is the reported type of drilling rig used for the
injection wells in Question A18. Although these are injection wells and not production wells, it is
reasonable to assume that the location of injection wells is likely to be proportionately the same as most
of the production wells at a typical injection facility. The second and third sources come from two
questions in Table B-7 requesting information on the number of wells that reported using either trucks or
barges for hauling drilling waste. Question B27 requests the transport capacity, and Question B28 requests
the number of vessels. In both cases, only barge and truck responses were counted since tugs are used to
move the barges. Table K-13 shows the number of facilities or drilled wells in the survey that indicated
truck- or barge-based operations in each of these questions. The percentages of land-based versus water-
based responses for all three sources were then averaged together to estimate the overall proportion of each
type of well in the region.
IX-16
-------
TABLE IX-10
ANNUAL DECK DRAINAGE VOLUMES CURRENTLY DISCHARGED FROM
WATER-BASED DRILLING OPERATIONS IN THE COASTAL GULF OF MEXICO REGION
' •• ' f ''"'•.•• •• ' ^ !
Type of W«H" "„' '"..
New and Exploratory
Recompletions and
Sidetracks
Total
•.
^ •. ''" 'v
Total Number of WeHs3 ;
152.2
182.4
334.6
Volume Discharged per
1 t$ell«} «
f f ^-.
157,605
112,043
269,648
b (Number of Wells) x (Per Well Volumes in Table IX-11)
rx-17
-------
TABLE IX-13
PROPORTION OF LAND-BASED VERSUS BARGE-BASED
OPERATIONS REPORTED IN THE COASTAL SURVEY
Type of
Response
Truck
Barge
Total
Number of
Responses to
Question
A18»
26
43
69
, %;<>f -;
.Total
^ .•••*?' \'
<'" «* £
*W £<
& •>£
37.7%
62.3%
100%
^Nnmberjof'^
Responses to "
Question B27b
Z* £**&?*' <"*
9
17
26
,••• -.
">'-'%<&"
;'Tofca
£
•A. f
f
v,>"
34.6%
65.4%
100%
Number of -
Responses to
Question B2&c
^ ^ * f ff ff ~f *!• / y.
8
18
26
i'of
"Total -
?
f f
30.8%
69.2%
100%
Averagfe %
S , •"* ? v
34.4%
65.6%
100%
* Question A1.8: What was the rig configuration for your injection well? Land-based, barge-based, or other?
Question B27: What was the chosen mode of transporting drilling waste and its capacity? Barge, truck, tug, or other?
0 Question B28: How many vessels or vehicles were required to dispose of drilling waste?
3.2.3.3
Numbers of Wells
Using the information reported in Question B2 in the Coastal Oil and Gas Questionnaire, the well-
type data were divided into six categories; "exploratory," "new production," "new and exploratory,"
"recompletion," "sidetrack of existing well," and "other and service". The estimated total wells for the
Gulf of Mexico coastal area that belong in each of these categories are provided in Table IX-14. Since the
sample size was small for "exploratory" and "sidetrack of existing well" (only four for each), these two
categories were combined with "new production" and "recompletion," respectively. In addition, the "other
and service" wells were predominantly "rig workovers" and some "through-tubing plug backs". Since
"other and service" wells mostly were not drilling operations, they are not included in this analysis. These
numbers are used to calculate estimated annual deck drainage volumes for each type of drilling operation.
Table K-15 presents the estimated number of wells in these categories that are land-based and barge-based
using the percentage split described in Table IX-13. For the purposes of estimating the olumes of deck
drainage generated, EPA assumed that new production and exploratory wells are similar in nature and thus
are grouped together. EPA also assumed the same is true for recompletions and sidetracks of existing
wells.
3.2.3.4 Volumes Generated Per Well
The data in Table K-13 show that, based on a review of the Coastal Oil and Gas Questionnaire,
the majority of the responses were from water-based operations. The one water-based drilling operation
IX-18
-------
TABLE IX-14
ESTIMATED NUMBER OF WELLS
DRILLED IN 1992 IN COASTAL GULF OF MEXICO AND
DURATION OF DRILLING5
'Type,;;,/,, _
••;
; ± ff s j ff.ff f. s •.-,
-*•*.
Exploratory
New production
New and Exploratory
Recompletion
Sidetrack of existing
Recompletion and Sidetrack
Other and service
Number
45
187
232
241
37
278
177
« Days To
4 Brill
9.8
21.4
19.3
8.5
10.6
19a
Only one well reported days drilling because most of these wells were
"rig workovers" and thus were not drilled.
TABLE IX-15
NUMBER OF WELLS BY LOCATION AND WELL TYPE CATEGORIES
,*^,£fccfiss-,s
%••••
"* "" ^ , '".•'
S „", ' , „ '6 '\ 'f \
New & Exploratory
Recompletion & Sidetracks
New & Exploratory
Recompletion & Sidetracks
Total Welfe *
JEaeh Type ;
•» ** ^
232
278
232
278
\ Land >&,.
' Wafer'"""''"'
^ Proportions '
34.4%
34.4%
65.6%
65.6%
, , Nuaiberjof
Welb
**•
79.8
95.6
152.2
182.4
visited by EPA was an unusually deep well and did not report the deck drainage volume because it was
combined with and included in the total volume reported for waste drilling fluid and wash water.27
Therefore, the average volume surface discharged from water-based drilling operations for exploratory and
new production wells, which is 516, was selected for use in this analysis based on responses to the Coastal
Oil and Gas Questionnaire database.
IX-19
-------
A review of a printout of the Coastal Oil and Gas Questionnaire database shows that the majority
of the deck drainage reported in Table B-9 was from water-based drilling operations.8 The average volume
of deck drainage discharged to surface waters from water-based operations, including all exploratory and
new production wells except the one land-based well, was 516 bbls per drilling job. The volumes ranged
from 60 bbls to 2,318 bbls. In general, the higher volumes were for deeper wells which take longer to drill
and therefore generate more deck drainage.
For water-based recompletions and sidetracks of existing wells, the estimated average deck
drainage volumes discharged for these categories are 824 bbls and 310 bbls respectively.3 These volumes
were averaged together to get the volume of 567 bbls discharged because of the low number of survey
responses for each category; two and three, respectively. The values reported in the questionnaire database
are the volumes disposed and thus already take into account any reduction in volume due to reuse of deck
drainage as mud make-up water. This may explain why the recompletion volume is greater even though
the drilling time is lower for recompletions,
A review of the site visit data in Table IX-16 shows that both of the land-based drilling operations
were deeper wells and longer in duration man the estimated average well in the Coastal Oil and Gas
Questionnaire.5 In the survey, the estimated average well depth was 8,429 ft for exploratory wells and
8,487 ft for new production wells, and the estimated average drilling duration was 10 days and 21 days,
respectively. Because the site visit data appear to represent greater than average values, a methodology
was developed for estimating the average volume of deck drainage generated by land-based drilling
operations rather than use the site visit data directly. The methodology utilized the drill site dimensions,
annual rainfall data, estimated mud make-up water volume and average drilling operation duration. Based
on this methodology, EPA. estimates that land-based drilling operations dispose of 5,901 bbls of deck
drainage per well.28 The assumptions used are described below.
3.2.3.5 Assumptions for New and Exploratory Wells
» Deck drainage and area runoff are collected in the cellar and ring levee ditch.
» The drilling pad area will be 350 ft x 350 ft with a total surface area of 122,500 sq ft.
These were the dimensions of the ARCO drilling operation in the Sabine Wildlife Refuge
and represent the minimum area requirements.29
IX-20
-------
TABLE IX-16
SUMMARY OF DECK DRAINAGE INFORMATION FROM THE
THREE COASTAL DRILLING SAMPLING SITE VISITS IN LOUISIANA27'29-31
i,3$$?-::
UNOCAL/
Posted Barge
ARCO/
Land Rig
GAP Energy/
Land Rig
7J5j6fea^*',:
•Vv^^'-X" -' -
Deck Drainage
Rainwater
Deck Drainage
and Rainwater
Deck Drainage
and Rainwater
$jfftc5$fcri
Drilling Interval
£s -'t^-. i7 •- ; ' ** ~
si, «•;«" '*•- ' '-, * •>•• ^ %
Water base/
0-13,555 ft
Oil base/
13,555- 19260 ft
Both intervals
Water base/
0-TD(14,928 ft)
Water base/
0-TD(12,860 ft)
- , "', Ufifeaftjieiii aJ$ J&jfosal ) ", t;
f* -,',','„»' X5 i, -"•, f'a ->„;. X •>;*,-
i ', f , ^. . 5 , - ,; v« • - '- f, -, 'f"\-','-
* 4 tj,*^', ', xi« "'- f>; ,'??-?- •*#'
Drains to shale barge
Drains to shale barge then annularly
injected
Drains to a sump
Contained in levee and trucked to
commercial facility
Contained in levee and trucked to
commercial facility; 8000 bbls were
surface discharged during heavy rain
;rj3tt!fc!ip
sW
7,236
7,236
7,236
122,500
sqft
164,025
sqft
*\ | ' f tirofiimfe Sejilratel ',, ^ "I
V/^-'f -(SP>"V=?| •* \
... , -... *,*• - , «•,•:*, ^.....^- of
•«, ., »,•> ,-!<•<, f | v- , „ ^ ^ - ^. » ^
Commingled with water based
mud. Total mud +• water = 2,515
bbls
4,199 bbls of wash water was
injected
Not reported
12,440
7,060
(commercial)
8,000
(surface)
1 "• JJay%oI«'V
- D>njjjig* v
'<^-- •• .%•',** \--
i*^\---'.
57
123
180
63
96
-------
• Drilling time will be 30 days. The estimated average drilling time from the Coastal Oil
and Gas Questionnaire was approximately 20 days (see Table EX-14), however this did not
include time to test the well and to plug and abandon or complete the well. The additional
10 days accounts for these activities.
• The amount of rainfall is based on the average 30-day rainfall for New Orleans Louisiana
using the 1993 annual rainfall amount of 52.7 inches.30 The 30-day average rainfall total
is 4.33 inches.
• Rainwater will be used as make up-water for drilling fluids.31 The amount used will be
equal to the volume of waste mud generated minus the solids content of the mud. The
estimated average volume of mud disposed as reported in the Statistical Analysis of the
Coastal Oil and Gas Questionnaire was 3,038.5 bbls.5 The drilling fluid solids content
ranged from below 10% to around 35% by volume at the three sampled drilling
operations.27'29'31 A solids content of 35% will be used as a conservative estimate since it
will result in a lower volume of deck drainage that is recycled. This results in a deck
drainage reuse volume of 1,975 bbls.
3.2.3.6 Assumptions For Recompletion and Sidetrack of Existing Land-based Well
• Table IX-14 shows that for recompletions and sidetracks, the average days to drill were
8.5 and 10.5 or roughly one half the time to drill a new well. Therefore, the amount of
rainwater generated is assumed to be one-half that of newly drilled wells (i.e., one-half the
average 30-day rainfall; 15 days duration). Although recompletions may use smaller
equipment and smaller pads, there is not sufficient information available to estimate the
size of the reduction in volume. The 15-day average rainfall total is 2.16 inches and is
based on the New Orleans annual 1993 rainfall data.30
• Rainwater will be used as make-up water for drilling fluids.31 The amount used will be
equal to the volume of waste mud generated minus the solids content of the mud. The
estimated average volume of mud disposed as reported in the Statistical Analysis of the
Coastal Oil and Gas Questionnaire was 1,803 bbls (Note that this volume is close to half
the volume reported for newly drilled wells).5 The drilling fluid solids content ranged
from the low 20's to around 35% by volume at the three sampled drilling operations. A
solids content of 35% will be used as a conservative estimate. This results in a deck
drainage reuse volume of 1,172 bbls.
3.2.4 Cook Inlet Alaska
Table IX-17 presents the Cook Inlet deck drainage volumes obtained from the Coastal Oil and Gas
Questionnaire and an EPA site visit. Of the 10 platforms in Cook Inlet that transfer produced fluids to
shore for separation, only four treat and discharge their deck drainage at the platform. The remaining six
commingle deck drainage with production fluids and transfer the combined stream to shore-based facilities
for separation and disposal of the deck drainage along with the produced water. At the five platforms that
separate produced fluids on the platform, deck drainage is treated along with the produced water and
discharged through the skim pile. The arithmetic average of four reported discharge volumes (44,891 bpy)
IX-22
-------
TABLE IX-17
ANNUAL DECK DRAINAGE VOLUMES DISPOSED IN COOK INLET, ALASKA
,, L.V. , , , , , c
*•*• ' Facififr *- : ''
Trading Bay
Granite Point
E. Foreland
Dillon
Bruce
Anna
Baker
Tyonek "A"
Platform
King Salmon
Dolly Varden
Steelhead
Monopod
Grayling"1
Spark
Spurr
Granite Poinf
SWEPI "A"d
SWEPI "C"d
Dillon6 .
Bruce'
Anna6
Baker6
Tyonek "A"6
Total
t Beek Drainage VoJiime^bJ/jT> »,~ ?-
- - Reported
—
4,000a
—
-
—
—
—
—
65,000a
81,000"
—
29,565 (max. 95,630)b
-
—
—
"• *" Average0 ' "" ' "'v
44,891
—
44,891
44,891
44,891
44,891
0
44,891
—
-
44,891
-
44,891
44,891
44,891
628,475
* Source: 1993 Coastal Oil and Gas Survey (Operators did not claim confidentiality of information for deck drainage data)
b Source: Wiedeman, May 1,1993
c Average Volume = (4,000 + 65,000 + 81,000 + 29465)74 = 44,891 bbl/yr
d These platforms do not commingle deck drainage with produced fluids. Deck drainage is treated and discharged at the platforms.
e These platforms commingle deck drainage with produced water and discharge both at the platform after treatment.
was used by EPA in studying costs and impacts of deck drainage options. By adding the reported volumes
to the calculated volumes reported in Table IX-17, the total volume disposed from Cook Inlet platforms
is estimated to be 628,475 bpy.
3.3 DECK DRAINAGE CHARACTERISTICS
Oil and grease are the primary pollutants identified in the deck drainage waste stream. In addition
to oil, various other chemicals used in drilling and production operations may be present in deck drainages.
EPA's analytical data for deck drainage comes from the data acquired during the Offshore Oil and
Gas rulemaking effort. As part of this effort, EPA evaluated Discharge Monitoring Reports (DMRs) for
deck drainage discharges from 32 oil companies located in the Gulf of Mexico.32 The DMR data spans two
IX-23
-------
years from May 1, 1981 through April 30, 1983 and consists of deck drainage monitoring data from oil
and gas production facilities. The data do not indicate the location of where the samples were taken, the
treatment of the waste stream prior to sampling, or the analytical method of determining oil and grease.
The DMR data included oil and grease concentrations of deck drainage discharges. Table IX-18 presents
the monthly averages of deck drainage oil and grease concentrations for the two years evaluated. The
DMR data reports monthly samples taken by the operators. The data do not indicate the location of where
the samples were taken, the treatment of the waste stream prior to sampling, or the analytical method of
determining oil and grease.
Also, as part of the Offshore Oil and Gas rulemaking effort, EPA conducted a comprehensive 4-day
sampling program at three oil and gas production facilities in June of 1989, to evaluate the performance
of granular filtration technology and to characterize produced water and other miscellaneous discharges
such as produced sand, well treatment fluids and deck drainage. EPA selected facilities for the three
facility study based on: (1) their use of granular filtration, and (2) the oil and grease level being comparable
to the BPT level prior to filtration. The facilities selected were from three separate oil and gas
subcategories. The three facilities selected for this study were: Thums Long Beach Island Grissom (coastal
subcategory), Shell Western, E & P, Inc. - Beta Complex (offshore subcategory), and Conoco's Maljamar
Oil Field (onshore subcategory).33'34'35
Samples of treated and untreated (pre-BPT) deck drainage were collected at two of the facilities;
the THUMS facility and the Shell Beta Complex. The range of pollutant concentrations in untreated deck
drainage are presented in Table IX-19. As can be seen from the data in Tables IX-18 and IX-19, the
pollutant concentrations can vary widely between locations and over time. In these samples, eight toxic
metals were detected, most notably lead (ranging in concentration from 25 - 325 ug/1) and zinc (ranging
in concentration from 2,970 - 6,980 ug/1). The presence of lead, copper and zinc may be related to the
presence of these metals in standard drill pipe thread compound. Organics were also present including
benzene, toluene, xylene and naphthalene. These organic pollutants are commonly found in oil.
The content and concentrations of contaminants in deck drainage can also depend on chemicals
used and stored at the oil and gas facilities. An additional study on deck drainage in Cook Inlet reviewed
during the development of the Offshore Guidelines showed that discharges from this wastestream may also
contain paraffins, sodium hydroxide, ethylene glycol methanol and isopropanol.36
IX-24
-------
TABLE IX-18
CHARACTERISTICS OF DECK DRAINAGE FROM OFFSHORE GULF OF MEXICO
PLATFORMS32
, Ss , ,v."*o.*o* ,;,?' Ofl and Grease in Deck Drainage : - r '-
:« . « l'**Y':<"" , -" > - *** - ••» tmg/l> " ' * '" s . r%v
Xw.' v. \f - '* *>' "• "*':
•. fS * •
_, v <•*• s Wi w> % Vl •••* •**
•, •» f ff ft f f*'
1981-82 (19 Sites)
1982-83 (117 Sites)
"M»Htwr^**gfe
Range/ ,
5-47
2-183
[ ' 'Average ,
22
28
Bally Maxutfnm " '-
" Range
19-72
5-1363
' Average
51
75
3.4 DECK DRAINAGE CONTROL AND TREATMENT TECHNOLOGIES
3.4.1 BPT Technology
BPT limitations for deck drainage prohibit the discharge of free oil. Typical BPT technology for
compliance with this limitation is a sump, skim tank or skim pile which facilitates gravity separation of any
floating oil prior to discharge of the deck drainage. Deck drainage treatment systems typically use gravity
to convey the flow, and the skim tanks generally do not require a constant power source for operation.
Thus, deck drainage generated at facilities located in powerless remote locations (such as satellite tank
batteries) can be effectively treated.
3.4.1.1 Cook Inlet
Typical platforms such as those in Cook Inlet are equipped with drip pans and gutters to collect
deck drainage. The drainage flows by gravity to a sump where the water and oil are separated by a gravity
separation process. Oil in the sump tank is recovered and transferred to the oil treater of the produced
water treatment system. Figure IX-1 is a schematic of a generic production platform flow system. The
water from the sump is discharged to the surface via a submerged outfall or a skim pile. Skim piles which
are common only to relatively deep water platforms, such as in Cook Inlet, remove that portion of oil
which quickly and easily separates from water (see Figure VHI-1). They are constructed of large diameter
pipes containing internal baffled sections and an outlet at the bottom. During the period of no flow, oil will
rise to the quiescent areas below the underside of inclined baffled plates where it coalesces. Due to the
differences in specific gravity, oil floats upward through oil risers from baffle to baffle. The oil is collected
at the surface and removed by a submerged pump. These pumps operate intermittently and will move the
separated oil to a sump tank. Oil recovered in the sump is combined with production oil. At some
IX-25
-------
TABLE EX-19
POLLUTANT CONCENTRATIONS IN UNTREATED DECK DRAINAGE33'34
(
Pollutant
Temperature (°C)
Conventionals (mg/1)
pH
BOD
TSS
Oil & Grease
Nonconventionals
TOC (mg/1)
Aluminum fag/1)
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Sodium
Tin
Titanium
Vanadium
Yttrium
Priority Metals fag/1)
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Silver
Thallium
Zinc
*& - ," 'if ,
s "' JKiUleJC' OJt •" •,"" •• •;
" Concentration51 -;1
20-32
6.6-6.8
< 18-550
37.2-220.4
12-1,310
21-137
176-23,100
2,420-20,500
3,110-19,300
98,200-341,000
<20
830-81,300
50,400-219,000
133-919
< 10-20 ISlxlO4-
568x10*
<30
4-2,030
< 15-92
<2-17
<4-<40
<2-<20
<1-1
<4-25
< 10-83
14-219
<50-352
<4
< 30-75
<3-47.5
<7
<20
2,970-6,980
** s f f - -. \ "* ** .... '
^ '• •, f ff
^ J Pollutant , ^
Priority Organics fag/1)
Acetone
Benzene
m-Xylene
Methylene chloride
N-octadecane
Naphthalene
o,p-Xylene
Toluene
1 , 1-Dichloroethene
' •»
f f jK$XOS& Ot ff <
Concentration"
ND-852
ND-205
ND-47
ND-874
ND-106
392-3,144
105-195
ND-260
ND-26
Ranges of four samples, two each, at two of the three facilities in the Three-Facility Study.
facilities deck drainage contaminated with oil is commingled with produced water and is treated in the
produced water treatment system.
One of the platforms examined in the Cook Inlet Discharge Monitoring Study was the Phillips
Petroleum Company's Platform Tyonek. On this platform all produced water and deck drainage water are
IX-26
-------
Deck Drainage
Inlat
Oil Pumped to
Oil Treatment
Unit
Treated
Deck Drainage
Outlet
Figure 1X4
Deck Drainage Sump
-------
commingled in a slop tank. Waters from the slop tank are pumped to the balance tank in batches.
Chemicals are added and circulated to extract the hydrocarbon from the water. The mixture is retained
in the tank for a period of time to allow the oil and water to separate by gravity. The water is discharged
to the sea. The remaining liquid is transferred to another slop tank for holding and reprocessing. Sampling
results indicated a mean average oil and grease content of 3.8 milligrams per liter.36
Some platforms in Cook Inlet collect crankcase oil separately and oil-based muds are diverted from
the platform drain systems for onshore separation and treatment. Deck drainage is either piped to shore
with the produced water waste stream and treated by gas flotation or gravity separated on the platform and
treated by gas flotation to an average of 25 mg/1 oil and grease.36
At the Bruce Platform in Cook Inlet, deck drainage from diked areas flows to a 300-bbl skim tank
where oil is skimmed off and pumped to the oil processing system. The effluent from the skim tank is then
commingled with produced water in two 600-bbl settling tanks. The combined effluent is discharged 10
feet below the water surface.22
On the jackup drilling rig, Adriatic 8, contaminated deck drainage is retained in the drilling deck
area using four inch collars. The deck drainage is collected in a 20-bbl skim tank that can hold
approximately one week's worth of deck drainage. The water then passes through a 7-ft high by 2-ft
diameter separator and is then discharged.22
3.4.1.2 North Slope
Drilling and production facilities on the North Slope of Alaska are typically constructed on gravel
pads to insulate the permafrost from melting and from the consequential subsidence due to oil and gas
operations.22 According to industry responses to the Coastal Oil and Gas Questionnaire, 2 percent of deck
drainage or area runoff is recycled with produced water, while the remaining 98 percent is injected for
disposal.8 All facilities in the North Slope inject produced water either for enhanced oil recovery or into
Class n disposal wells.37
An example of deck drainage waste management on the North Slope is found at the Endicott Field.
The Endicott Field consists of two gravel islands constructed in the Beaufort Sea. A 40' x 40' wastewater
settling tank collects miscellaneous wastes including area runoff and treatment, workover or completion
fluids. After settling, the fluids are injected into a Class II disposal well located on site.22
EX-28
-------
3.4.1.3 Gulf of Mexico-Production Operations
Typical production operations in the Gulf area that use elevated platforms are equipped with drip
pans and gutters to collect deck drainage and direct it to a sump where oil skimming occurs prior to
discharge below the water surface. Skim piles are not used because of the generally shallow water which
preclude installation of skim piles (see Chapter VIE for a discussion of skim piles). Figure IX-2 presents
a schematic diagram of a sump/skim tank. In this tank, deck drainage enters near the bottom at one end
and passes over a baffle into a quiescent zone where oil floats to the surface. The separated oil passes over
a weir and is pumped to an oil-water treatment unit such as a gun barrel. Treated deck drainage exits the
skim tank from a port near the bottom of die tank and passes through an inverted "U" shaped pipe and is
discharged below the water surface. The inverted "U" shaped pipe controls the liquid depth in the tank
and is referred to as the water leg. These tanks are usually installed below the deck near the water surface
to take advantage of using gravity flow in the deck drainage collection system.
Operations that are located on land or fill are usually equipped with earthen or concrete beams with
a depression in one area that acts as a sump to collect drainage. The collected water may be either sent
to a treatment system, commingled with produced water for treatment and disposal (where feasible), or
discharged without treatment. Three of the 10 coastal facilities sampled by EPA in 1992 commingled deck
drainage with produced water prior to treatment and subsurface injection.38 Three facilities used skim tanks
prior to surface discharge and the remaining five discharged deck drainage without treatment, if no sheen
was visible.
3.4.1.4 Gulf of Mexico-Drilling Operations
Deck drainage is periodically pumped from the ring levee ditch or collection sump and is disposed
by one or more of the following four methods: (1) hauled offsite in vacuum trucks or barges for disposal,
(2) reused as make-up water in drilling fluids, (3) subsurface injection through the annulus of the
intermediate casing of the well being drilled or (4) surface discharge.
Deck drainage from the drilling deck contains a considerable amount of drilling fluid and is almost
always collected, treated, and disposed in the same manner as waste drilling fluids. For many land-based
drilling operations in the Gulf region, at least a portion of the deck drainage, particularly site runoff, is
used as make-up water for drilling fluid. For deck drainage that is not reused in this manner and does not
meet the state discharge limitations, the treatment and disposal method is either annular injection or
IX-29
-------
Deck
drainage
collected in
diked area
Pumped
backto
oil/water
separation
In production
system
Valve
normally
open
Sump Tank
Surface of surrounding water
Pumped back
to oil/water
separation in
production
system
Skim Pile
(deep water
platforms only)
Water
discharge
Figure IX-2
Deck Drainage Treatment System
K-30
-------
transportation to and disposal at an offsite commercial facility. For water-based drilling operations, deck
drainage is collected in a sump tank and can be combined with waste mud for offsite disposal. Although
deck drainage from oil-base drilling operations can be treated using gravity separation, EPA observed that
because of the relatively small deck drainage volumes contaminated with oil-based drilling fluids, the
common practice is to dispose of the untreated water by injection or transport it to a commercial disposal
facility.27-29-31
3.4.2 Additional Deck Drainage Technologies
At proposal, EPA considered BAT and NSPS limitations based on commingling deck drainage with
produced water or drilling fluids and requiring best management practices. Under such requirements, deck
drainage would be commingled with either produced water or drill fluids and thus become subject to the
limitations imposed on these major waste streams. EPA also considered requiring best management
practices (BMPs) on either a site-specific basis or as part of the Coastal Guidelines. However, as discussed
below and in Chapter XVI, these additional requirements were rejected in the final rule (see Chapters IX
and Xin of the Development Document for the proposed rule for additional discussions).
An example of commingling can be found on Shell Western's "SWEPI A" platform in Cook Inlet.
All deck drainage is collected and drained to the production surge tank where it combines with produced
fluids and is also shipped to shore. It was found, through a telephone conversation with a senior process
engineer in Cook Inlet, that mixing of the deck drainage and produced water is only conducted when the
deck drainage stream fails the visual sheen test, while some operators diverted deck drainage to a sump
tank to be treated and discharged.39 As noted earlier, three of the ten Gulf coastal production facilities
visited by EPA in 1992 commingled deck drainage with produced water prior to treatment and disposal
by subsurface injection.
Difficulties encountered in commingling the whole deck drainage waste stream with the produced
waste water stream include:12
• The resulting flow variations could seriously upset the produced water treatment facility.
• Deck drainage water, saturated with oxygen, when combined with the salt content of the
produced water could result in higher corrosion rates in the equipment. Also, the oxygen may
combine with iron and sulfide in the produced water can causing the formation of solids which
foul treatment equipment;
IX-31
-------
• Detergents, used for washing oil off the decks, cause emulsification of oil and seriously upset
the produced water treatment processes.
While the total volume of deck drainage is less than the total volume of produced water generated
annually, the deck drainage sent to the produced water treatment system could create hydraulic overloading
of the equipment because of the highly variable nature of the flow rate. An add-on treatment specifically
designed to capture and treat deck drainage, other than the type of sump/skim pile systems typically used,
is not technologically feasible. Deck drainage discharges are not continuous discharges and they vary
significantly in volume. At times of platform washdowns, the discharges are of relatively low volume and
are anticipated. During rainfall events, very large volumes of deck drainage may be discharged in a very
short period of time. A wastewater treatment system installed to treat only deck drainage would have to
have a large treatment capacity, be idle at most times, and have rapid startup capability.
Since zero discharge for all deck drainage poses problems with storage and handling capacity
during severe storm events, EPA considered the capturing of only the first 500 bbls (first flush) and
commingling it with produced water for disposal at production operations and commingling it with drilling
wastes for disposal at drilling operations. Rainfall in excess of the 500 bbl volume would be subject to BPT
limitations. The volume of 500 bbls was selected because it is a standard storage tank volume and would
capture approximately 3.5 inches of rainfall at an average production operation (see Section XIII.3.2 of
the Development Document for the proposed coastal guidelines).40 The installation of larger tanks was
considered to be too costly.
The current BPT limitations allows for use of non-powered systems that utilize gravity to collect
and treat deck drainage. The commingling of the first flush volume has several technical problems
including:
Above-deck storage tanks would require the installation of a sump and high capacity pumps
(e.g.,two 200-gpm pumps) to handle sudden surges in flow.
Many coastal facilities are unmanned and have no power source available to them. Generators
or fuel powered pumps would be required at these locations that otherwise would not need
them.
Facilities that do not have a power source capable of driving high capacity pumps would need
to use gravity to direct the first flush volume to the storage tank. This would require the
installation of the tank below the deck which may not be feasible in many instances.
IX-32
-------
• Control systems that would prevent the overflow of an already full tank, during severe or back-
to-back storms would be required.
• The storage tanks would require additional deck space that would add significant costs,
especially for water-based facilities.
• Isolating me first flush at land-based drilling operations, that use ring levees, would be difficult
because the first flush volume could become mixed with deck drainage already in the ring levee
at the time of a storm event. The installation of a separate collection system, including pumps
and tanks, would add significant cost.
Upon review of the above information, EPA rejected the first flush option for control of deck
drainage for several reasons primarily relating to whether this option is technically available to operators
throughout the coastal subcategory. Deck drainage is currently captured by drains and flows via gravity
to separation tanks below the deck floor. However, the problems associated with capture and treatment
beyond gravity feed, power independent systems, are compounded by the possibilities of back-to-back
storms which may cause first flush overflows from an already full 500 bbl tank. In addition, tanks the size
of 500 bbl are too large to be placed under deck floors. Installation of a 500 bbl tank would require
construction of additional platform space, and the installation of large pumps capable of pumping sudden
and sometimes large flows from a drainage collection system up into the tank. The additional deck space
would add significantly, especially for water-based facilities, to the cost of this option. Further, many
coastal facilities are unmanned and have no power source available to them. Deck drainage can be
channeled and treated without power under the BPT limitations.
Capturing deck drainage at drilling operations poses additional technical difficulties. Drilling
operations on land may involve an area of approximately 350 square feet. A ring levee is typically
excavated around the entire perimeter of a drilling operation to contain contaminated runoff. This ring
levee may have a volume of 6,000 bbls, sufficient to contain 500 bbls of the first flush. However,
collection of these 500 bbls when 6,000 bbls may be present in the ring levee would not effectively capture
the first flush. Costs to install a separate collection system including pumps and tanks, would add
significantly to the cost of this option.
While costs are significant, the technological difficulties involved with adequately capturing deck
drainage at coastal facilities are the principal reason why additional requirements were rejected for the final
rule.
EX-33
-------
The volume of contaminated deck drainage can be reduced by segregating the clean area of the site
from the potentially contaminated area.41 This involves using a segregation berm to separate the office
trailer and parking/truck maneuvering areas which generate relatively little pollution from the drilling
equipment, pipe racks, production and treatment areas, and waste storage areas. Such a set up which also
recycled the dirty water into the mud system was reported to result in a 40% savings to location and waste
management costs.41 The storm water from the non-contaminated side of a drilling or production site
would be subject to NPDES requirements for storm water and may require the operator to develop and
implement a site-specific storm water pollution prevention plan consisting of a set of BMPs, depending on
specific sources of pollutants at each site. A discussion of best management practices is presented in
Chapter XVI of this document.
4.0 PRODUCED SAND
Produced sand consists of the accumulated formation sands and other particles (including scale)
generated during production as well as the slurried particles used in hydraulic fracturing. This waste
stream also includes sludges generated by chemical fiocculation used in solids separation processes for
produced water such as filtration or sedimentation. The following sections describe the sources, volumes,
characteristics, and treatment methods for produced sand.
•t-
4.1 PRODUCED SAND SOURCES
Produced sand is generated during oil and gas production by the movement of sand particles in
producing reservoirs into the wellbore, by silica material spilling off the face of the producing formation
and by the precipitation of scale and other solid particles. The generation of produced sand usually occurs
in reservoirs comprised of young, unconsolidated sand formations.42 Produced sand is considered a solid
and consists primarily of sand and clay with varying amounts of mineral scale (epsom salts, magnesite,
gypsum, calcite, barite, and celestite) and corrosion products (ferrous carbonate and ferrous sulfide).43
Produced sand is carried from the reservoir to the surface by the fluids produced from the well.
The well fluids stream consists of hydrocarbons (oil and/or gas), water, and sand. At the surface, the
production fluids are processed to segregate the specific components. The produced sand drops out of the
well fluids stream during the separation process due to the force of gravity as the velocity of the stream
is decreased during passage through the treatment vessels. The sand accumulates at low points in the
equipment and is removed periodically through sand drains, manually during equipment shut-downs for
cleaning, or by periodic blowdowns as a wet sludge containing both water and oil.44-45 One source indicates
IX-34
-------
that desanders or desilters (hydrocyclones) are used to remove sand if the volume produced is high.43
However, observations during the EPA 1992 Production Sampling Program indicate that for lower
production volumes more typical of coastal situations, sand removal is primarily achieved by tank cleanouts
and that desanders are seldom used.38 Equipment is typically cleaned on a three to five year cycle. At
some locations, sand is collected on a yearly basis because large volumes of sand are being generated due
to failure of downhole sand control measures.45
4.2 PRODUCED SAND VOLUMES
The generation rate of produced sand will vary between wells and is a function of the amount of
total fluid produced, location of the well, type of formation, production rate and completion methods.43-44
Oil producing reservoirs will typically generate more produced sand than gas producing reservoirs. This
is because oil reservoirs generate more liquids (both oil and water) which are more viscous than gas and
thus the liquids will remove and cany the sand more easily to the surface than gas. Also, the greater water
volumes associated with oil reservoirs will create more scale particles. Another reason is because gas
producing wells have sensors that detect sand flowing with the gas stream to prevent erosion on the
production equipment due to sand flowing with the gas at high velocities.46 Table IX-20 presents a
summary of the produced sand volumes data.
4.2.1 Gulf of Mexico
224 production separation facilities in the Gulf of Mexico provided produced sand data in the 1993
Coastal Oil and Gas Questionnaire.8 Of these 224, a total of 37 facilities reported produced sand
generation volumes. The average volume generated was 74 bbls. Since produced sand is not collected
from process equipment every year, the survey only represents a snapshot of produced sand collection for
the year of 1992. The average frequency of generation of produced sand for these 37 facilities ranged
between 2.2 times per year and once every 2.9 years. Although only 16.5% of the facilities reported
produced sand volume data, this does not indicate that 83.5 % of the facilities did not generate any produced
sand that year. It indicates that either these facilities did not generate any produced sand, or no produced
sand was collected from the process equipment for that year, or that the volume was unknown.
The annual sand generation rates obtained during EPA's 1992 10 production facility study ranged
from 106 to 400 bbls for facilities with produced water flowrates of 6,462 and 7,000 bpd respectively.38
In addition, one of the two commercial produced water injection facilities sampled by EPA hi 1992
IX-35
-------
TABLE IX-20
PRODUCED SAND VOLUMES GENERATED
Source
Oil & Gas
Questionnaire
Trip Reports
f^\Jf L;
Produced Sand
Generated
74 bblsa
106 bbls38
400 bbls38
liiesdco -^ ; * } f
Frequency
1/2.9 yr*
1/1 yr38
1/1 yr38
f •" fff : "•
; •, ;' ^""'-"Cook
Produced Sand
Generated
365 bbl8
Ibbl8
Ibbl8
Ibbl8
600 bbl22
,$ ' •',•'
Met , *s ,
Frequency
—
V^+yr22
* Estimated average from SAIC, September 30, 1994.s
reported an annual sand generation rate of 50 bbls with an average produced water flowrate of 5,000 bpd.47
It is likely that some of the produced sand in the produced water received by the commercial facility would
have settled out in the production equipment and produced water storage tanks prior to being sent to
commercial disposal.
The Coastal Oil and Gas Questionnaire indicates that only one of the operators surveyed discharged
produced sand at three of its facilities hi 1992. The operator indicated that this practice would be
discontinued in the near future.48 All other operators dispose of produced sands via landfarming,
underground injection, landfilling, or onsite storage. The total sand production from the three sites
discharging sand was 144 bbls which is a small proportion of produced sand generated in the region.
4.2.2
Cook Inlet
Four of the platforms in Cook Inlet reported produced sand generation volumes in the 1993 Coastal
Oil and Gas Questionnaire.8 One reported generating 365 bbls in 1992 while the remaining three reported
only one bbl for 1992. Operators of the Bruce Platform in Cook Inlet reported that they had removed 600-
bbls of produced sand for disposal from their two 600-bbl produced water settling tanks two years prior
to EPA's visit in August 1993.22 Therefore, the amount generated per platform can vary greatly. The
current produced sand disposal practice in Cook Inlet is zero discharge via land disposal and storage for
future land disposal.49-50 In the past, produced sand from the Bruce Platform had been sent to the Kenai
IX-36
-------
Gas Field for storage. This produced sand has recently been ground and injected as part of a pilot project
to grind and inject stored wastes and the contents of old reserve pits.23
4.3 PRODUCED SAND CHARACTERIZATION
Produced sand is generally contaminated with crude oil from oil production or condensate from
gas production. The primary contaminant associated with produced sand is oil.12 The oil content of
unwashed produced sand can range from a trace (expected in sand from blowdown) to as much as 19
percent by volume.
During the EPA 1992 Production Sampling effort, samples of settling tank bottoms were collected
at four facilities and analyzed for conventional, non-conventional, organic pollutants and metals and
radionuclides.38 These samples are considered representative of produced sand. Table IX-21 presents the
maximum and minimum observed concentrations detected in these samples. In cases of a single detect for
a particular pollutant, the detected concentration value is reported in Table IX-21 as the maximum observed
concentration. Due to a limited volume available at some of these sites, not all analytes were analyzed for
all of the samples. For the two samples that were analyzed for oil content, the concentration ranged from
12.7 to 19 percent. All toxic metals were present except silver, with most notable contributions from
copper (32.15 mg/kg) and lead (171.94 mg/kg).51 The toxic organic pollutants present were similar to
those found hi produced water including benzene, ethylbenzene, toluene, xylene, propanone, and
phenanthrene.
4.4 PRODUCED SAND CONTROL AND TREATMENT TECHNOLOGIES
The primary control and treatment technology for produced sand is preventing the sand from
exiting the formation. Sand control is determined by the type of well completion. A specialized
completion can prevent sand from being brought into the production line with the fluids.46 The most up-to-
date completion technology will prevent production solids from entering the production tubing, even hi
loose and unconsolidated formations.
The most common type of completion that prevents solids from entering the production tubing is
a gravel pack completion. A gravel pack completion is a perforated cased hole completion that includes
the placement of gravel, glass beads, or some other packing material between the production tubing and
the casing. A screen or mesh is also placed between the production tubing and the casing. The gravel
pack and screen serve as a filter to prevent solids from entering the production tubing. Older wells are
K-37
-------
TABLE IX-21
RANGE OF POLLUTANT CONCENTRATIONS IN PRODUCED SAND
FROM THE 1992 COASTAL PRODUCTION SAMPLING PROGRAM51
Pollutant
%<
Total Recoverable Oil & Grease
Oil Content
Total Solids
BOD 5-day (Carbonaceous)
Total Organic Carbon (TOC)
Ph
Chloride
Fluoride
Nitrate/Nitrite
Total Releasable Sulfide
Total Sulfide (Isometric)
JftaA*
COJTOBNTION4
Mg/kg
%
Mg/kg
Mg/kg
Mg/kg
Ph
Mg/kg
Mg/kg
Mg/kg
Mg/kg
Mg/kg
o Number-of,
-• ^Samples ' $?
3
2
3
3
3
3
3
3
3
3
3
. Number of
'••- •• Detects '-
3
2
3
3
3
3
3
3
1
1
2
Minimum
Value '
"i <
84,000.00
12.70
76.00
16,000.00
20,000.00
6.70
1,360.78
1.30
(a)
(a)
26.14
- , •.-,,- \«c'", PMOMTY^OOJCTAKl* METALS ,
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
Aluminum
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
NON-ERTOK
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
4
4
4
4
4
4
4
4
4
4
4
4
1
2
3
2
4
4
4
1
4
1
1
4
(a)
8.30
0.10
0.93
3.70
6.50
25.70
(a)
4.90
(a)
(a)
63.80
ixripoM.mv^m'METAi^ ,
4
4
4
4
4
4
4
4
4
4
2
4
4
4
4
4
4
4
4
4
4
4
4
4
2
4
2
4
3
4
4
4
879.00
201.00
26.80
6,020.00
1.70
4,650.00
602.00
54.50
1.60
13,300.00
131.00
1,570.00
3.80
14.60
2.90
2.30
Maximum!
-' Vklae
\ f / '
328,562.87
19.00
1,052,084.21
161,413.51
285,693.11-
10.50
25,000.00
368.25
19.00
200.00
2,000.00
'', '
4.50
34.00
0.20
2.20
26.60
72.00
510.00
0.20
12.50
4.00
2.70
11,700.00
"/ ,
71,100.00
3,680.00
328.00
23,500.00
3.50
14,300.00
3,030.00
121.00
15.70
32,800.00
256.00
5,890.00
349.00
60.80
18.60
5.80
«^ „ '..
Benzene
Ethylbcnzcne
Methylene Chloride
Mg/kg
Mg/kg
Mg/kg
3
3
3
3
3
2 . '
55,352.86
33,170.00
193.37
283,445.00
296,995.00
54,140.35
EX-38
-------
TABLE EX-21 - Continued
RANGE OF POLLUTANT CONCENTRATIONS IN PRODUCED SAND
FROM THE 1992 COASTAL PRODUCTION SAMPLING PROGRAM51
;, - /' **•*"«*-
"'•••" - ' , <
Toluene
Trichlorofluoromethane
stMtS s -
COmmm&m
Mg/kg
/*g/kg
Number of -
Samples
3G-AN0NON-€C
3
3
Number-of
.Detects
SNViSNTJOOKEAL
3
2
Minimum
*. Vatoe
«
89,417.14
30,707.14
Maximum
-Vatofe
355,835.00
250,754.39
NON-PRIORITY POLLUTANT VOLATILE ORGANICS
M-Xylene
O+P Xylene
2-Propanone
jig/kg
Mg/kg
Mg/kg
3
3
3
3
2
1
18,827.14
70,039.68
(a)
161,610.00
116,645.00
222,183.05
% v " < ""• " piaoHrjnnpQi£OTA)OT ^ - , „,
Acenaphthene
Anthracene
Fluorene
Naphthalene
Phenanthrene
2,4,6-Trichlorophenol
^ig/kg
^tg/kg
^g/kg
Mg/kg
/ig/kg
/*g/kg
3
3
3
3
3'
3
1
1
2
3
2
1
(a)
(a)
12,115.33
46,547.00
19,739.00
(a)
8,511.33
10,442.33
19,521.00
57,003.33
26,779.67
139,153.33
•-~ - — „'- - - ^NOKf-mQRITiriXHi^ ,'"- ^ ** "
Acetophenone
Biphenyl
Dibenzofuran
Dibenzothiophene
n-Decane
n-Docosane
n-Dodecane
n-Eicosane
n-Hexacosane
n-Hexadecane
n-Octacosane
n-Octadecane
n-Tetracosane
n-Tetradecane
n-Triacontane
1-Methylfluorene
1-Methylphenanthrene
1-Phenylnaphthalene
2-Isopropylnaphthalene
2-Methylnaphthalene
2-Phenylnaphthalene
3,6-Dimethylphenanthrene
4-Aminobiphenyl
/ig/kg
Atg/kg
/*g/kg
ptg/kg
^tg/kg
^g/kg
/ig/kg
Mg/kg
*tg/kg
**g/kg
Atg/kg
Mg/kg
Atg/kg
Mg/kg
^g/kg
Mg/kg
^g/kg
/*g/kg
jtg/kg
ptg/kg
A*g/kg
/ig/kg
/tg/kg
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
1
2
1
2
3
3
3
3
3
3
3
3
3
3
3
3
2
1
1
2
2
1
1
(a)
25,620.33
(a)
4,873.33
7,302.67
53,659.33
50,642.33
139,153.33
20,380.00
250,070.00
5,543.67
225,183.33
64,200.00
253,220.00
16,789.00
31,473.33
10,717.33
(a)
(a)
96,533.33
6,012.00
(a)
(a)
50,996.67
50,769.33
15,397.00
6,826.33
169,263.33
199,183.33
716,843.33
333,090.00
123,716.67
554,033.33
150,746.67
463,686.67
187,440.00
439,433.33
393,873.33
88,670.00
38,270.00
5,124.00
39,190.00
155,923.33
6,871.33
62,333.33
31,025.67
' - ,,- , - '* - * RASaONCCLIDES - - ~" ~ v ;
Gross Alpha
Gross Beta
Lead 210
Radium 226
Radium 228
pCi/g
pCi/g
pCi/g
pCi/g
pCi/g
4
4
4
5
5
1
4
3
4
3
(a)
12.00
4.20
2.60
2.70
872.00
668.00
11.70
6.90
6.50
(a) Analyte detected in only one sample; the detected value is reported as the maximum.
EX-39
-------
typically open holed perforated completions in which nothing prevents solids from entering the production
tubing with the fluid. Figure K-3 presents a schematic diagram of a closed hole perforated completion
with gravel packing.
Gas producing wells are typically equipped with sand sensors which indicate the presence of sand
in the gas stream. Sand sensors are commonly used in gas producing wells because sand flowing at high
velocities with the produced gas will erode tubing, valves, and other process equipment. A sand sensor
is a simple device that detects the sand particles hitting its surface. If sand is detected, an electrical signal
will trigger an alarm to notify the operator. The operator can either alleviate the sand generation problem
at (he source or reduce the gas velocities to prevent the sensor from detecting the sand flow. The sand
probes do not work in liquid streams and thus are not used on oil producing wells.46 In addition, produced
sand contained in liquids such as oil and water do not pose as great a physical erosion problem due to the
lower velocities of these fluids and the lubricating properties of the liquids.
4.4.1 BPT Technology
The management of produced sand wastes involves either treating the sand to meet the no free oil
limitations and discharge to the surface waters, land application, or hauling the sand to a commercial
facility for final disposal.
Of the 10 coastal production facilities in the Gulf of Mexico region visited by EPA in 1992, only
one reported onsite disposal of produced sand. At this facility located in Texas, produced sand is removed
from the produced water treatment tanks and deposited on the ground within the diked area. Samples are
collected for oil and grease analysis and if the concentration is below 1.0 percent, they are allowed to
dispose of the produced sand by spreading it on their sand and gravel roads.52 The remaining nine
production facilities reported that they transport produced sand to commercial disposal facilities.
Data from the 1993 Coastal Oil and Gas Questionnaire indicate that 4.6 percent of the coastal
facilities in the Gulf of Mexico inject produced sand and that the remainder is either landfilled, stored
onsite for future disposal, hauled offsite for disposal or is encapsulated and disposed in abandoned wells.5
Since only one operator in the Gulf of Mexico reported discharge of produced sand and that
operator reported its intention to discontinue this practice, this information indicates that the current
practice of the industry is zero discharge. The one operator that reported discharge of produced sand
IX-40
-------
1
Production
Tubing
Cement
Casing
Hanger
Liner Cemented
and
Perforated
Figure EX-3
Closed Hole Perforated Completion (With Gravel Pack)
IX-41
-------
indicated that the sand was first treated by sand washing prior to disposal.48 A detailed discussion of sand
washing technology and its capabilities is presented below.
4.4.2 Additional Technologies
Several methods other than zero discharge via land disposal were identified hi the literature for
treatment of produced sand and are included hi this section. The treatment methods include: washing the
material with water and detergents, mechanical separation, separation with solvents, thermal treatment and
air flotation. Most of the sources consulted did not provide data or cleaning efficiencies for the treatment
of produced sand.
Data submitted from an industry supported study for the offshore subcategory demonstrate the
variability of oil content in washed sand. In the study, produced sand was washed using detergents and
the resultant oil content ranged from 0.99 to 4.6 percent by weight.53 Information recently reached regard-
ing current sand washing technology indicates that oil can be removed without the use of detergents or
other chemicals.54-55 Data provided by vendors submitted in comments to the proposed rule demonstrate
that the oil content of washed sand can be below 1 percent by weight but can vary from 0.2 percent to 3.9
percent. Another sand washing system demonstrated at offshore sites generates sand capable of meeting
a no-free-oil limitation, although residual liquids and solids (by-products from washing) remain which are
unable to meet the no-free-oil limitation and must be disposed in a manner other than surface discharge.56
Several other treatment systems have been identified in the literature:
• A sand washer system that mechanically removes oil from produced sand consisting of a bank
of cyclone separators, a classifier vessel, and another cyclone. Following treatment the sand
is reported to have no trace of oil.57 Actual data were not presented.
• A sand cleaning system consisting of two vertical two-phase separators. The initial separator
is baffled and sand falls through to the second separator. The second separator contains a
solvent layer to absorb oil from the sand grains.57 Data were not presented.
• A produced sand disposal system consisting of a conventional cyclone and a cyclone with
chemical and air injection that removes the oil by air flotation.58
Treatment of produced sand via mechanical washing has several drawbacks. The capital costs
necessary to install a complete sand washing unit on a platform preclude the widespread installation of
systems on platforms which only need to wash sand every 3 to 5 years. In addition to the equipment costs,
EX-42
-------
current existing platform space is limited or not available for such equipment and therefore the addition
of extra platform space would be required. Sand washing does not always guarantee one-hundred percent
discharge of the sand. Sands containing heavy oils cannot always be washed thoroughly enough to meet
the permit discharge prohibition on free oil. In these cases, the sand cannot be discharged and must be
transported offsite for disposal. Since sand washing is designed to only reduce the oil content, produced
sand that contains certain levels of Naturally Occurring Radioactive Material (NORM) must be transported
to shore for disposal depending on state requirements. In addition, sand washing can generate additional
wastes, such as oily solids and oily water, which require further treatment and disposal.
5.0 DOMESTIC WASTES
5.1 DOMESTIC WASTE SOURCES
Domestic wastes (gray water) originate from sinks, showers, laundry, food preparation areas, and
galleys on the larger facilities. Domestic wastes also include solid materials such as paper, boxes, etc.
5.2 DOMESTIC WASTE VOLUME AND CHARACTERISTICS
The volume of domestic waste discharged has been estimated to range from 50 to 100 gallons per
person per day, with a BOD of 0.2 pound per day per person.36-59 For drilling rigs, rather than require
flow measurement, the State of Louisiana requires operators to report the estimated domestic waste volume
as equal to 0.7 bbs/day (30 gal/day) per person occupying the rig.27 The 1993 Coastal Oil and Gas
Questionnaire statistics estimate that 76 percent of production facilities discharge domestic/sanitary wastes
with an average volume of 2,049 bpy (282 bpd).5 It often is necessary to utilize macerators with domestic
wastes to prevent the release of floating solids. Chlorination is not necessary since these wastes do not
contain coliforms. Tables LX-22 and IX-23 summarize the volume and characteristics of domestic wastes
for offshore platforms which would reflect domestic waste in Cook Inlet.
5.3 DOMESTIC WASTE CONTROL AND TREATMENT TECHNOLOGIES
Because domestic wastes do not contain fecal coliform, no chlorination is required. Domestic
wastes must only be ground up so as to comply with the NPDES permit prohibitions on discharges of
floating solids. Maceration by comminutor should be sufficient treatment. Treatment such as macerators
will guarantee that this discharge will not result in any floating solids. In addition, many existing NPDES
and State permits prohibit discharges of foam (as no visible foam). Where existing discharges may be
experiencing discharges of foam, measures taken to remediate the situation can include the relocation of
IX-43
-------
TABLE EX-22
TYPICAL UNTREATED COMBINED SANITARY AND DOMESTIC WASTES FROM
OFFSHORE FACILITIES60
Number of
Persons
76
66
67
42
10-40
How
(gal/day)
5,500
1,060
1,875
2,155
2,900
* « < <. A < ^ * -. -. ^ •. s^ * ¥• ^
"* - BOD * '
„ «$*»! \ SfXjis^ t * .., •> -v
- "*
v-V%s " iv\ ^>
ClRan^e f
JV^-T,^ %^> •(••;.?'
270-770
Suspendi
. <»
Average
195
1,025
620
220
-d Solids
g» ' < ,
** •,•"• •>
v I?ange
14-543
1,025
620
220
« f> y •• •• » V
•*,?, '< -- '
s * .• '
Total Colifowns ' ,
' ' (*!«*, -
10-180
TABLE EX-23
TYPICAL OFFSHORE SANITARY AND DOMESTIC WASTE CHARACTERISTICS61
Waste TNppe
Sanitary Waste
(treated)
Domestic Waste
(direct discharge)
•. ^ <
Discharge ' ',
Rate s C
(mtVcap/day) ,
0.075
0.110
- -.-. *-, Loading " ""••' "„
•,* -.>%•• ^
"^ 5s *! '
4V>*> "#*•
^^cap/da^^
0.002
0.022
t __ v1^*
1-"S.S; T'
i ,(k§/cap/day) ,•
0.003
0.016
*•! ^ %C ' ff * ' ' < ' '• * f
- '-, - '- Concentration - :
BOB * '
'; C«>g*l)
30
195
, ,&a
(mgtl) ,
40
140
j Residual
'dhJwinfe ,
;'(i»g/D
1.7
0
the discharge to a standpige with a subsurface discharge location and careful selection and use of
detergents.
5.3.1 Additional Technologies
EPA is incorporating Annex V of the Convention to Prevent Pollution from Ships (MARPOL), Part
151 of Title 33 Code of Federal Regulations, and the Act to Prevent Pollution from Ships, 33, U.S.C. 1901
et seq., in the BCT and NSPS limitations on domestic waste.
EX-44
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EPA compiled U.S. and international regulations governing the discharge of domestic wastes into
ocean waters from ships and fixed or floating platforms. Although these Coast Guard regulations are
primarily intended for offshore and international waters, EPA Region VI has adopted them as part of the
domestic wastes limitations in the General Permit for coastal drilling operations (58 FR 49126).
International waters are governed by MARPOL 73/78 (the International Convention for the Prevention of
Pollution from Ships, 1973, as modified by the Protocol of 1978 relating thereto). The Coast Guard
implemented MARPOL 73/78 as part of its pollution regulations (33 CFR-Part 151) governing U.S.
waters.
Disposal from drilling rigs are dealt with in Regulation 4 of Annex V .of MARPOL. It states that:
(1) Fixed or floating platforms engaged in the exploration, exploitation, and associated
offshore processing of sea-bed mineral resources, and all other ships alongside
such platforms or within 500 meters of such platforms, are forbidden to dispose
of any materials regulated by this Annex, except as permitted by paragraph (2) of
this Regulation.
(2) The disposal into the sea of food wastes when passed through a comminutor or
grinder from such fixed or floating drilling rigs located more than 12 nautical
miles from land and all other ships when positioned as above. Such comminuted
or ground food wastes shall be capable of passing through a screen with openings
no greater than 25 mm.
Table IX-24 summarizes the garbage discharge restrictions from fixed or floating platforms.
In summary, under the Coast Guard Regulations, discharges of garbage, including plastics, from
fixed and floating platforms engaged in the exploration, exploitation and associated offshore processing of
seabed mineral resources are prohibited with the exception that food wastes may be discharged from fixed
and floating platforms located beyond 12 nautical miles from the nearest land (33 CFR 151.75).
6.0 SANITARY WASTES
6.1 SANITARY WASTE SOURCES, VOLUMES AND CHARACTERISTICS
The sanitary wastes from oil and gas facilities are comprised of human body wastes from toilets
and urinals. The volume and concentration of these wastes vary widely with time, occupancy, platform
characteristics, and operational situation.
IX-45
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TABLE IX-24
GARBAGE DISCHARGE RESTRICTIONS
1 - -> "v -XH * * •• v ; ^
^ ''%' •< *s *•
-, , " _. >•*»•*» ' - V^
Garbage Type -,;',- ,
Plasdcs - includes synthetic ropes and fishing
nets and plastics bags.
Dunnage, lining and packing materials that float.
Paper, rags, glass, metal bottles, crockery and
similar refuse.
Paper, rags, glass, etc. comminuted or ground.*
Victual waste not comminuted or ground.
Victual waste comminuted or ground.*
Mixed garbage types.0
* V :- Fixed or Floating Platforms &
v< -, Associated Vessels* , (33 CFRISI. 73) '}
Disposal prohibited (33 CFR 151.67)
Disposal prohibited
Disposal prohibited
Disposal prohibited
Disposal prohibited
Disposal prohibited less than 12 miles from
nearest land and in navigable waters of the U.S.
See note c.
* Fixed or floating platforms and associated vessels include all fixed or floating platforms engaged in exploration,
exploitation, or associated offshore processing of seabed mineral resources, and all ships within 500m of such platforms.
Comminuted or ground garbage must be able to pass through a screen with a mesh size no larger than 25 mm (1 inch)
(33 CFR 151.75).
c When garbage is mixed with other harmful substances having different disposal requirements, the more stringent
disposal restrictions shall apply.
EPA compiled U.S. and international regulations governing the discharge of sanitary waste into
ocean waters from manned ships and manned fixed or floating platforms. International waters are
governed by MARPOL 73/78, Annex IV which deals specifically with the disposal of sewage from ships.
The Federal Water Pollution Control Act (FWPCA) §312 (33 U.S.C. 1322) administered/implemented by
U.S.EPA, provides the regulations and the standards to eliminate the discharge of untreated sewage from
vessels into waters of the U.S. and the territorial seas. The U.S. Coast Guard has established regulations
governing the design and construction of marine sanitation devices and procedures for certifying that
marine sanitation devices meet the regulations of the FWPCA (33 CFR Part 159 and 40 CFR Part 140).
Combined sanitary and domestic waste discharge rates of 3,000 to 13,000 gallons per day have
been reported.62 Monthly average sanitary waste flow from Gulf Coast platforms was 35 gallons per day
based on discharge monitoring reports.63 For drilling rigs, rather than require flow measurement, the State
of Louisiana requires operators to report the estimated sanitary waste volume as equal to 0.00006
MGD/day (60 gal/day) per person occupying the rig.27 The EPA 1993 Coastal Oil and Gas Questionnaire
IX-46
-------
statistics estimate that 76 percent of production facilities discharge domestic/sanitary wastes with an average
volume of 2,049 bpy (282 bpd).5
6.2 SANITARY WASTE CONTROL AND TREATMENT TECHNOLOGIES
There are two alternatives to handling of sanitary wastes from coastal facilities. The wastes can
be treated at the facility, or they can be retained and transported to shore facilities for treatment. However,
due to storage limitations on platforms, water-access facilities usually treat and discharge sanitary waste
at the source. The treatment systems presently in use may be categorized as physical/chemical and
biological.
Physical/chemical treatment may consist of evaporation-incineration, maceration-chlorination, and
chemical addition. With the exception of maceration-chlorination, these types of units are often used to
treat wastes on facilities with small numbers of men or which are intermittently manned. The incineration
units may be either gas fired or electric. The electric units have been difficult to maintain because of
saltwater corrosion and heating coil failure. The gas units are not subject to these problems, but create a
potential source of ignition which could result in safety hazards. Some facilities have chemical toilets
which require hauling of waste and create odor and maintenance problems. Macerators-chlorinators would
be applicable to provide minimal treatment for small and intermittently manned facilities.
The most common biological system applied to manned water-access operations is aerobic digestion
or extended aeration processes. These systems usually include a comminutor which grinds the solids into
fine particles, an aeration tank with air diffusers, a gravity clarifier return sludge system, and a chlorination
tank. These biological waste treatment systems have proven to be technically and economically feasible
means of waste treatment at offshore facilities which have more than 10 occupants and are continuously
manned.
BPT for sanitary wastes from coastal facilities continuously manned by 10 or more persons requires
a residual chlorine content of 1 milligram per liter (and maintained as close to the limit as possible).
Facilities continuously manned by fewer than 10 persons or intermittently manned by any number of
persons are prohibited from discharging floating solids. These standards are based on end-of-pipe
technology consisting of biological waste treatment systems (extended aeration). The system may include
a comminutor, aeration tank, clarifier, return sludge system, and disinfection contact chamber. Studies
of treatability, operational performance, and flow fluctuations are required prior to application of a specific
IX-47
-------
treatment system to an individual facility. EPA has not identified any additional control beyond BPT
appropriate for this wastestream.
7.0 MINOR DISCHARGES
The term "minor" discharges is used here to describe all point sources originating from coastal oil
and gas drilling and production operations, other than produced water, drilling fluids, drill cuttings, deck
drainage, produced sand, well treatment, completion and workover fluids, and sanitary and domestic
wastes. The following sections identify these discharges followed by a brief description.
7.1 BLOWOUT PREVENTER (BOP) FLUID
An oil (vegetable or mineral) or antifreeze solution (glycol) is used as hydraulic fluid in blowout
preventer (BOP) stacks during drilling of a well. The blowout preventer is designed to maintain the
pressure in the well that cannot be controlled by the drilling mud. Small quantities of BOP fluid are
discharged periodically to the sea floor during testing of the blowout preventer device. Such discharges
are limited to deep water operations such as in Cook Met. BOP fluid released from above water
applications would be captured, treated and disposed accordingly.
7.2 DESALINATION UNIT DISCHARGE
This is the residual high-concentration brine discharged from distillation or reverse osmosis units
used for producing potable water and high quality process water. The concentrate is similar to sea water
in chemical composition. However, as the name implies, anion and cation concentrations are higher. This
waste is discharged directly to the surface as a separate waste stream.
7.3 FIRE CONTROL SYSTEM TEST WATER
The local water source, which may be treated with a biocide, is used as test water for the fire
control system on platforms and other facilities. This test water is discharged directly as a separate waste
stream.
7.4 NON-CONTACT COOLING WATER
Non-contact, once-through water is used to cool crude oil, produced water, power generators, and
various other pieces of machinery at production and drilling operations. Biocides can be used to control
IX-48
-------
biofouling in heat exchanger units. Non-contact cooling waters are discharged directly to the surface as
a separate waste stream.
7.5 BALLAST AND STORAGE DISPLACEMENT WATER
Two types of ballast water are found in production and drilling operations: tanker and platform
ballast. Tanker ballast water can be either salt/brackish water or fresh water from the area where ballast
was pumped into the vessel. It may be contaminated with crude oil (or possibly some other cargo such as
fuel oil), if the vessel is not equipped for segregated cargo and does not have segregated ballast tanks.
Unlike tank ballast water, which may be from multiple sources and may contain added
contaminants, platform stabilization (ballast) water is taken on from the waters adjacent to the platform and
will, at worst, be contaminated with stored crude oil and platform oily slop water. Newly designed and
constructed floating storage platforms use permanent ballast tanks that become contaminated with oil only
in emergency situations when excess ballast must be taken on. Oily water can be treated through the
oil/water separation process prior to discharge.
7.6 BILGE WATER
Bilge water is a minor waste for floating platforms. Bilge water is seawater that becomes
contaminated with oil and grease and with solids such as rust, when it collects at low points in the bilges.
This bilge water is usually directed to the oil/water separator system used for the treatment of ballast or
produced water, or is discharged intermittently.
7.7 BOILER SLOWDOWN
Purges from boilers circulation waters necessary to minimize solids build-up are intermittently
discharged to the surface.
7.8 TEST FLUIDS
Test fluids are discharges that would occur if hydrocarbons are located during exploratory drilling
and tested for formation pressure and content.
EX-49
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7.9 DlATOMACEOUS EARTH FILTER MEDIA
Diatomaceous earth filter media are used to filter seawater or authorized completion fluids and then
washed from the filtration unit.
7.10 BULK TRANSFER OPERATIONS
The transport and handling of bulk materials can result in discharges of barite or cement.
7.11 PAINTING OPERATIONS
Sandblasting and painting operations can result in discharges of sandblast sand, paint chips, and
paint spray.
7.12 UNCONTAMINATED FRESHWATER
Uncontaminated freshwater discharges come from wastes such as air conditioning condensate or
potable water during transfer or washing operations.
7.13 WATERFLOODING DISCHARGES
Oil fields that have been produced to depletion and have become economically marginal may be
restored to production, with recoverable reserves substantially increased, by secondary recovery methods.
The most widely used secondary recovery method is waterflooding. A grid pattern of wells is established,
which usually requires downhole repairs of old wells or drilling of new wells. By injecting water into the
reservoir at high rates, a front or wall of water moves horizontally from the injection wells toward the
producing wells, building up the reservoir pressure and sweeping oil in a flood pattern.
Waterflooding can substantially improve oil recovery from reservoirs that have little or no
remaining reservoir pressure. Treated seawater typically is used in Cook Inlet for injection purposes.
Waterflooding is also used in California and to a lesser degree in the Gulf of Mexico region. Treatment
consists of filtration to remove solids that would plug the formation, and dearation. Dissolved oxygen is
removed to protect the injection pipeline system from corrosion. A variety of chemicals can be added to
water flooding systems such as flocculants, scale inhibitors, and oxygen scavengers. Biocides are also used
to prevent the growth of anaerobic sulfate-reducing bacteria, which can produce corrosive hydrogen sulfide
in the injection system. Discharges from water flooding operations will include excess injection water and
backwash from filtering systems.
EX-50
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7.14 LABORATORY WASTES
Laboratory wastes contain material used for sample analysis and the material being analyzed. The
volume of this waste stream is relatively small and is not expected to pose significant environmental
problems. Freon may be present in laboratory waste. Because freon is highly volatile, it will not remain
in aqueous state for very long. The Agency is discouraging the discharge of chlorofluorocarbon to air or
water media.
7.15 NATURAL GAS GLYCOL DEHYDRATION WASTES
A common step in processing natural gas is dehydration using a desiccant such as triethylene
glycol. In this process natural gas is brought into contact with a glycol stream which has an affinity for
and adsorbs water vapor. The glycol is then passed through a reboiler where the water is distilled out of
the solution. This vaporized water is then condensed into a liquid waste stream. This waste stream may
be returned to the produced water treatment and disposal system or it may be surface discharged.
Sometimes impurities will build up in the glycol solution requiring that it be replaced. Spent glycol can
be regenerated onsite through distillation or it is hauled offsite for regeneration or disposal.
7.16 MINOR WASTES VOLUMES AND CHARACTERISTICS
Information concerning the characteristics, discharge volumes, and the frequency of discharge of
these minor waste streams is limited. Table IX-25 provides a range of discharge volumes for the minor
waste streams that were identified for the offshore category. Data concerning the characteristics and
volumes of test fluids, diatomaceous earth filter media, bulk transfer operations, and painting operations
are not available.
IX-51
-------
TABLE IX-25
MINOR WASTE DISCHARGE VOLUMES15
Waste V;, 1_^i>;™ ,
BOP fluid
Boiler blowdown
Desalination waste
Fire system test water
Noncontact cooling water
Uncontaminated ballast/bilge water
Water flooding
Test fluids
Diatomaceous earth filter media
Bulk transfer operations
Painting operations
Uncontaminated fresh water
Glycol dehydration condensate
' '' *' ' •*»" ^* ft > ' ' '''
' ," ^ s , " Discharge Volume „, '-;
10 - 500 gal/day
0 - 5 bbl/day
typically < 238 bbl/day
24 bbl/test
7 - 124,000 bbl/day
70 - 620 bbl/day
up to 4,030 Ib solids/month
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
K-52
-------
8.0 REFERENCES
1. 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)," January 1993.
2. Memorandum from Allison Wiedeman, Project Officer to Marv Rubin, Branch Chief, regarding
"Supplementary Information to the 1991 Rulemaking on TreatmentAVorkover/Completion Fluids,"
December 10, 1992.
3. American Petroleum Institute, "Detailed Comments on EPA Supporting Documents For Well
Treatment and Workover/Completion Fluids." Attachment to API Comments on the March 13,
1991 Proposal, May 13, 1991. (Offshore Rulemaking Record Volume 146).
4. Parker, M.E., "Completion, Workover, and Well Treatment Fluids," June 29, 1989. (Offshore
Rulemaking Record Volume 116).
5. SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31, 1995.
6. Jones, A., ERG, Memorandum to Niel Patel, U.S. EPA, regarding "Estimates for total numbers
of coastal wells, operators, and production," September 26, 1994.
7. Envirosphere Company, Summary Report: Cook Inlet Discharge Monitoring Study: Workover,
Completion and Well Treatment Fluids, Discharge Numbers 017, 018 and 019, prepared for the
Anchorage, Alaska Offices of Amoco Production Company, ARCO Alaska, Inc., Marathon Oil
Company, Phillips Petroleum Company, Shell Western E&P Inc., Texaco Inc., Unocal
Corporation, and the U.S. EPA Region X, Seattle, Washington, April 10, 1987 - September 10,
1987. (Offshore Rulemaking Record Volume 116)
8. U.S. EPA, Responses to the "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160, July
1993. (Confidential Business Information)
9. Orentas, N., Avanti, Memorandum to the record regarding "Calculation of Total Annual TWC
Fluid Discharge Volume for All Operators in Cook Inlet, Alaska," September 30, 1996.
10. Wilkins, Glynda E., Radian Corporation, "Industrial Process Profiles for Environmental Use
Chapter 2: Oil and Gas Production Industry," for U.S. EPA, EPA-600/2-77-023b, February 1977.
(Offshore Rulemaking Record Volume 18).
11. Hudgins, Charles M., Jr., "Chemical Treatments and Usage in Offshore Oil and Gas Production
Systems," prepared for American Petroleum Institute, Offshore Effluent Guidelines Steering
Committee, September 1989. (Offshore Rulemaking Record Volume 145).
12. Arctic Laboratories Limited, et. al., "Offshore Oil and Gas Production Waste Characteristics,
Treatment Methods, Biological Effects and Their Applications to Canadian Regions," prepared for
Environmental Protection Services, April 1983. (Offshore Rulemaking Record Volume 110)
13. U.S. EPA, "Report to Congress, Management of Wastes from the Exploration, Development and
Production of Crude Oil, Natural Gas, and Geothermal Energy, Volume 1, EPA/530-SW-88-002,
December 1987. (Offshore Rulemaking Record Volume 119)
IX-53
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14. Walk, Haydel and Associates, Industrial Process Profiles to Support PMN Review: Oil Field
Chemicals, prepared for EPA, undated but received by EPA on June 24, 1983. (Offshore
Rulemaking Record Volume 26)
15. SAIC, "Summary of Data Relating to Miscellaneous and Minor Discharges from Offshore Oil and
Gas Structures," prepared for Industrial Technology Division, U.S. Environmental Protection
Agency, February 1991. (Offshore Rulemaking Record Volume 118)
16. Meyer, Robert L. and Rene Higueras Vargas. "Process of Selecting Completion or Workover
Fluids Requires Series of Tradeoffs." Oil and Gas Journal. January 30, 1984. (Offshore
Rulemaking Record Volume 30)
17. Acosta, Dan, "Special Completion Fluids Outperform Drilling Muds." Oil and Gas Journal. March
2,1981. (Offshore Rulemaking Record Volume 25)
18. "World OU's 1994 Guide to Drilling, Completion and Workover Fluids," World Oil. June 1994.
19. Straus, Matthew A., Director, Waste Management Division, EPA Office of Solid Waste,
Memorandum to Thomas P. O'Farrell, Director, Engineering and Analysis Division, EPA Office
of Water, regarding "Use of OSW Oil and Gas Exploration and Production Associated Waste
Sampling and Analytical Data," October 4, 1994.
20. Souders, Steve, EPA Office of Solid Waste, Memorandum to Allison Wiedeman, EPA Office of
Water, regarding "1992 OSW Oil and Gas Exploration and Production Associated Wastes
Sampling - Facility Trip Reports," October 27, 1994.
21. Sunda, J., SAIC, Memorandum to Allison Wiedeman, U.S. EPA regarding "The exclusion of
certain samples from compilation of OSW TWC data," December 1, 1994.
22. Wiedeman, A., U.S. EPA, "Trip Report to Alaska - Cook Inlet and North Slope Oil and Gas
FacUities, August 25-29, 1993" August 31, 1994.
23. Alaska Oil and Gas Association, Technical Fact Sheet No. 93-6, "Miscellaneous Discharges in
Cook Met: What Are They?" August 1993.
24. Johnson, Michael R., Gulf States Environmental Solutions, Inc. and Morris Hoagland,
Cetco/Aquatec, "Proposal for Treatment of Acid Flowbacks for Main Pass 311, OCS-G-4127 Well
No. A-3," presented to Dr. Syed A. Ali, Chevron, U.S.A., September 20, 1995.
25. Miller, A., and Thompson, J. "Elements of Meteorology 2 nd. Edition.," Charles E. Merrill
Publishing Company. Columbus, Ohio, 1975.
26. Sunda, J., SAIC, Communication with WVUE-TV, New Orleans, regarding rainfall data for the
New Orleans area, May 13, 1994.
27. U.S. EPA, "Trip Report to Unocal City, Louisiana, September 8-9, 1993," Freshwater Bayou,
Vermillion Parish, LA, January 25,1994.
28. Sunda, J., SAIC, Memorandum to Allison Wiedeman, U.S. EPA, concerning the estimation of
deck drainage volumes generated by land-based drilling operations, December 15, 1994.
K-54
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29. U.S. EPA, "Sampling Trip Report to ARCO Oil and Gas Drill Site, Black Bayou Field, Sabine
Wildlife Refuge, Lake Charles, Louisiana, July 21 & 22, 1993," October 21, 1994.
30. Britton, S., Louisiana Office of State Climatology, Louisiana State University. Facsimile to J.
Sunda regarding daily precipitation data for New Orleans, Lake Charles, and Galveston for 1993
and 1994. October 18, 1994.
31. U.S. EPA. "Sampling Trip Report to Gap Energy Drill Site, Holmwood, Louisiana, June 16 &
17, 1993." June 8, 1994.
32. Burns and Roe Industrial Services Corp., "Review of USEPA Region VI Discharge Monitoring
Report, Offshore Oil and Gas Industry," Draft September 1984.
33. ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the THUMS Long Beach Company Agent for the Field Contractor Long Beach Unit -
Island Grissom City of Long Beach - Operator," Draft, prepared for Industrial Technology
Division, U.S. Environmental Protection Agency, March 1990. (Offshore Rulemaking Record
Volume 113)
34. ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the Shell Western E&P, Inc. - Beta Complex," Draft, prepared for Industrial Technology
Division, U.S. Environmental Protection Agency, March 1990. (Offshore Rulemaking Record
Volume 114)
35. ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the Conoco, Inc. - Maljamar Oil Field," Draft, prepared for Industrial Technology
Division, U.S. Environmental Protection Agency, January 1990. {Offshore Rulemaking Record
Volume 115)
36. Envirosphere Co., Cook Inlet Discharge Monitoring Study: Deck Drainage. (Discharge 003), 10
April 1987 to 10 April 1988, prepared for the U.S. EPA Region X. No date. (Offshore
Rulemaking Record Volume 117)
37. Erickson, M., SAIC, "Oil and Gas Exploration and Production Wastes Handling Methods in
Coastal Alaska," January 6, 1995.
38. SAIC, Coastal Oil and Gas Production Sampling Summary Report. April 30, 1993.
39. Hoppy, Brian K., SAIC, telephone correspondence with Fred Duthweiler, UNOCAL, 12 June
1992 concerning deck drainage treatment practices in Cook Inlet, AK. June 12, 1992. (Offshore
Rulemaking Record Volume 174)
40. U.S. EPA, "Development Document for Effluent Limitations Guidelines and Standards for the
Coastal Subcategory of the Oil and Gas Extraction Point Source Category," EPA 821-R-95-009,
February 1995.
41. Longwell, H.J. and Akers, T.J., Exxon Co., U.S.A., "Economic Environmental Management of
Drilling Operations," prepared for presentation at the 1992IADC/SPE Drilling Conference held
in New Orleans, Louisiana, February 18-21, 1992.
IX-55
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42. ERT, Exploration and Production Industry Associated Wastes Report, prepared for API, Document
No. 0300-004-008, May 1988. (Offshore Rulemaking Record Volume 158)
43. Stephenson, Dr. M., "Produced Sand: A Presentation for U.S. Environmental Protection Agency."
June 29, 1989. (Offshore Rulemaking Record Volume 154)
44. University of Tulsa, Chemical Engineering Department, "Effluent Limitations for Onshore and
Offshore Oil and Gas Facilities - A Literature Survey," prepared for U.S. EPA Division of Oil and
Special Materials Control. May 1974. (Offshore Rulemaking Record Volume 22)
45. OOC, Offshore Operators Committee. "Responsee to EPA Request for Additional Information,"
letter from J.F. Branch, Chairman to Ronald P. Jordan, U.S. EPA Office of Water. August 30,
1991. (Offshore Rulemaking Record Volume 155)
46. Parker, M., Exxon, New Orleans, personal communication with Joe Dawley, SAIC, regarding
produced sand generation volumes and washing costs. September 16,1992. (Offshore Rulemaking
Record Volume 174)
47. EPA, Trip Report to Houma Saltwater in Louisiana. March 12, 1992. May 29, 1992.
48, Sunda, J., Telephone correspondence with Dave LeBlanc, Texaco, regarding discharge of
produced sand. March 24, 1994.
49. Erickson, M., Telephone Correspondence with Lori Litzen, Shell Western E&P, regarding current
practices for produced sand disposal. June 6, 1994.
50. Erickson, M., Telephone Correspondence with Dan Hanchera, Marathon Oil, regarding current
practices for produced sand disposal. June 6, 1994.
51. SAIC, Statistical Analysis of Effluent from Coastal Oil and Gas Extraction Facilities. Final Report.
September 30, 1994.
52. U.S. EPA, Trip Report: Exxon Corporation, Clam Lake, Texas. September 15, 1993.
53. Vallejo, R. J., Shell Offshore Inc. Letter to D.J. Bourgeois, Minerals Management Service.
"Produced Sand Discharge Monitoring Study Interim Data Submittal." June 11, 1991. (Offshore
Rulemaking Record Volume 147)
54. Overgard, Ola, READ Process Engineering, A/S, letter to Allison Wiedeman regarding the
proposed rule for effluent limitation guideline, 40 CFR Part 435 (FRI-5149-7) RIN 2040-AB72
with attachments, June 20, 1995.
55. Favret, Uncas, Engineering Specialties, Inc., letter to Allison Wiedeman regarding comments on
produced sand washing, with attachments, June 22, 1995.
56. American Petroleum Institute. "Comments of the American Petroleum Institute in Response to
U.S. Environmental Protection Agency's Proposed Effluent Limitations Guidelines and New
Source Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point
Source Category, 56 Federal Register 10664-10715 (March 13, 1991)." May 13, 1991. (Offshore
Rulemaking Record Volume 142)
IX-56
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57. Frankenberg, W.G., and J.H. Allred. "Design, Installation, and Operation of a Large Offshore
Production Complex," 1st Annual Offshore Technology Conference, (Houston, 8/18-21/69).
Reprint No. OTC 1082, pp. H 117 - D 122, 1969 (V.2).
58. Garcia, J.A., "A System for the Removal and Disposal of Produced Sand." 47th Annual SPE of
AIME Fall Meeting (San Antonio, 10/8-11/72) Reprint No. SPE-4015, 1972.
59. Mors, T,A,, RJ. Rolan, and S.B. Roth, Interim Final Assessment of Environmental Fate and
Effects of Discharges from Offshore Oil and Gas Operations, prepared by Dalton, Dalton,
Newport, Inc., for U.S. EPA, 1982. (Offshore Rulemaking Record Volume 32)
60. U.S. EPA, Development Document for Interim Final Effluent Limitations Guidelines and New
Performance Standards for me Oil and Gas Extraction Point Source Category, EPA 440/1-76/055-
a, September 1976.
61. EPA, Development Document for Interim Final Effluent Limitations Guidelines and New Source
Performance Standards for the Oil and Gas Extraction Point Source Category (Proposed), EPA
440/1-85/055, My 1985.
62. Envirosphere Company, Summary Report Cook Inlet Discharge Monitoring Study: Excess
Cement Slurry and Mud, Cuttings and Cement at the Sea Floor (discharge Numbers 013 & 014)
10 April 1987 - 10 April 1988, Specific Drilling Events Monitored 4-28-88 through 9-12-89
(prepared for U.S. EPA Region X), no date. (Offshore Rulemaking Record Volume 117)
63. OSS, Attachment to memorandum from Division Operations Manager Coastal Division, OSS 2280
to Production Superintendents Coastal Division. "Cleaning Oily Tank Solids." September 17,
1990.
K-57
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CHAPTER X
COST AND POLLUTANT REMOVAL DETERMINATION OF
DRILLING FLUIDS AND DRILL CUTTINGS
1.0 INTRODUCTION
This section presents incremental costs and pollutant removals for the regulatory options considered
for control of drilling fluids, drill cuttings and dewatering fluids. Incremental compliance costs beyond
current industry practices and NPDES permit requirements were developed for each control option for
Cook Inlet, Alaska only. Compliance costs were not developed for the other coastal regions where oil and
gas activity exists or is expected, because, as is discussed in earlier chapters of this document, discharges
of drilling fluids and drill cuttings do not occur in these areas.a
BAT and BCT limitations for dewatering effluent are applicable prospectively. The BCT and BAT
limitations for dewatering effluent are applicable to discharges of dewatering effluent from those reserve
pits which receive drilling fluids and/or drill cuttings after the effective date of the coastal guidelines. BAT
and BCT limitations in this rule are not applicable to discharges of dewatering effluent from reserve pits
which as of the effective date of this rule no longer receive drilling fluids and drill cuttings. Limitations
on such discharges shall be determined by the NPDES permit issuing authority.
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS
Two disposal options were considered for control and treatment of drilling fluids, drill cuttings,
and dewatering effluent for this rule. These options are:
Option 1: Zero discharge for all areas except Cook Inlet, where discharge limitations require
toxicity of no less than 30,000 ppm hi the suspended particulate phase (SPP), no discharge of
free oil and diesel oil, and no more than 1 mg/1 mercury and 3 mg/1 cadmium hi the stock barite
a Based on an agreement with the Alaska Department of Environmental Conservation (ADEC), operators in Alaska's
North Slope are allowed to clean and reuse drill cuttings as gravel as long as the cuttings meet certain criteria. The
operators developed the "Drill Cuttings Reclamation Program" whose goals are to minimize the volume of larger
cuttings requiring grinding and injection and to reduce the need for gravel mining. Details regarding this program are
provided in the rulemaking record.1
X-l
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(these limitations are reflective of current practice in Cook Inlet and are similar to the offshore
limitations).
* Option 2: Zero discharge for all areas.
Costs for these options are applicable only to Cook Inlet operators since zero discharge represents
current practice in all other coastal areas. Since Option 1 is reflective of current practice hi Cook Inlet,
no costs or pollutant removals are attributed to this option. (See Section 2.1 for a discussion of current
practice.) Thus, only costs and poEutant removals that are incremental to current practice were determined
for Option 2.
Options 1 and 2 apply to the drill cuttings as well as to drilling fluids since drilling fluid adheres
to cuttings and is discharged along with the drill cuttings.2 The same pollutants found in drilling fluids
are thus found on the wet drill cuttings. Section discusses the constituents in drilling wastes as part of the
pollutant removal analysis.
One option considered at proposal would have retained the limitation of Option 1 above, but
required a more stringent toxicity limit in the range of 100,000 ppm (SPP) to 1 million ppm (SPP). At
proposal, EPA based the more stringent toxicity limitations, in part, on the volume of drilling wastes that
could be injected or disposed of onshore without interfering with ongoing drilling operations. The more
stringent toxicity limit would have been based on (1) the volume of drilling wastes that could be subjected
to zero discharge without interfering with ongoing drilling operations and (2) a specified level of toxicity
selected such mat no more than this volume of waste, determined in the previous step, would exceed the
specified level of toxicity. However, as pointed out in comments on the proposal and confirmed with
further investigation, there are a number of problems with the database making it insufficient for
establishing a more stringent toxicity limitation. Many of the records in the database do not have either
a waste volume identified or indicate whether the drilling fluids were discharged. Where waste volumes
are reported, the methods used to determine these volumes are not consistent and they are not documented.
It is also unclear whether the volumes and fluid systems reported tor any given well represent a complete
record of the drilling activity associated with the well. For these reasons, EPA rejected the option of
developing a more stringent toxicity limitation for the final rule.
Another wastestream resulting from drilling activities is the wastewater derived from dewatering
drill cuttings, called dewatering effluent. This wastestream is typically created only where drill cuttings
and drilling fluid may not be discharged, and there is incentive to reduce the volume of these wastes prior
X-2
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to disposal. Also, cuttings must be dewatered to the extent landfills limit the amount of liquid in the solids
they accept for disposal. Depending on the availability of fresh water, dewatering effluent may also be
recycled within the active drilling fluid system, thus never becoming a separate wastestream.
In the Gulf Coast region where discharges of drill cuttings and drilling fluids are prohibited, the
EPA Region 6 general permits for drilling operations for Texas and Louisiana (58 PR 49126, September
21, 1993) include limitations for the discharge of dewatering effluent. However, the 1993 Coastal Oil and
Gas Questionnaire results showed that few operators discharge dewatering effluent as a separate
wastestream.3 Additionally, contacts with industry indicate that the volume of dewatering effluent from
reserve pits is small and growing smaller since the use of pits is phasing out due to state permit conditions,
environmental or landowner concerns, and the expanding use of closed-loop systems in the Gulf Coast
region. EPA site visits to drilling operations where closed-loop solids control systems were in place
showed that none of the dewatering effluent was discharged.4'5-6 Instead, it was either recycled or sent
with other drilling wastes to commercial disposal. Operators at theses facilities explained that it is less
expensive to send this waste stream along with drilling fluids and drill cuttings for onshore disposal rather
than to treat for discharge. Therefore, EPA has concluded that any costs attributable to zero discharge of
dewatering effluent are negligible in comparison to the costs of treating and discharging this waste.
In Cook Inlet where drill cuttings may be discharged under current NPDES requirements,7 there
is no incentive to dewater the cuttings and create a separate dewatering effluent wastestream. The
compliance costs and pollutant removals presented in this document are based on the total volume of drill
cuttings (including the drilling fluid adhering to the cuttings) and drilling fluids generated by Cook Inlet
operators. Since dewatering effluent is derived from separating the solids in the drill cuttings wastestream
from the liquid (drilling fluid) adhering to the cuttings, and EPA's compliance cost estimates for Cook Inlet
are based on the total volume of drilling wastes generated, EPA's analyses include any costs that may be
attributable to dewatering effluent in Cook Inlet.
The purpose of the toxicity limitation in Option 1 is to encourage the use of water-based or other
low toxicity drilling fluids and the use of low-toxicity drilling fluid additives. The toxicity limitation hi
Option 1 (30,000 ppm) represents current industry practice.8 The toxicity limitation applies to any periodic
blowdown of drilling fluid as well as to bulk discharges of drilling fluid systems and cuttings. The term
"drilling fluid systems" refers to particular types of drilling fluids used during the drilling of a single well.
As an example, the drilling of a particular well may use a spud mud for the first 200 feet, a seawater gel
X-3
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mud to a depth of 1,000 feet, a lightly treated lignosulfonate mud to 5,000 feet, and finally a freshwater
lignosulfonate mud system to a bottom hole depth of 15,000 feet. Typically, bulk discharges of spent
drilling fluids occur when such systems are changed during the drilling of a well or at the completion of
a well.
For the purpose of self monitoring and reporting requirements in NPDES permits, it is intended
that only samples of the spent drilling fluid system discharges be analyzed in accordance with the proposed
bioassay method. These bulk discharges are the highest volume mud discharges and will contain all the
specialty additives included in each mud system. Thus, spent drilling fluid system discharges are the most
appropriate discharges for which compliance with the toxicity limitation should be demonstrated. In the
above example well, four such determinations at each of the depth intervals (i.e., 200, 1,000, 5,000, and
15,000 feet) would be necessary.
For determining the toxicity of the bulk discharge of mud used at maximum well depth, samples
may be obtained at any time after 80 percent of actual well footage (not total vertical depth) has been
drilled and up to and including the time of discharge. This would allow time for a sample to be collected
and analyzed by bioassay and for the operator to evaluate the bioassay results so that the operator will have
adequate time to plan for the final disposition of the spent drilling fluid system. For example, if the
bioassay test is failed, the operator could then anticipate and plan for either land disposal or injection of
the spent drilling fluid system to comply with the effluent limitations. However, the operator is not
precluded from discharging a spent mud system prior to receiving analytical results, although the operation
would be subject to compliance with the effluent limitations regardless of when self monitoring analyses
are performed. The prohibition on discharges of free oil and diesel oil would apply to all discharges of
drilling fluid and cuttings at any time. These requirements described above represent existing NPDES
permit requirements.
For Option 1, diesel oil and free oil would serve as "indicators" of toxic pollutants, and thus these
discharges would be prohibited by this rule. The discharge of diesel oil, either as a component in an oil-
based drilling fluid or as an additive to a water-based (or synthetic-based or enhanced mineral oil) drilling
fluid, would be prohibited under these limitations. Diesel oil would be regulated as a toxic pollutant
because it contains such toxic organic pollutants as benzene, toluene, ethylbenzene, naphthalene, and
phenanthrene. The method of compliance with this prohibition is to:
X-4
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• use mineral oil instead of diesel oil for lubricity and spotting purposes;
• transport to shore for recovery of the oil, reconditioning of the drilling fluid for reuse, and
land disposal of the drill cuttings; or
• grind and inject the drilling wastes.
EPA believes that in most cases substitution of mineral oil or other lubricity additive or the use of newer
synthetic material based fluids such as those comprised of linear or poly(alpha)olefins, vegetable esters,
or polyesters will be the method of compliance with the diesel oil discharge prohibition. Mineral oil is a
less toxic alternative to diesel oil and is available to serve the same operational requirements. Low toxicity
mineral oils and other drilling fluid systems, such as linear or polyolefins, vegetable oil and other synthetic
hydrocarbon-based fluids, are available as substitutes for diesel oil and continue to be developed for use
in drilling systems. Free oil is being used as an "indicator" pollutant for control of priority pollutants,
including benzene, toluene, ethylbenzene, and naphthalene.
Cadmium and mercury would be regulated at a level of 3 and 1 mg/kg, respectively, hi the stock
barite. This limit pertains to the barite used hi the drilling fluid compositions and is not an effluent limit
measured at the point of discharge. These two toxic metals would be regulated to control the metals
content of the barite component of any drilling fluid discharges. Control of other toxic pollutant metals
occurs because cleaner barite that meets the mercury and cadmium limits has been shown 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, and zinc, and the concentration of cadmium
with the concentration of arsenic, boron, calcium, sodium, tin, titanium, and zinc (see Section VI.2.4).
Compliance with this requirement would involve use of barite from sources that either do not contain these
metals or contain the metals at levels below the limitation.
Option 2 would prohibit the discharge of drilling fluids and cuttings from all coastal oil and gas
drilling operations. This option utilizes grinding and injection and onshore disposal as a basis for
complying with zero discharge of drilling fluids and cuttings. The technology option alternatives for Cook
Inlet have been developed taking into consideration that Cook Inlet operations are unique to the industry
due to a combination of climate, transportation logistics, and structural and space limitations (see
Chapter XIV).
X-5
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Four different scenarios were investigated as possible technology bases for achieving zero
discharge under Option 2. These scenarios included:
• Landfill without CLS: Landfill disposal without closed-loop solids control technology (CLS).
• Landfill with CLS: Waste minimization using closed-loop solids control followed by disposal
via transporting wastes to a landfill.
• Injection without CLS: Grinding followed by onsite injection.
• Injection with CLS: Waste minimization using closed-loop solids control technology followed
by grinding and injection. This alternative is presented for comparison with the injection-
without-solids control alternative.
Table X-l presents the total coastal Cook Inlet compliance costs and pollutant removals calculated
for each option. The total costs are based on the drilling activity plans or schedules as provided by the
industry and cover a seven-year period from 1996 through 2002. The pollutant removals are based on
typical volumes and characteristics of drilling wastes. The derivation of these costs and removals are
described in detail in the remainder of this chapter.
TABLE X-l
INCREMENTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS FOR
DRILLING FLUIDS AND DRILL CUTTINGS BAT OPTIONS3
\ *• ''
BAT Option 7
Option 1: Zero discharge except
Cook Inlet = no free oil or
diesel, and limits of 30,000
ppm SPP toxicity, 1 mg/1
Hg and 3 mg/1 Cd
Option 2: Zero discharge all
' ^/ ^Tbfea'Costs, ,, '
>-, , " " (&&$ , V
$0
Landfill Without CLS" $66,167,388
Landfill With CLS $57,337,369
Injection Without CLS $35,625,501
Injection With CLS $47,307,372
' < ' ••
Pollutant Removals ,,,„;.<,„
'" ; (fibs) * ,
Conventional
Priority Organics
Priority Metals
Non-Conventionals
Total
Conventionals
Priority Organics
Priority Metals
Others
Total
0
0
0
0
0
168,624,108
35
30,399
8,361,216
177,015,758
1 Costs and pollutant removals are totals for seven years following promulgation (1996-2002), based on drilling activity
schedules as provided by the industry.
b CLS = Closed-loop solids control equipment.
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2.1 CURRENT PRACTICE
BPT effluent limitations for coastal drilling fluids and cuttings prohibit the discharge of free oil
(using the visual sheen test). However, because of either EPA general permits, state requirements, or
operational preference, no discharges of drilling fluids, drill cuttings, or dewatering effluent are occurring
in the North Slope, the Gulf coast states, or California. The only coastal operators discharging drilling
fluids and cuttings are located hi Cook Inlet. In Cook Inlet, neither diesel nor mineral-oil-based drilling
fluids or resultant cuttings may be discharged to surface waters because they have been shown to cause a
visible sheen upon the receiving waters. Compliance with the BPT limitations may be achieved either by
product substitution (substituting a water-based or synthetic material-based fluid for an oil-based fluid),
recycle and/or reuse of the drilling fluid, grinding and injection, or by onshore disposal of the drilling
fluids and cuttings at an approved facility.
NPDES permits issued by EPA for Cook Inlet drilling operations have also included BAT
limitations on "best professional judgement" (BPT). The permit requirements allow discharges of drilling
fluids and drill cuttings provided certain limitations are met including a prohibition on the discharges of
free oil, diesel oil, and oil-based drilling fluids, as well as limitations on mercury, cadmium, and oil content
(see Chapter HI for a summary of the permits). The toxicity of drilling fluids is controlled by
"preapproval" requirements that limit drilling fluid constituents to "generic" drilling fluids and authorized
additives only. Operators may employ any number of the following waste management practices to meet
those permit limitations:
• Product substitution - to meet prohibitions on free oil and diesel oil discharges, as well as the
toxicity requirements and clean barite limitations,
• Onshore treatment and/or disposal of drilling fluids and drill cuttings that do not meet the permit
requirements,
• Waste minimization - enhanced solids control to reduce the overall volume of drilling fluids and
drill cuttings,
• Conservation and recycling/reuse of drilling fluids, and
• Grinding and injection.
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3.0 OVERVIEW OF METHODOLOGY
A set of detailed spreadsheets was developed for predicting industry-wide compliance costs and
pollutant removals for each regulatory option considered (see Appendix X-l). All costs are for BAT or
BCT, and no costs are attributed to NSPS since there are no plans for construction of any new development
wells from new platforms in Cook Inlet. (All well drilling will be from existing platforms and is therefore
defined as existing sources.) la characterizing the coastal Alaska drilling industry, EPA used the drilling
activity plans or schedules as provided by the industry which actually covered only a 7-year period, from
1996 through 2002, because no information on drilling beyond this time was available.9 The typical
volumes of drilling fluids and cuttings generated during a drilling event were estimated based on
information provided by the industry in the 1993 Coastal Oil and Gas Questionnaire (see Worksheet 1 in
Appendix X-l). The disposal costs were estimated based on the cost and operation information provided
by the industry (see Worksheets 2 to 4A in Appendix X-l).
EPA also considered the logistical difficulties of transporting drilling wastes in Cook Inlet as part
of its costing analysis of the options. To accomplish zero discharge via landfill, operators would have to
transport drill wastes to a staging location on the eastern side of Cook Inlet by supply boat. During the
summer months, the one operator with access to an existing Cook Inlet landfill would then transfer the
wastes to barges for transport to the landfill which is located on the west side of the Inlet. During ice
conditions, the wastes would have to remain stored at the transfer station until they could be transported
by barge. Other operators would transport wastes via truck from the east side of Cook Inlet to a landfill
located in Arlington, Oregon. Details of waste transport information and data are discussed below.
Details of the methodology used to develop the compliance costs and pollutant removals presented
in Table X-l are discussed in Sections 4.0 and 5.0, respectively. Although the zero discharge scenarios
are not considered to be feasible for all facilities in Cook Inlet, the analyses of costs and pollutant
reductions are included here to provide an indication of the magnitude of costs that would be faced by a
given facility. While not considered feasible throughout Cook Inlet, it is conceivable that site-specific data
may be developed that would indicate that zero discharge may be available at some locations. In such
instances, it is possible that water quality considerations may warrant imposition of zero discharge
limitations on a site-specific basis where feasible.
X-8
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4.0 COMPLIANCE COST METHODOLOGY
The following sections detail the methodology used to develop compliance cost estimates for the
four Option 2 (zero discharge) scenarios. The compliance costs for these four scenarios are presented in
Table X-2. Option 1 is reflective of current industry practice and would not incur incremental compliance
costs.
4.1 GENERAL ASSUMPTIONS AND INPUT DATA
All four zero discharge cost scenarios are based on the total volume of drilling waste (including
drilling fluids and drill cuttings) estimated for currently planned drilling activity in Cook Inlet. This total
volume was calculated based on the numbers of new wells and recompletions planned by the Cook Inlet
operators, and the estimated volume of waste generated by a "model" Cook Inlet drilling project. The
following sections discuss the bases of these estimates. Additional sections discuss the means of achieving
zero discharge, namely transportation and landfilling, grinding and injection.
4.1.1 Drilling Activity
The compliance cost analysis is based on the most current drilling plans available from the Cook
Inlet operators. The total volume of fluids and cuttings generated was estimated from the projection of the
number of wells to be drilled by the industry and the average volume of waste generated from each well.
Table X-3 presents the numbers of platforms, new wells and recompletions included for each operator
based on information provided by industry. EPA estimates that the total amount of drilling fluids and
cuttings annually generated from the drilling activities listed in Table X-3 is 89,438 barrels per year, or
626,070 barrels over the next seven years.
One operator that was included in the proposed analysis has no further plans to drill in Cook Inlet
and is therefore not included in the analysis presented in this document. In the proposal analysis, this
operator was designated as Operator C. In the current analysis, Operator C represents a different
company.
4.1.2 Model Well Characteristics and Costs
The drilling waste compliance cost analysis was based on the total estimated volume of drilling
fluids and drill cuttings generated from a typical or "model" Cook Inlet'well. Various characteristics of
X-9
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TABLE X-2
X
S
DRILLING WASTE COMPLIANCE COSTS FOR
FOUR ZERO-DISCHARGE SCENARIOS'
(1995 $)
' Waste Management
- - Scenario
Landfill Without CLSb
Landfill With CLS
Injection Without CLS
Injection With CLS
TotalBHlling Waste
Volume Disposed '
- ^ (bbfe)_ ,
626,070
431,988
626,070
431,988
: >'€;:":
Compliance <•
' Cost -
$66,167,388
$57,337,369
$35,625,501
$47,307,372
y
; 'Cost per '-4
-^jBami;,/
/of Waste '
'"'PfsposwL*
$106
$133
$57
$110
f ' f
f *,:'
Cost per
'-"ftatforirt-'v
1 ^ * SA s •.
$6,015,217
$5,212,488
$3,238,682
$4,300,670
, % / •-
_ .'.Clbst'per
Dl-illillg Event
$1,084,711
$939,957
$584,025
$775,531
Cost per-
-New Well
$1,501,859
$1,301,436
$808,623
' $1,073,777
- - - ,-*
' % X *••*
- Cost'peti,
Reconlpletion
$229,558
$198,924
$123,598
$164,126
1 Costs in this table are from Worksheets 2, 3, 4, and 4A in Appendix X-l. Total costs represent costs incurred over the seven-year period following
promulgation, from 1996 through 2002.
' CLS = Closed-loop solids control equipment.
-------
TABLE X-3
SCHEDULE OF DRILLING ACTIVITY BY OPERATOR IN COOK INLET, ALASKA
FOR SEVEN YEARS AFTER PROMULGATION
„ » ,
", ,,, , Operator
A
B
C
TOTALS
: •. i, " <•? v. < <-% s\ •*
Number of Platforms
VHth Planned Drilling
- ' " Pfflgnati' "' '
1
9
1
11
ISUlUUer <>1 ItleW Wells
to be Drilled
3
28
10
41
Number' of Existing
Wellsrtosbe, ,' "
' JReeompleted ,,,
1
19
0
20
Note: The identity of the operators is confidential. Sources of this information are listed hi a memorandum
filed as confidential business information.9
the model well, such as depth, waste volumes, and cost of drilling, were incorporated into the four Option
2 waste management scenarios discussed in Section 2.0.
The model Cook Inlet well was developed from industry data submitted to EPA in the 1993
Questionnaire for Coastal Oil and Gas Operators.3 Worksheet 1 in Appendix X-l presents the detailed
calculations involving the model well data, as well as the cost of drilling an injection well based on these
data. All wells considered in this estimation were drilled in three intervals to an average total depth of
11,765 feet. The volume of drilling waste (drilling fluids and drill cuttings) generated from an average
11,765-foot well was estimated to be 14,354 barrels with an average cuttings content of 19 percent by
volume. This volume compares well with the 13,500 bbl per well provided by industry.9 Since no
information was available on the volumes of drilling waste generated during recompletion of existing wells,
EPA assumed that the volume of drilling fluids and drill cuttings generated during an average recompletion
is equal to the average volume of wastes generated during the last drilling interval of a new well. This
volume was estimated to be 2,194 barrels and was assumed to contain 19 percent cuttings by volume. This
volume is a conservative estimate when compared to the volumes estimated for recompletions in the Gulf
of Mexico: 1,803 barrels of drilling fluid and 72 barrels of drill cuttings per job.10
The estimated drilling waste generation rate and the percent cuttings were used to estimate the total
volumes of waste drilling fluids and drill cuttings generated for each operator. The estimated total
X-ll
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industry-wide volume of waste drilling fluids and drill cuttings generated is the sum of all volumes
estimated for each, operator. An industry source stated that under current NPDES permit requirements,
file volume of non-complying drilling waste is generally less than one percent (1 %) of the total generated
waste volume.11 Therefore, EPA estimates that one percent of all generated drilling waste in Cook Inlet
is currently not meeting the existing permit requirements and limitations in this region and therefore cannot
be discharged." Since all disposal costs are directly proportional to the amount of drilling fluids and drill
cuttings that are currently generated, all estimated total disposal volumes were reduced by one percent to
reflect current practice. Thus, the amount of drilling fluids and drill cuttings discharged is estimated to
be one percent less than the amount generated.
Hence, for the two compliance cost scenarios without closed-loop solids control equipment, the
waste volume for each new well drilled is 99 percent of the total average 14,354 bbls of waste calculated
for the model well, or 14,210 bbls. The waste volume per recompletion comprises 99 percent of the 2,194
bbls generated in the third interval (from 9,901 to 11,765 feet) of the model well, or 2,172 bbls.
For the two scenarios with closed-loop solids control equipment, the per-well waste volume was
reduced 31 percent in addition to the one percent reduction due to current practice. The additional volume
reduction is attributed to the application of high-efficiency closed-loop solids control. A detailed
description of the closed-loop systems is presented in Chapter VII of this document. The per-well waste
volumes used in these scenarios are 9,805 bbls and 1,499 bbls for new wells and recompletions,
respectively.
In the scenarios involving injection of drilling wastes, the cost of drilling an injection well was
derived from 1993 Questionnaire data, as shown in Worksheet 1 in Appendix X-l. The $1,313,897 (1995
dollars) cost of this injection well was adjusted from 1992 dollars to 1995 dollars using the Engineering
News Record Construction Cost Index (ENR-CCI) ratio of 5471/4985 (1.0975).12 This cost appears in
Worksheets 4 and 4A, as described in Section 4.3.3.
4,1.3 Transportation and Onshore Disposal Costs of Drilling Wastes
For Cook Met operators, on-land disposal sites in Alaska are available only to Operator B. This
operator owns an oil and gas landfill disposal site on the west side of the Met. EPA has determined that
there is sufficient on-land disposal capacity to accept all of the drilling fluids and cuttings generated by this
operator at this disposal facility.13 EPA investigated the logistical difficulties of storing and transporting
X-12
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drilling wastes in Cook Inlet due to the extensive tidal fluctuations, strong currents, and ice formation
during winter months. Based on operational difficulties in conjunction with the long distances that the
wastes must be hauled by most operators to disposal sites outside of Cook Inlet, EPA found that zero
discharge was not technologically available to Cook Inlet operators. EPA nevertheless did an analysis of
the costs of zero discharge assuming that zero discharge could be attained in order to assess the economic
impacts of zero discharge. EPA has taken into consideration supplementary costs incurred by additional
winter transportation and storage of drilling wastes in its cost evaluation of this option. However, the
feasibility of this option throughout Cook Inlet is questionable.
EPA costed the zero discharge option assuming that all operators would use supply boats to
transport generated drilling fluid and drill cuttings to location on the east side of Cook Inlet. Operator B
would transfer the drilling wastes into barges during the summer months, or temporarily store the wastes
at an east-side facility during winter months when barge traffic is not possible due to sea ice conditions.
For example, the upper Cook Inlet would be covered by solid ice in winter if it were not for large tidal
ranges (frequently in excess of 30 feet). Because these large tidal ranges produce very strong currents,
moving broken ice is a common occurrence in Cook Inlet.14 Ice typically covers upper Cook Inlet for
about four months during the year and portions of the lower Cook Inlet for about three months during the
year.14 Therefore, during ice conditions, only V-hulled vessels can be used to transport drilling wastes.
Because of tidal fluctuations in the summer and ice conditions in winter, EPA costed this option assuming
V-hulled supply vessels rather than barges would be used for transporting supplies to and wastes from
platforms.
EPA costed zero discharge by assuming barges would be used by Operator B to transport wastes
to the west side of Cook Inlet because during low tide the water depth prohibits access by V-hulled
vessels.13 EPA further assumed that since no docking facility is available on the west side of the Inlet, the
offloading of barges would have to be done by building earthen ramps onto the beach to provide access
to the barge. Barges would then have to be maneuvered to the earthen ramps during the high tide. When
the tide recedes, the barges would be beached near the ramps and unloading resumes.
For all other operators, EPA costed this option assuming that drilling wastes would be transported
from the east side of Cook Inlet by truck to a landfill in Arlington, Oregon. There is also capacity for the
waste volumes generated over the seven year period at a disposal site in Idaho. The Idaho facility
information was used in the proposal analysis and was based on responses to the 1993 Coastal Oil and Gas
X-13
-------
Questionnaire. However, exists for the final rule were based on the transportation and disposal costs at the
Oregon facility.
4.1.4 Grinding and Injection
To meet the zero discharge requirements of Option 2, Cook Inlet operators could elect to grind and
inject the drilling waste if suitable geology were found to be available. Disposal of drilling wastes by
injection requires: (1) installation of processing equipment to grind the solids into a slurry liquid with fine
particles; (2) installation of injection equipment for delivery of the processed wastes into a subsurface
formation; and (3) installation of injection wells to allow injection into suitable subsurface formations.
Grinding and injection is a relatively contemporary technology that has been successfully
demonstrated on the North Slope, and has been used to a limited extent on the Gulf Coast. While it was
evaluated as a disposal scenario, grinding and injection is not used in the cost basis for Cook Inlet because
geology amenable to grinding and injection does not appear to be available throughout Cook Inlet and
transportation of such wastes to where it could be reinjected is further not available due to operational
difficulties faced by operators. Nonetheless, EPA did calculate the compliance costs for such an option
with the following assumptions. EPA assumed that all platforms in question require retrofitting for
installation of processing and injection equipment. According to industry, operators with multiple
platforms do not need to purchase or lease injection equipment for each platform since such equipment
could be shared between platforms.16 Processing and injection equipment for use on platforms can be
constructed in package units in such a way that the entire unit could be transported and placed on a
platform when needed, provided that adequate space is available on that platform and that the formations
are suitable for accepting the waste.
Operators in Cook Inlet have the option of either purchasing or leasing the processing and injection
equipment. EPA evaluated both the costs of leasing and purchasing of this equipment for the purpose of
compliance cost calculations. According to industry sources, the 1992 unit cost of purchasing processing
and injection equipment was approximately $1,000,000 and the unit rental cost of the same equipment was
approximately $1,500 per day.13 The total equipment purchase and rental costs for each operator were
indexed to 1995 dollars and presented in Worksheets 4 and 4A in Appendix X-l. The calculated total
purchasing costs of grinding and injection equipment were greater than total rental costs for all operators
included in this compliance cost analysis.
X-14
-------
Injection of processed drilling waste also requires access to a suitable subsurface formation. EPA
based injection costs on drilling injection wells to a depth of 4,000 feet.
4.2 OPTION 2: ZERO DISCHARGE
The methodologies used to develop.the four zero-discharge cost scenarios are described in the
following sections. Worksheets 2, 3, 4 and 4A in Appendix X-l present the detailed cost calculations.
4.2.1 Landfill Without Closed-Loop Solids Control
Worksheet 2, located in Appendix X-l, presents the detailed calculation of the compliance cost for
achieving zero discharge via landfill without the use of incremental closed-loop solids control equipment.
An onshore disposal cost of $103 per barrel was calculated for Operator B. This unit cost takes
into account the costs of all transportation, purchasing waste containers, temporary storage, and landfill
gate fees. This unit cost was calculated based on the following assumptions:
• Eight-barrel fluid/cuttings boxes (4 feet x 4 feet x 4 feet) are used to store the drilling waste
prior to landfill disposal, with a/purchase cost of $125 per box.13-15
• Supply boats are used to transport the drilling waste from the platforms to a temporary onshore
storage facility on the east side of the inlet at the rate of $5,000 per day per boat, including
loading and unloading costs.9
• Supply boats currently make two regularly scheduled trips per week to each platform.9
• Supply boats have a capacity of 300 tons on deck (for cuttings boxes) and 170 tons below deck
(for bulk drilling fluids)-17
• Platform capacity for storing waste cuttings is 12 boxes.9
• Transportation for one supply boat load of drilling waste to the east-side temporary storage area
includes: one day for loading boxes onto the supply boat and transporting to the east Cook Inlet
docking area, and one day for unloading boxes and transporting by truck to the temporary
storage area.15
• Trucks that are used to transport drilling waste to the temporary onshore storage area have a
capacity of 12 boxes per load, and cost $300 per load.13
• Barges that are used to transport drilling waste from the east Cook Inlet docking area to the
existing landfill facility on the west side of the inlet have a capacity of 240 boxes, and cost
$6,000 per day.9-18
X-15
-------
Transportation from temporary storage to the west side Cook Inlet landfill includes: one day to
truck the wastes from the storage area to the docking facility and load the barges, one day to
barge the wastes to the west side unloading area, and one day to unload boxes and truck them
to the landfill.15
Additional costs were included to address industry comments regarding specific fees associated
with disposal at the Kustatan landfill, as follows:9
- Platform waste handling cost: $ 6.90/bbl
- Waste stabilization cost: $12.47/bbl
- Landfill usage fee: $45.38/bbl
- Fill cell cost: $ 8.28/bbl
Operators A and C were assigned costs associated with the use of a landfill located in Arlington,
Oregon. The unit landfill cost applied to these operators was $112/bbl, as per the following assumptions:
• Transportation of the drilling wastes includes the use of supply boats from the platform to an
east Cook Met docking facility followed by the use of trucks from the docking facility to
Arlington, Oregon.19
• Supply boats are assumed to have the same capacity, frequency, and cost as described above
(see also Appendix X-2).
• Trucks transporting drilling wastes from the east-side docking facility to Arlington, Oregon have
a 22-ton capacity and cost $1,800 per load.20
• The Arlington, Oregon disposal facility cost is $500 per eight-barrel cuttings box.19
Other assumptions established for Operator B, including the cost of cuttings boxes and platform storage
capacity, are also applied to the costs for Operators A and C. The detailed calculation of the unit landfill
costs for these operators is presented hi Appendix X-2.
4.2.2 Landfill With Closed-Loop Solids Control
The land disposal with the closed-loop systems scenario assumes installation of high efficiency
solids separation units to minimize the volume of drill waste generated. The components of a closed-loop
system considered by EPA include high efficiency shale shakers, mud cleaners, chemically enhanced
centrifugation (CEC), waste storage tanks, and transfer equipment. Installation of closed-loop systems
reduces the overall landfill and transportation costs but will incur additional costs of retrofitting the
platform, purchasing or leasing of high efficiency separation equipment,' and operating the equipment.
X-16
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Installation of closed-loop systems will enable the operator to reuse the same drilling fluid for a
longer period of time and therefore reduce the need to introduce fresh drilling fluid into the system.
However, a platform may not have adequate deck space for installation of additional solids separation
systems and may require retrofitting. The Agency estimated an average retrofitting cost of $270,000 and
assumed that all platforms need retrofitting. This retrofitting cost was estimated based on the need for 450
square feet of additional deck space at the rate of $600 per square foot.16-21
Based on information obtained from Gulf of Mexico industry sources, EPA estimated an average
cost of $2,085 per day for leasing high efficiency solids separation systems.21 The estimated $2,085 per
day costs include all maintenance costs. However, the Agency added an additional cost of $1,098 per day
for any additional operating costs that may be needed in Cook Inlet. The $1,098 per day operating cost
was reported by Cook Inlet industry sources for operation of waste processing and injecting equipment.22
Since a closed-loop system is comparable to a processing and injecting system in terms of labor
requirements, the Agency assumed the unit operating cost determined for operation of injection systems
as the unit operating cost for operation of closed-loop systems. The total equipment and operating costs
of a closed-loop system were calculated from the total number of drilling events for each operator, the
average drilling period estimated for each drilling event, the unit equipment cost, and the unit operating
cost. These costs were adjusted from 1992 dollars to 1995 dollars using ihe ENR-CCI of 5471/4985
(1.0975).12 The same $103 per barrel and $112 per barrel land disposal unit costs specified for Worksheet
2 were also used for mis disposal method.
4.2.3 Subsurface Injection Through Dedicated Wells
Subsurface injection of drilling waste through a dedicated injection well involves the installation
of dedicated injection wells to a suitable underground formation, grinding of the drilling fluid and drill
cuttings solids into a slurry liquid with fine particles, and injection of processed waste into the subsurface
formation.
The total industry-wide disposal cost for this method includes the costs of dedicated injection wells,
platform retrofitting, injection equipment, and injection equipment operation. The unit cost of installing
a 4,000-foot injection well was estimated to be $1,313,897 per well in Worksheet 1. For the zero
discharge option (Option 2), the number of dedicated wells was estimated for each operator based on the
assumption that one injection well is needed for every 4 new drillings23 and one for every 16 recompletions.
The assumption for one injection well for every 16 recompletions was based on ihe approximate ratio of
X-17
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4:1 between the estimated volumes of drilling waste generated from a new well and a recompletion which
was shown hi the 1993 Coastal Oil and Gas Questionnaire data.3
The cost of retrofitting platforms was assumed to be $750,000 per platform based on information
provided by the industry.13 The Agency assumes that all platforms would need retrofitting. Based on
information obtained from industry, it was further assumed that operators with multiple platforms do not
need to install injection equipment at each platform, because injection equipment could be shared as long
as space is available at each platform.13 Based on information provided by industry, it was assumed that
4 injection units would be adequate for Operator B which operates 12 platforms in Cook Inlet. For the
other operators with only one platform, one injection unit was assumed for each platform.
The costs of acquiring injection equipment were estimated for both purchasing and leasing of the
equipment based on $1,097,500 per system for purchasing or $1,537 per day for leasing.13 These costs
were indexed from 1992 dollars to 1995 dollars using the ENR-CCI of 5471/4985 (1.0975).12 All
operators were assigned the lesser cost of leasing equipment in this analysis.
The last scenario investigated for achieving zero discharge was the use of closed-loop solids control
technology followed by grinding and injection. Worksheet 4A hi Appendix X-l presents the detailed
calculations for this scenario. The costs and assumptions developed for Worksheets 3 and 4 were combined
hi this scenario. Specifically, the total waste volume (431,988 bbls) is the same as the waste volume hi
Worksheet 3, reflecting the waste-minimizing effect of closed-loop solids control equipment. Itemized
costs include both solids control equipment and grinding and injection equipment. The purpose of this
analysis was to determine whether minimizing the waste volume would reduce the overall compliance cost.
The analysis showed that the additional equipment costs override the savings earned through waste
rnxaimization, resulting hi a.total cost that was 33 percent greater than the cost of grinding and injecting
without waste minimization (see Table X-l).
5.0 POLLUTANT REMOVALS
The following sections describe hi detail the methodology used hi determining pollutant removals
associated with Option 2 (zero discharge). There are no incremental pollutant removals associated with
Option 1 because it represents current industry practice hi Cook Inlet, Alaska.
X-18
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5.1 GENERAL ASSUMPTIONS AND INPUT DATA
The following sections describe the assumptions and input data used to develop pollutant removals
for drilling wastes in the Cook Inlet region. These sections include the following topics:
• Drilling fluid characteristics
• Drill cuttings characteristics
• Mineral oil content
• Barite characteristics.
5.1.1 Drilling Fluid Characteristics
Since the drilling fluid characteristics change as drilling proceeds to greater depths, an average mud
density was assumed for the purposes of determining the pollutant loadings. Based on the information
provided by the industry in the 1993 Coastal Oil and Gas Questionnaire and information obtained through
sampling trips, EPA assumed a 10 pound per gallon mud with 11 percent solids by volume to have the
average characteristics (density) of the mud system used over the entire drilling project.24 Using the same
bases of information, the density of dry solids and concentration of barite in this mud were estimated to
be 1,025 pounds per gallon and 24 pounds per gallon, respectively.25 The drilling fluid characteristics are
also discussed in Chapter VII of this document.
5.1.2 Drill Cuttings Characteristics
In order to calculate the total suspended solids (TSS) loading due to spent drill cuttings, the density
of dry drill cuttings was estimated. Based on a geological stratigraphic profile provided by the industry,
dry drill cuttings were estimated to have a density of 980 pounds per barrel on a dry weight basis.26 For
the purpose of the pollutant loading analysis for this rule, the volume of wet cuttings was estimated to be
19 percent of the total volume of drilling wastes.3 The volume of dry drill cuttings was determined by
subtracting the amount of drilling fluid (estimated to be 5 percent by volume2) that adheres to the cuttings
discarded from the solids separation equipment. Since dry cuttings are generally comprised of inert
material, no hydrocarbons or metals were assumed to be present in the dry drill cuttings. Drill cuttings
characteristics are also discussed hi Chapter VII of this document.
X-19
-------
5.1.3 Mineral Oil Content
Based on information obtained from the 1993 Coastal Oil and Gas Questionnaires, EPA assumed
a mineral oil content of 0.02 percent by volume in the entire volume of drilling waste generated from
drilling operations in Cook Inlet.27 Since there are generally no significant sources of organic pollutants
in the drilling waste other than any oil based lubricant added to the drilling fluid system, it is assumed that
the mineral oil is the only source of organic pollutants in the spent drilling fluid and drill cuttings.
Table X-4 presents the organic constituents hi the mineral oil used to calculate the pollutant loadings for
this rulemaking. The concentrations in Table X-4 are averages of concentrations for three types of mineral
oil presented in the Offshore Development Document.8
5.1.4 Barite Characteristics
Barite is the primary source of metals (cadmium, mercury, and other priority pollutants of concern)
in drilling fluids. The characteristics of the raw barite used will determine the concentrations of metals ha
the drilling fluid and thus, provide EPA with the bases to determine pollutant reductions for each
technology option. The concentrations of metals in drilling fluids containing barite have been shown to
be directly related to the concentrations of cadmium and mercury in the stock barite.26 The current NPDES
permits in Cook Met have limitations on the concentrations of cadmium and mercury in the stock barite.
Stock barite that meets regulated metals limitations is referred to in this document as "clean" barite. For
the purposes of calculating the BAT metals concentrations in drilling fluids, the metals concentrations of
clean barite was used.
The mean metals concentrations for clean barite are presented in Table X-5. The metals
concentrations represent averages of data from Region 10 Discharge Monitoring Report Data.26 The metals
concentrations from Region 10 are considered to represent those of clean barite. Where no concentration
data were given for an analyte hi the Region 10 data, the concentration of the analyte from the 15 Rig
Study from the Gulf of Mexico was incorporated.26 The barium concentration reported in Table X-5 was
calculated from the total pounds of barite in the drilling fluid.25 The barite was assumed to be pure barium
sulfate (100% BaSO4) and the barium sulfate was assumed to contain 58.8 percent (by weight) barium.8
For the purposes of calculating the pollutant loadings for the BAT option, use of clean barite was assumed
for drilling operations in Cook Inlet, Alaska.
X-20
-------
TABLE X-4
ORGANIC CONSTITUENTS IN MINERAL OIL
(mg/ml, unless noted otherwise)
' f f f t ff\ "f ff ••
•• """ "" Qrgame-CoiKtituejjt ' ;-,
Benzene
Ethylbenzene
Naphthalene
Fluorene
Phenanthrene
Phenol (ug/1)
Alkylated benzenes3
Alkylated naphthalene1"
Alkylated fluorenes"
Alkylated phenanthrenesb
Alkylated phenols'
Total biphenylsb
Total dibenzothiophenes (ug/g)
, ,- v ; -Concentration (mg./ml)
ND
ND
0.05
0.08
0.12
ND
30.0
0.49
1.74
0.14
ND
1.94
370
Notes: The above data are averages of data presented in Table VH-9 of the 1993 Offshore Development Document for
three types of mineral oil.8 Averages include only detected values.
ND = Not Detected for all three types of mineral oil
a Includes C, through Q alkyl homologues
b Includes C, through Cg alkyl homologues
0 Includes cresol and C, through C4 alkyl homologues
5.2 INCREMENTAL POLLUTANT REMOVALS
The total industry-wide incremental pollutant removals were estimated for Option 2 based on the
total incremental volume and pollutant concentrations in the generated drilling fluids and drill cuttings.
Table X-6 presents the pollutant loadings and removals for Option 2. Loadings are the product of the
pollutant concentrations and the waste volume discharged following a particular treatment. The loadings
resulting from zero-discharge are all 0 barrels per year because no discharge would be allowed. The
X-21
-------
TABLE X-5
METALS CONCENTRATIONS IN BARITE
Metal ^ ^ , ,
• ' : •«<•«.
Cadmium
Mercury
Aluminum
Antimony
Arsenic
Barium
Beryllium
Chromium
Copper
Iron
Lead
Nickel
Selenium
Silver
Thallium
Tin
Titanium
Zinc
v "Oean" Bariie Concentration
'vA> * '> ?,»
-------
TABLE X-6
COOK INLET DRILLING WASTE POLLUTANT LOADINGS AND REMOVALS
BASED ON ZERO DISCHARGE"
Conventional
TSS (Total)
OB Content (Total)
24,084,790
4,368
24,084,790
4,368
168,593,529
30,579
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthiene
0.3
4.1
0.6
0.3
4.1
0.6
1.8
28.9
4.3
Priority Pollutant Metals
Cadmium
Mercury
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
9.1
0.8
47.1
58.7
5.8
1,983.4
154.5
290.1
111.6
9.1
5.8
9.9
1,656.9
9.1
0.8
47.1
58.7
5.8
1,983,4
154.5
290.1
111.6
9.1
5.8
9.9
1,656.9
63.6
5.8
329.7
410.7
40.5
13,883.5
1,081.8
2,030.5
780.9
63.6
40.5
69.4
11,598.5
•t?i$$;V3l&a8&$$ma?'
^<^;;;;?JW'^*P>'%^
Non-Conventionals
Aluminum
Barium
Iron
Tin
Titanium
Alleviated benzenes'
Alkylated napthatanes1"
Alkylated ftaorenes'
Alkylated phenanthrenes
Total biphenyls'
Total dibgnzothiophenes
74,953.7
991,680.1
126,805.3
120.7
723,1
154.0
2.5
8.9
1.0
10.0
0.03
74,953.7
991,680.1
126,805,3
120.7
723.1
154.0
2.5
8.9
1.0
10.0
0.03
524,675.6
6,941,760.9
887,637.2
844.6
5,061.7
1,078.3
17.6
62.5
7.3
69.8
0.2
Source: Appendix X-3
Values are from Column 4 of Worksheet 10, divided by 7 years (See Appendix X-3)
Values are from Column 6 of Worksheet 10, divided by 7 years (See Appendix X-3)
Values are from Column 7 of Worksheet 10, divided by 7 years (See Appendix X-3)
Total cumulative reductions cover the 7-year period from 1996 through 2002.
These analyte groups contain both priority pollutants and non-conventional pollutants, but were not distinguished in
the source document.
X-23
-------
because in the absence of a zero-discharge requirement, Cook Inlet operators would not use closed-loop
technology since they are already accomplishing a fairly high level of solids control.
The values in Column 3 of Worksheet 10 (page 2), "Amount of Total Drilling Waste Currently
Discharged," are calculated on page 1 of the worksheet. The value by which heavy metal concentrations
are multiplied (57,848,007 Ibs) is the dry weight of the total volume of drilling fluids expected to be
discharged over the next seven years. This value is used hi Column 3 because the metals concentrations
are given on a dry weight basis, and because it is assumed that metal contaminants are associated only with
barite in the drilling fluid (see Section 5.1.4.). The value by which organic and total oil concentrations are
multiplied (513,064 bbls) is the volume of drilling fluids expected to be discharged over the next seven
years. The concentrations of these pollutants are given on a volumetric basis.
Column 5 of Worksheet 10 presents the percentage of the amounts reported in Column 3 that will
be discharged following application of each option. Worksheet 10 shows 0% discharged following the
zero-discharge option.
Page 1 of Worksheet 10 provides calculations for the total suspended solids (TSS) values in the drill
cuttings and the drilling fluids. The TSS value for the drill cuttings is equal to the total weight of dry
cuttings, calculated as the product of the estimated volume of dry cuttings discharged (i.e., 95 percent of
the wet cuttings volume) and the density of the dry cuttings. The TSS value for the drilling fluids is the
product of the estimated volume of drilling fluids discharged (comprised of 81 percent of the drilling waste
volume plus 5 percent of the wet cuttings volume as adhering drilling fluid), the percent of dry solids in
the mud by volume (11 percent), and the density of dry solids in drilling fluid. The TSS value for drilling
fluids in Column 4 of Worksheet 10 (57,848,007 pounds) is also the value of the dry-basis weight of waste
discharged, listed hi Column 3.
6.0 BCT COMPLIANCE COSTS AND POLLUTANT REMOVALS DEVELOPMENT
6.1 BCT METHODOLOGY
The methodology for deterrnining "cost reasonableness" was proposed by EPA on October 29,
1982 (47 FR 49176) and became effective on August 22, 1986 (51 PR 24974). These rules set forth a
procedure which includes two tests to determine the reasonableness of costs incurred to comply with
candidate BCT technology options. If all candidate options fail any of the tests, or if no candidate
X-24
-------
technologies more stringent than BPT are identified, then BCT effluent limitations guidelines must be set
at a level equal to BPT effluent limitations. The cost reasonableness methodology compares the cost of
conventional pollutant removal under the BCT options considered to be the cost of conventional pollutant
removal at publicly owned treatment works (POTWs).
BCT limitations for conventional pollutants that are more stringent than BPT limitations are
appropriate in instances where the cost of such limitations meet the following criteria:
• The POTW Test: The POTW test compares the cost per pound of conventional pollutants
removed by industrial dischargers in upgrading from BPT to BCT candidate technologies with
the cost per pound of removing conventional pollutants in upgrading POTWs from secondary
treatment to advanced secondary treatment. The upgrade cost to industry must be less than
the POTW benchmark of $0.586 per pound ($0.25 per pound in 1976 dollars indexed to 1995
dollars).
• The Industry Cost-Effectiveness Test: This test computes the ratio of two incremental costs.
The ratio is also referred to as the industry cost test. The numerator is the cost per pound of
conventional pollutants removed in upgrading from BPT to the BCT candidate technology; the
denominator is the cost per pound of conventional pollutants removed by BPT relative to no
treatment (i.e., this value compares raw wasteload to pollutant load after application of BPT).
The industry cost test is a measure of the candidate technology's cost-effectiveness. This ratio
is compared to an industry cost benchmark, which is based on POTW cost and pollutant
removal data. The benchmark is a ratio of two incremental costs: the cost per pound to
upgrade a POTW from secondary treatment to advanced secondary treatment divided by the
cost per pound to initially achieve secondary treatment from raw wasteload. The result of the
industry cost test is compared to the industry Tier I benchmark of 1.29. If the industry cost
test result for a considered BCT technology is less than the benchmark, the candidate
technology passes the industry cost-effectiveness test. In calculating the industry cost test, any
BCT cost per pound less than $0.01 is considered to be the equivalent of de minimis or zero
costs. In such an instance, the numerator of the industry cost test and therefore the entire ratio
are taken to be zero and the result passes the industry cost test.
These two criteria represent the two-part BCT cost reasonableness test. Each of the regulatory
options was analyzed according to this cost test to determine if BCT limitations are appropriate.
6.2 BPT BASELINE
In order to estimate the incremental costs and the incremental conventional pollutant removals for
the BCT options, BPT baseline compliance costs and pollutant removals for drilling fluids and drill cuttings
were determined. BPT limitations prohibit the discharge of drilling fluids and drill cuttings containing free
oil, as determined by the visual sheen test. The estimated costs incurred by industry to comply with the
X-25
-------
BFT limitations consist of transportation and onshore disposal costs for all non-compliant drilling fluids and
drill cuttings.
For the purpose of developing HPT compliance costs, EPA applied current waste management costs
to the amount of drilling waste that currently does not meet BPT limitations. The following information
was used to develop the BPT drilling costs and conventional poEutant removals:
* Based on information provided by the industry,11 EPA estimates that approximately one (1)
percent of the drilling waste currently generated ta Cook Inlet cannot be discharged due to
existing discharge requirements (see Chapter HI, Section 3.0 for a review of current Region
10 NPDES regulations).
• Using the total drilling waste volume calculated for the seven-year period of anticipated drilling
activity (626,070 bbl of drilling fluids and drill cuttings, from Appendix X-l), the total volume
of waste estimated to incur BPT compliance costs is 6,261 bbl.
* Drilling waste composition and property data utilized in the pollutant removal analysis
presented in Appendix X-l are applied to this analysis as follows:
- Combined drilling waste consists of 19 percent wet cuttings and 81 percent drilling
fluids, by volume.3
- Wet drill cuttings contain 5 percent by volume adhering drilling fluid.2
- Drilling fluids contain 11 percent by volume dry solids.25
Average density of dry cuttings is 980 Ibs/bbL28
Average density of dry solids in drilling fluids is 1,025 Ibs/bbl.25
- Specific gravity of mineral oil is 0.85.8 This converts to a density of 297.74 Ibs/bbl
(0.85 x 350 Ibs water/bbl).
* The drilling fluid in the non-compliant drilling waste volume is estimated to contain 60 percent
by volume mineral oil.8
» The unit cost of disposing drilling wastes at landfills is $106 per bbl (Worksheet 2, Appendix
X-l).
Table X-7 presents the calculations for the BPT baseline disposal costs and conventional pollutant
removals based on the above information. Table X-8 presents the results of the unit BPT costs for drilling
fluids, drill cuttings, and for the drilling wastes combined. The values used in the Table X-8 calculations
are the results of the calculations presented in Table X-7.
X-26
-------
TABLE X-7
COOK INLET BPT DRILLING WASTE DISPOSAL COST AND CONVENTIONAL
POLLUTANT REMOVAL CALCULATIONS
,;, ,, DISPOSAL COSTS
a) Drilling waste disposal cost is $106/bbl (Worksheet 2, Appendix X-l).
b) Total drill cuttings disposal cost:
(0.19) x (6,261 bbls) x (106 $/bbl) = $126,097 ,
c) Total drilling fluids disposal cost:
(0.81) x (6,261 bbls) x (106 $/bbl) = $537,569
a) TSS in drilling fluid disposed:
(5,071 bbl drilling fluid) x (0.11) x (1,025 Ibs/bbl) = 571,801 Ibs TSS
b) Oil in drilling fluid disposed:
(5,071 bbl drilling fluid) x (0.60) x (297.74 Ibs/bbl) = 905,977 Ibs Oil
c) TSS in cuttings disposed:
(1,190 bbl wet cuttings) x (0.95) x (980 Ibs/bbl) = 1,107,508 Ibs TSS
d) Oil in cuttings disposed:
(1,190 bbl wet cuttings) x (0.05) x (0.60) x (297.74 Ibs/bbl) = 10,626 Ibs Oil
TABLE X-8
COOK INLET DRILLING WASTE UNIT BPT COSTS
Waste Stream
Drilling Fluids
Cuttings
Drilling Fluids + Cuttings
=V.,\:' '•::™*r*°°*>> •;,;. , !
$571,801 = $0.364/lb
(571,801 + 905,977)
$124,022 = $0.113/lb
(1,107,508 + 10,626)
$126,097 + $537,569 = $0.256/lb
(571,801 + 905,977 + 1,107,508 + 10,626)
X-27
-------
6.3 BCT COMPLIANCE COSTS, POLLUTANT REMOVALS, AND COST REASONABLENESS TEST
Only one BCT option was considered in the analysis: zero discharge of waste drilling fluids and
drill cuttings. The BCT compliance costs and pollutant removals were based on the scenarios previously
described in Section 4.2: 1) zero discharge via landfill and 2) zero discharge via injection. Although zero
discharge was determined to be not available in Cook Met, the results of the BCT cost test calculations
are presented to show whether such a limitation would pass the cost tests.
The conventional pollutant removals (for TSS and oil) are identical to those developed for the BAT
options analysis. Table X-9 presents the TSS and oil removals calculated in Worksheet 10 of Appendix
X-l and used in the BCT cost reasonableness test. These removals are based on the total volume of drilling
waste estimated to be disposed in the seven-year period following promulgation, 626,070 barrels of drilling
fluid and drill cuttings (see Section 4.1).
TABLE X-9
CONVENTIONAL POLLUTANT REMOVALS3
Wastestream
Drilling Huids
57,848,007
30,579
57,878,586
Dry Drill Cuttings
110,745,522
NA
110,745,522
Huids + Cuttings
168,593,529
30,579
168,624,108
" Pollutant removals for conventional analytes (TSS and oil) are derived in Worksheet 10, Appendix X-L
As stated above, the BCT costs were calculated for two zero discharge scenarios. The cost for the
zero discharge via landfill scenario comes from Worksheet 3 in Appendix X-l which includes costs for
applying closed-loop solids control equipment. The total cost for this scenario is $57,337,369. To
distinguish the cost of disposing drilling fluids from the cost of disposing drill cuttings in the BCT cost
analysis, the total cost was multiplied by the percentage that each waste volume represents. Worksheet 1
in Appendix X-l shows that 19 percent of the total wastestream is cuttings. Therefore, the cost of
disposing cuttings was calculated to be $10,894,100 (0.19 x $57,337,369). Likewise, the cost of disposing
X-28
-------
drilling fluids was calculated to be $57,337,369 (0,81 x $57,337,369). Table X-10 presents these costs
based on disposal via landfill, as well as the pollutant removals, the unit POTW cost, and the results of the
BCT cost reasonableness test. As discussed elsewhere in this document, a zero discharge limitation for
drilling fluids, drill cuttings and dewatering effluent was rejected for Cook Inlet because it was found to
be unavailable (see Chapter XTV).
Table X-ll presents the BCT cost analysis for the second zero-discharge scenario, disposal via
subsurface injection. The total cost for this scenario, from Worksheet 4 in Appendix X-l, is $35,624,501.
The cost of disposing cuttings was calculated to be $6,768,845 (0.19 x $35,624,501), and the cost of
disposing drilling fluids was calculated to be $28,856,656 (0.81 x $35,624,501).
X-29
-------
TABLE X-10
BCT COST TEST RESULTS FOR
DRILLING FLUIDS AND DRILL CUTTINGS BASED ON
DISPOSAL COSTS FOR CLOSED-LOOP SOLIDS CONTROL AND LANDFILL
Wastestream
Drilling Fluid
Dry Drill
Cuttings
Fluids +
Cuttings
Total Conv.s
Removed
Obs)
57,878,586
110,745,522
168,624,108
Total eosfe"
"" t
&99S$l "
46,443,269
10,894,100
57,337,369
* •'oA , **
,JW&
.Cost*
: '$/&?*
0.802
0.098
0.340
"Statvorxyrt
<<$0.58&ttb)
N
Y
Y
BIT Cost
<$/lb)
0.364
0.113
0.256
ICR Ratio
NA
0.87
1.33
PassIGR?
C<1.29)
•"" >••
N
Y
N
* Total cost for fluids+cuttings comes from Worksheet 3, Appendix X-l (zero discharge via landfill). (Total cost for fluids
- 0.81 x $57,337,369; total cost for cuttings = 0.19 x $57,337,369.
TABLE X-ll
BCT COST TEST RESULTS FOR
DRILLING FLUIDS AND DRILL CUTTINGS BASED ON
DISPOSAL COSTS FOR SUBSURFACE INJECTION
Wastestream
Drilling Fluid
Dry Drill
Cuttings
Fluids +
Cuttings
Total Comr.s
Removed
(Ibs)
57,878,586
110,745,522
168,624,108
Total-Co!^
s v ^ '•.j '••
\m$$ ;;
28,856,656
6,768,845
35,625,501
<„ i- ;•. ', '
fPTW^
, Cost
'-mut*
0.499
0.061
0.211
'iPasspb-TW?
{<&iJ58&S>)
' f » ^V<
Y
Y
Y
Brtcost-
;<$^lb):' -
0.364
0.113
0.256
ICR;»atio;
ff s
1.37
0.54
0.83
3Pas$ ICR?
(^ii2s>;
N
Y
Y
a Total cost for fluids+cuttings comes from Worksheet 4, Appendix X-l (zero discharge via subsurface injection). Total cost
for fluids - 0.81 x $35,625,501; total cost for cuttings = 0.19 x $35,625,501.
X-30
-------
7.0 REFERENCES
1. Horstman, J., Avanti, Memorandum to Ron Jordan, U.S. EPA, regarding "North Slope Drill Cuttings
Reclamation Program," August 12, 1996.
2. Ray, James P., "Offshore Discharges of Drill Cuttings," Outer Continental Shelf Frontier
Technology, Proceedings of a Symposium, National Academy of Sciences, December 6, 1979.
(Offshore Rulemaking Record Volume 18)
3. U.S. EPA, Responses to the 1993 "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160, July
1993. (Confidential Business Information)
4. U.S. EPA, "Sampling Trip Report to GAP Energy Drill Site, Holmwood, Louisiana, June 16-17,
1993," JuneS, 1994.
5. U.S. EPA, "Sampling Trip Report to ARCO Oil and Gas Drill Site, Black Bayou Field, Sabine
Wildlife Refuge, Lake Charles, Louisiana, July 21-22, 1993," October 21, 1994.
6. U.S. EPA, "Trip Report to Unocal, Intracoastal City, Louisiana, September 8-9, 1993," January 25,
1994.
7. U.S. EPA, Development Document for Proposed Effluent Limitations Guidelines and Standards for
the Coastal Subcategory of the Oil and Gas Extraction Point Source Category, EPA 821-R-95-009,
February, 1995.
8. 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)," January 1993.
9. Mclntyre, J., Avanti, Memorandum to the record regarding Cook Inlet Drilling Operators
Confidential Business Information, September 12, 1996. (Confidential Business Information)
10. SAIC, "Preliminary Statistical Analysis of Permit Compliance Monitoring Records for the Toxicity
of Drilling Fluids in Alaska (Draft Final Report)," December 9, 1994.
11. Schmidt, R., Unocal, Correspondence to Manuela Erickson, SAIC, regarding drilling fluids not
acceptable for discharge, July 11, 1994.
12. Engineering News Record, "First Quarterly Cost Report," p. 72, March 25, 1996.
13. Safavi, B., Memorandum to Allison Wiedeman regarding Cook Inlet operators' 308 questionnaire
identification numbers and related confidential data, January 30, 1995. (Confidential Business
Information)
14. SAIC, "Oil and Gas Exploration and Production Wastes Handling Methods in Coastal Alaska,"
January 6, 1995.
15. Wiedeman, A., U.S. EPA, "Trip Report to Alaska - Cook Inlet and North Slope Oil and Gas
Facilities, August 25 - 29, 1993," August 31, 1994.
X-31
-------
16. Schmidt, R,, Unocal Corp., Correspondence with Manuela Erickson, SAIC, regarding drill cuttings
and fluid discharge information, April 21, 1994.
17. Mclntyre, J., SAIC, Record of telephone call with Russell Schmidt, Unocal, regarding "Possibility
of Shipping Wastes from Cook Inlet to Seattle, WA," May 12, 1995.
18. Erickson, M., SAIC, Contact report with Arctic Tug and Barge Company, March 16, 1994.
19. Mclntyre, J., SAIC, Record of telephone call with Alan Katel, Chemical Waste Management,
regarding "Cost of Disposing Drilling Wastes and Possible Transportation Routes," May 9, 1995.
20. Mclntyre, J., SAIC, Record of telephone call with Josh Stenson of Carlisle Trucking, regarding
"Costs to Truck Wastes from Kenai, Alaska to Arlington, Oregon," May 23, 1995.
21. SAIC, Worksheet entitled "Solid Separation Equipment Cost Estimation," May 3, 1994.
22. Litzen, L., Shell Western E&P, Inc., Communication with Manuela Erickson, SAIC, regarding
production platforms in Cook Met," April 18, 1994.
23. Schmidt, R., Unocal Corp., Communication with Manuela Erickson, SAIC, regarding injection of
drilling waste in Cook Inlet, Aprl 7, 1994.
24. SAIC, Worksheet entitled "Calculation of Average Mud Weight for Cook Inlet Drilling Mud," April
13,1994.
25. SAIC, Worksheet entitled "Calculations for Average Density of Dry Solids in,Cook Inlet Drilling
Mud," June 6, 1994.
26. SAIC, Worksheet entitled "Calculations for Average Density of Cuttings in Cook Inlet," September
7, 1994.
27. SAIC, Worksheet entitled "Estimation of Organic Concentrations in Cook Inlet Drilling Mud," June
7, 1994.
28. SAIC, "Descriptive Statistics and Distributional Analysis of Cadmium and Mercury Concentrations
in Barite, Drilling Fluids, and Drill Cuttings from the API/USEPA Metals Database," prepared for
Industrial Technology Division, U.S. Environmental Protection Agency, February 1991. (Offshore
Rulemaking Record Volume 120)
X-32
-------
CHAPTER XI
COMPLIANCE COST AND POLLUTANT REMOVAL DETERMINATION-
PRODUCED WATER
1.0 INTRODUCTION
This section presents the estimated compliance costs and reductions in pollutants discharged as a
result of the treatment options developed for control of produced water. Currently, discharges of produced
water in the coastal subcategory are occurring only in the Gulf of Mexico and Cook Inlet, Alaska. The
technology costs represent additional investment required beyond those costs associated with BPT
technologies. The methods used to develop compliance costs for the control options are presented in
Sections 4 and 5. Pollutant reductions are presented in Section 6.
Treatment technology costs were estimated on a facility-specific basis. For operators in coastal
areas of the Gulf of Mexico, regulatory compliance costs and pollutant removals are based on mathematical
cost model equations applied to each production facility that is projected to be discharging produced water
after January 1997. For operators in Cook Inlet, compliance costs and pollutant removals were estimated
for each production facility that currently discharges produced water, based on the current level of treatment
at each facility.
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS
Three BAT options for produced water effluent limitations guidelines for existing coastal sources
were considered in this estimate of compliance costs and pollutant removals:
Option 1: Zero discharge except: (a) facilities discharging produced water derived from offshore
subcategory wells into main [major] deltaic passes of the Mississippi River must meet a monthly
average oil and grease content of 29 mg/1 and a daily maximum of 42 mg/1; and (b) Cook Inlet
facilities allowed to discharge must meet a monthly average oil and grease content of 29 mg/1 and
a daily maximum of 42 mg/1.
Option 2: Zero discharge for all coastal facilities except in Cook Inlet, where discharges must
meet the 29/42 mg/1 oil and grease limitations.
Option 3: Zero discharge for all coastal facilities.
XI-1
-------
2.1 OPTION 1
The technology basis for meeting the 29/42 mg/1 limitations contained in Option 1 (and for Cook
Inlet in Option 2) is improved operating performance of gas flotation. This technology consists of
improved operation and maintenance of gas flotation treatment systems, more operator attention to
treatment systems operations, chemical pretreatment to enhance system effectiveness, and possible re-sizing
of certain treatment system components for increased treatment efficiency. The improved performance gas
flotation technology basis was developed as part of the Offshore Oil and Gas rulemaking effort, and is
described more fully in the 1993 Offshore Development Document.1 Improved operation of gas flotation
can result in additional removal of oil and grease from the produced water relative to BPT-level treatment
systems. The discharge limitations on oil and grease as described in the regulatory options are more
stringent than the current BPT limitations of 48 mg/1 monthly average, 72 mg/1 daily maximum. For those
platforms or facilities that do not have gas flotation units, the installation of new flotation units was assumed
necessary in the analysis to achieve compliance with the new limitations. For Cook Inlet, the compliance
costs and pollutant removals calculated for Options 1 and 2 are identical since both options are based on
improved operation of gas flotation.
2.2 OPTIONS 2 AND 3
For coastal Gulf of Mexico facilities, compliance costs and pollutant removals for Options 2 and
3 are identical since both options are based on subsurface injection of produced water. Subsurface injection
is the predominant technology used for zero discharge compliance in the Onshore Subcategory. It consists
of filtration followed by injection of produced water into a compatible geologic formation, either for
disposal or for enhanced oil recovery or waterflooding. For operators in the Gulf of Mexico, the injection
option includes cartridge filtration as pretreatment followed by injection for disposal. (For Cook Inlet
operators, the injection option includes granular media filtration and gas flotation as pretreatment followed
by injection either for waterflooding or for disposal. Injection may take place for enhanced oil recovery
or for disposal, or for a combination of purposes.) Injection of produced water for enhanced oil recovery
generates an economic benefit for the facility that has not been credited against zero discharge compliance
costs.
In order to generate estimates of costs and pollutant removals for each option, EPA used the coastal
Gulf of Mexico. The industry profile information was obtained from studies described hi Chapter V, and
includes state discharge monitoring data, EPA site visits and sampling reports, and direct contacts with the
operators. This information consists of the following elements:
XI-2
-------
• Identification of currently discharging production facilities including name of the operator,
state discharge permit number, location of the producing field, produced water discharge
volumes, and date of compliance with state requirements for no discharge where
applicable.
• Contaminant levels hi produced water from BPT treatment.
All options considered for this regulation beyond the BPT level of control for the coastal region
are based on two treatment technologies:
• Improved operating performance of gas flotation followed by discharge to surface water.
• Subsurface injection.
In referring to the options considered for control of produced water discharges, the Gulf of Mexico
and Cook Inlet are presented separately in the option descriptions and accompanying discussion. All other
coastal areas are practicing zero discharge of oil and gas production wastes, and will be subject to this rule,
even though not mentioned specifically.
2.3 SUMMARY COSTS AND REDUCTIONS
Table XI-1 presents summary compliance costs for Options 1, 2, and 3 using the Region 6 General
Permit to define regulatory baseline. Operating and maintenance (O&M) costs are estimated for the first
year after implementation. These first year O&M costs may rise in subsequent years as produced water
flow rates increase. This increase hi O&M costs is addressed in the "Economic Impact Analysis for Final
Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction
Point Source Category. "2
Table XI-2 presents summary compliance costs for Options 1, 2, and 3 using the alternative
baseline. Compliance costs for Cook Inlet are identical to the baseline costs presented hi Table XI-1.
Operating and maintenance (O&M) costs are estimated for the first year after implementation, which may
rise as produced water flow rates increase in the future.2
No new source facilities are expected to occur in facilities discharging produced water derived from
offshore subcategory wells into main [major] deltaic passes of the Mississippi River. Discharges at other
coastal facilities would already be required to comply with zero discharge under the Region 6 General
Permits (60 FR 2387, January 9, 1995).3 No new source production facilities are expected to occur in Cook
XI-3
-------
TABLE XI-1
TOTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS FOR
PRODUCED WATER BAT OPTIONS
(BASELINE)
Options-; :J,f;:;
Pption1: Zero discharge except
(a) major pass facilities and (b)
Cook Inlet facilities - 29/42 mg/1
oil and grease
11,051,065
1,455,085
2,281,305
Pption 2: Zero discharge except
Coofc Met facilities = 29/42 mg/1
oil and grease
30,512,598
10,774,115
1,494,100,361
Pp|ioij3: Zero discharge, all fa-
cilities
118,236,230
30,566,255
2,549,142,381
Inlet in the near future. Therefore, no NSPS costs or pollutant reductions are anticipated as a result of this
rulemaking. However, due to frequent changes in the oil and gas industry, costs for a model new source
facility in Cook Inlet have been estimated for purposes of analysis and are discussed in Section 4.3.
3.0 GULF OF MEXICO BASELINE COMPLIANCE COST METHODOLOGY
EPA determined that six production facilities will be discharging produced water from eight outfalls
as of January 1997* The produced water population consists of production facilities in Louisiana with
medium to high produced water flow rates (referred to hereafter as medium/large facilities) that will treat
or inject onsite. These facilities treat offshore-derived produced water prior to discharge into major deltaic
passes of the Mississippi River. The treatment/disposal technologies evaluated and costed for disposal of
produced water from these facilities are based on: 1) effluent limitations based on improved operating
performance of gas flotation (IGF), and 2) zero discharge by subsurface injection in dedicated disposal
wells. In the proposed rule, EPA assumed that a production facility with more man one outfall would
consolidate produced water into a single flow for treatment or for injection. While generally true, site-
specific information on the eight outfalls in the coastal Gulf of Mexico population indicates it would not
XIr4
-------
TABLE XI-2
TOTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS FOR
PRODUCED WATER BAT OPTIONS
(ALTERNATIVE BASELINE)
•"* * •* ^sf '' ''f
"• i A?^"1 ** *'*' v< % ^ X ""
»-"• i $- '- Options '
-- , J ",~ * c -
v... \ >s » *
Option 1: Zero discharge except
(a) major pass facilities and (b)
Cook Inlet facilities = 29/42 mg/1
oil and grease
Option 2: Zero discharge except
Cook Inlet facilities = 29/42 mg/1
oil and grease
Option 3: Zero discharge, all fa-
cilities
, "'•. "• > , ,"
iCowpJIiwcsCoiSts '
CagiM Costs
L >:V995® ::
36,197,804
92,756,848
180,480,480
, - 0&M£q$ts :
{1995=$/yr) N
5,067,546
36,147,868
55,940,008
'Pollutant:1 ,
Retttovafe " " "
(pounds); '
10,585,607
4,602,978,833
5,658,020,853
be practical for these particular outfalls to be consolidated. For example, two of North Central's outfalls
are separated by the Southwest Pass of the Mississippi River, while the third is over five miles away.5
\
These features are prohibitive to consolidation at North Central, thus EPA estimated compliance costs
assuming produced water from each outfall would be injected separately.
This section describes the development of compliance costs in terms of capital and operating and
maintenance (O&M) costs for production facilities in the coastal Gulf of Mexico region. For the purpose
of clarity, terminology used in this section is defined as follows:
Design cost data: Produced water flow rates and capital and O&M costs developed from actual
equipment design and cost data obtained from oil and gas operators and equipment vendors. The
term "design cost data" refers to both the "design costs" and the "design flows" (each defined
below). For the zero discharge option and flows above 5,000 bpd in the improved gas flotation
option, the design cost data were used to develop mathematical models to best represent the
relationship between cost and flow in order to predict facility-specific compliance costs.
Design flows: Produced water flow rates specifically selected using available treatment equipment
sizes and best engineering judgement.
XI-5
-------
Design costs: Capital and O&M costs calculated from actual equipment cost data obtained from
oil and gas operators and equipment vendors. Design costs were calculated for each selected
design flow.
Step costs: Discrete capital and O&M design costs calculated for specific produced water flows
were applied to produced water flow rates under 5,000 bpd. (Refer to following discussion.)
Figure XI-1 is a flow chart showing the development of the capital and O&M costs for the Gulf
of Mexico production facilities, based on discharge option, facility size and produced water volumes
generated. Information and data obtained from EPA site visits, oil arid gas production operators, vendor
quotes, cost data developed by the Energy Information Administration (Department of Energy), and
engineering analyses were used to estimate design costs based on selected design flow rates.6'7-8-9 The
design cost data were then used to develop mathematical models that best represented the relationship
between the design costs and the design produced water flow. When the cost equation development
methodology was used, actual facility-specific discharge flows were inserted into the equations to calculate
capital and O&M compliance costs.
One exception to the cost equation methodology applies to lower flows (70.5 to 5,000 bpd) for the
improved gas flotation option. In this case, continuous mathematical models did not adequately represent
the engineering relationship between design costs and lower flow rates. Equipment costs are steady across
a low flow range until a threshold is reached which requires equipment sizes to "step up" to the next
available size. To more precisely portray costs at low flow ranges (70.5 to 5,000 bpd), step costs were
applied to three flow rate ranges:
• 200 bpd step cost: The capital and O&M costs calculated for 200 bpd design flows were
applicable to the 70.5 to 200 bpd flow range.
• 2,000 bpd step cost: The capital and O&M costs calculated for 2,000 bpd were applicable to
the 201 to 2,000 bpd flow range.
• 5,000 bpd step cost: The capital and O&M costs calculated for 5,000 bpd were applicable to
the 2,001 to 5,000 bpd flow range.
When the step cost methodology was used, actual facility-specific discharge future flow rates were
compared to the defined flow ranges and the corresponding cost was applied. Capital and O&M
compliance costs were derived for each of the eight production facilities based on individual flow. Current
produced water flows for the eight facilities reportedly range from 291 bpd to 153,895 bpd.
XI-6
-------
CC« 340,764+ 6.95Qf
Large-Volume Facility
»|0&MCl)st(tryr)| OM = 37,099
CC-190,221
>»]0&MCosl(S'yrT] OM-JMM + MJSQp
CC=C«pllaICost(1995$)
OM-Annual O&MCcst (1095 5.\T)
Qp = Cu nc nt Produced W«cr Flow (bpd)
Qf» Future Produced Water Flow (bpd)
»JQ&MCoil(S^] OM-42.25Qp-8.225.l5
Figure XI-1
Produced Water Cost Determination How Chart For Gulf of Mexico
-------
Regulatory compliance costs were estimated for all options based on estimated future produced
water volumes. Future produced water volumes were required when sizing and costing the treatment
equipment. EPA based its estimate of future flow rates based on the following assumptions:
• Future produced water volume increases by the same rate for both oil and natural gas producing
wells. While produced water volumes from gas producing wells is not expected to increase by
the same rate as from oil producing wells, EPA made a conservatively higher cost assumption
in the absence of data.
• Capital costs for facilities currently discharging produced water were estimated by assuming a
future produced water flow 1.5 times the current flow. The use of this factor, which is a
standard engineering design practice, has resulted in an overall conservative (i.e., high) capital
cost estimate. Many operators have indicated a factor of 1.2 to 1.25 is typically used when
sizing and costing produced water treatment equipment.7
• Production facility location, either land- or water-access, was considered in the proposed rule
as an important factor in determining cost. In the final rule, all facilities are assumed to be
water-access due to their locations on major deltaic passes and supported by telecons with each
operator.4
3.1 GULF OF MEXICO OPTION 1 BASELINE CAPITAL AND O&M COSTS (IMPROVED OPERATING
PERFORMANCE OF GAS FLOTATION)
As previously stated, costs for medium/large-volume facilities (including all Gulf of Mexico
facilities) to achieve improved gas flotation treatment were developed by first estimating design costs based
on selected design flows, and then either performing a regression analysis with these data points to derive
the cost equations or applying discrete step costs to the appropriate flow rates. Section 3.1.1 discusses the
design parameters used as the basis for the cost equation and step cost derivations. Section 3.1.2 presents
the basis for O&M cost estimates.
3.1.1 Development of Gulf of Mexico Option 1 Baseline Capital Costs (Improved Operating
Performance of Gas Flotation)
Under Option 1, EPA would establish effluent limitations based on the operating performance of
gas flotation technology, improved over the performance noted in the development of BPT limitations.
This technology would consist of improved operation and maintenance of gas flotation treatment systems,
more operator attention to treatment system optimization, chemical pretreatment to enhance system
effectiveness, and possible resizing of certain treatment system components for increased treatment
efficiency. The costs for this option were developed for new improved gas flotation systems for the
facilities not having existing improved gas flotation systems. Design capital and O&M costs for medium/
XI-8
-------
large-volume facilities include the costs of the gas flotation unit, and a natural gas driven generator for
systems that require more than 25 hp to operate. Costs for natural gas generators were derived based on
information developed by Energy Information Administration (Department of Energy).8
One Gulf of Mexico facility, Flores & Rucks, currently operates an improved gas flotation system.
EPA has reviewed discharge data on Flores & Rucks' treated produced water effluent to determine the
level of effluent treatment. This data consisted of historical DMRs from LDEQ and other information
submitted directly to EPA.10'11'12 This information demonstrates effluent treatment performance within the
effluent limits of 29 mg/1 monthly average and 42 mg/1 daily maximum. A single exceedance of these
limits was reported between January 1993 and September 1995." In view of comments made by Flores
& Rucks and the fact that this facility is currently only required to meet BPT limits, it may have allowed
effluent levels to fluctuate somewhat. Thus, this lone exceedance is viewed as an anomaly. For these
reasons Flores & Rucks incurs no capital or O&M costs under Option 1.
Another facility, North Central, currently operates a gas flotation system at one outfall. The
effluent data from mis facility do not represent oil and grease levels attainable with improved operation of
gas flotation technology. Therefore, EPA has included costs to upgrade the gas flotation unit at that outfall
to improved gas flotation operational levels. These upgrade costs are included as O&M costs and represent
costs for chemical addition, labor (for closer monitoring of operating parameters), and other costs
associated with achieving IGF treatment levels.
3.1,1.1 Design Capital Costs for Improved Operating Performance of Gas Flotation
Treatment
Table XI-3 presents the capital costs for improved gas flotation for the selected design flows.
Design equipment capital costs for gas flotation in coastal areas were obtained from supporting
documentation for the Offshore Development Document in 1986 dollars.1 These figures were adjusted to
1995 dollars by the ratio of Engineering News Record-Construction Indices (ENR-CCI) of 5471 (for 1995)
to 4295 (for 1986).»
The following list summarizes the information and methodology used to develop the design capital
costs.
• Equipment Purchase Cost: The equipment purchase cost for all production facilities includes:
gas flotation unit and feed pump, and natural gas generator for systems that require more than
XI-9
-------
TABLE XI-3
DESIGN CAPITAL COSTS (1995 DOLLARS) FOR IMPROVED GAS FLOTATION AT MEDIUM/LARGE
FACILITIES
Component | < -
Gas Flotation
Generator
Feed Pumps
Total Equipment Purchase Cost:
Piping and Instrumentation
Installation
Equipment Installed Cost:
Engineering
Contingency
Insurance/Bonding
Total Equipment Installed Cost:
Platform Retrofit
TOTAL CAPITAL COST:
. Medium Design Flow (bpd)
200
89,369
0
4,032
93,401
14,010
29,888
137,299,
13,730
20,595
5,492
177,116
10,289
187,405
. »>«?
-------
25 hp to operate. A regression analysis was performed to determine the relationship between
the horsepower demand and the produced water flow. 25 hp power requirements corresponded
to a produced water flow of 5,000 bpd. Flows greater than 5,000 bpd require more than 25 hp
to operate and the electric power is supplied by natural-gas driven generators.8 Gas flotation
equipment cost includes: gas flotation skid-mounted, complete electrical systems, oil and water
outlets brought to the edge of the skid, and sufficient instrumentation for proper operation. All
gas flotation systems are equipped with electric motors.8
• Installed Costs: Equipment installation costs include the piping cost (15% of the purchase
cost), and installation labor cost (32% of the purchase cost). No transportation costs were
separately included because the equipment costs already take this into account by being based
on costs of equipment delivered to the Gulf of Mexico area.6
• Additional Costs (Engineering, Contingency, and Insurance/Bonding Fees): These fees
were added to the equipment purchase and installation costs to develop actual capital costs.
These fees include all engineering design costs (10%), administrative costs (4%), and any
incidental costs incurred in the process of purchasing and installing the equipment (15 %).7
• Platform/Concrete Pad Retrofit Costs: Equipment space requirements were estimated to be
twice the footprint. The retrofit costs were $82/ft? (1995 dollars).6
3.1.1.2 Model Cost Equations for Improved Operation of Gas Flotation
Two separate capital cost methodologies were developed for Option 1. For future produced water
flow rates exceeding 5,000 bpd, cost relationships were predicted using equations developed from actual
data. These calculations are described in Large Flow Cost Determination, below. For facilities projected
to have produced flow rates below 5,000 bpd, EPA developed a methodology to more closely model costs
for these medium-size facilities. This methodology is presented in Medium Flow Cost Determination,
below.
Large Flow Cost Determination
For Option 1, two independent cost equations were developed for medium/large-volume facilities
with predicted future flows greater than 5,000 bpd: one capital cost equation and one O&M cost equation.
Table XI-4 lists the two cost equations developed and used to predict costs for treatment by improved gas
flotation of high produced water flow facilities in the Gulf of Mexico (i.e., Chevron Pipe Line Company,
Flores & Rucks, North Central Outfall 003-1, and Amoco).
For production facilities with future flows projected to exceed 5,000 bpd, the best-fit mathematical
model is a linear function of the general form:
XI-11
-------
TABLE XI-4
CAPITAL AND O&M STEP COSTS AND COST EQUATIONS FOR IMPROVED GAS FLOTATION
'{::-: '•'..'.-'... ...,-..•:•:! Medium-Volume Gas Flotation Systems
Design Flow
Ranges
(bpd)
70.5-200
201-2,000
2,001-5,000
Capital Cost (1995$)
Design
187,405
190,223
247,000
Step Cost
187,405
190,223
247,000
O&M Cost (1995 $/yr)
Design
31,947
32,228
37,099
Step Cost
31,947
32,228
37,099
';'*"' -" --,-:," '- * -' ,',/-..>"'
Design Flow
(bpd)
10,000
15,000
25,000
40,000
80,000
Cost Equation
Capital Cost (1995$)
Design
418,252
445,182
509,968
610,199
900,895
Calculated
410,215
444,941
514,393
618,570
896,376
% Error
-1.92%
-0.05%
0.87%
1.37%
-0.50%
340,764 + 6.95 x (flow, bpd)
O&M Cost (1995 $/yr)
Design
52,578
54,901
60,342
68,991
93,739
Calculated
51,893
54,855
60,779
69,665
93,360
% Error
-1.30%
-0.08%
0.72%
0.98%
-0.40%
45,969 + 0.59 x (flow, bpd)
I
-------
where: Y — design cost (either capital or O&M cost)
m = slope (X-coefficient)
X — design flow (in barrels per day)
b = Y-intercept (constant)
The X-coefficient and constant for each of the two equations were determined using regression
analyses with the design costs.14 Note that in Table XI-4, "calculated" costs are those generated by the
model cost equations for each design flow listed. The comparison of design to calculated costs shows an
error of no greater than ±2% for all IGF.14
Medium Flow Cost Determination
The proposed rule had represented the relationship between medium design flows and design costs
as a binomial function of the form: Y = a + bX + cX2. EPA re-evaluated costs predicted by the binomial
model for facilities with medium produced water flows (i.e., between 70.5 and 5,000 bpd) and determined
that modeling for capital costs and O&M costs could be improved with a different modeling approach.
Within the medium flow range, costs change at discrete yet small intervals which were distorted when
applied to the continuous mathematical models in the proposal Development Document. In this case,
continuous mathematical models did not adequately represent the engineering relationship between design
costs and lower flow rates. Equipment costs are steady across a low flow range until a threshold is reached
which requires equipment sizes to "step up" to the next available size. To more precisely portray costs
at low flow ranges (70.5 to 5,000 bpd), step costs were applied to three flow rate ranges. Table XI-3 lists
the flow ranges and the corresponding design costs.
State DMR data for the Gulf of Mexico facilities were used to establish current flow rates. Current
flow rates were escalated to future flow rates by a factor of 1.5.7 Facilities with future flow rates predicted
at less than 5,000 bpd included Warren Petroleum, Gulf South Operators, North Central outfall 002-2 and
North Central outfall 001 (see Table XI-5). These future flow rates were compared to one of the three flow
ranges and assigned the corresponding design cost to estimate each facility's compliance cost. Table XI-5
presents the facility-specific compliance estimates based on either the step cost determination or the model
capital and O&M cost equations.
XI-13
-------
TABLE XI-5
GULF OF MEXICO FACILITIES CAPITAL AND O&M COSTS PRODUCED WATER TREATMENT
VIA IMPROVED GAS FLOTATION (1995 DOLLARS)
Permit-Outfall
Number. ' Operator
3229-001-3
2963-006
2071-004-1
2400-001
2184-002-2
2184-003-1
2184-001
3407-001
TOTALS
Chevron Pipe Line Company
Warren Petroleum Company
Flores & Rucks, Inc.
Gulf South Operators, Inc.
North Central
North Central
North Central
Amoco
Current Average Future Average
.Volume (bp,d)/ - Volume (bpd) „ ^
18,920
1,808
153,895
291
1,910
7,606
572
6,290
191,292
28,380.0
2,712.0
230,842.5
436.5
2,865.0
11,409.0
858.0
9435.0
Capita) Cost
. CD
537,867
247,000
0
190,223
247,000
0
190,223
406,291
$1,818,604
O&MCost
57,177
32,228
0
32,228
32,228
50,475
32,228
49,695
$286,259
-------
3.1.2 Development of Gulf of Mexico Option 1 O&M Costs (Improved Operating Performance
of Gas Flotation)
Estimated design O&M costs for IGF treatment are presented in Table XI-6. Standard operating
and maintenance cost was estimated to be 10% of the total capital equipment cost.8 In addition, labor costs
were estimated based on one person-hour per day at a rate of $39.00 per hour (in 1995 dollars).15 Typical
operating and maintenance costs, other than increased labor, include: polymer and/or flocculation
enhancement chemicals, fuel cost, and feed pump and agitator maintenance and replacement costs. As
discussed in Section 3.0, EPA based capital costs on assuming future produced water flow 1.5 times the
current flow. O&M costs estimate first year expenditures, which may be expected to rise as produced
water flow rates increase. This future escalation in O&M costs due to produced water flow increases is
addressed in the economic impact model.2
3.2 GULF OF MEXICO OPTIONS 2 AND 3 BASELINE CAPITAL AND O&M COSTS (ZERO DISCHARGE BY
SUBSURFACE INJECTION)
Capital and O&M costs for zero discharge by subsurface injection at medium/large-volume
facilities include the costs of pretreatment by cartridge filtration, the costs of injection pumps and wells,
and the costs of well installation and maintenance. Produced water injection costs are the same whether
or not the subsurface formation is utilized for disposal or for enhanced oil recovery (waterflood).
However, potential production benefits from the use of produced water injection as waterflood support
could reasonably been credited against compliance costs. Since little data is available to quantify this
benefit, and to help ensure conservatively higher cost estimates, this credit is not reflected in the following
analyses.
Since the completion of the Development Document for the proposal, capital costs have been
adjusted to 1995 dollars, and certain other costs have been revised as a result of EPA's evaluation of
information submitted by commenters. O&M costs have been added since proposal for replacement filters,
additional treatment chemicals, and increased well backwash frequency. These costs are detailed in
following sections and in the technical support document.14
3.2.1 Design Capital Costs for Subsurface Injection
Design capital costs are based on direct quotes from equipment vendors, summary statistics from
the EPA 1993 Coastal Oil and Gas Questionnaire,16 and standard engineering cost estimating factors. The
following list summarizes the bases for the design capital costs:
XI-15
-------
TABLE XI-6
DESIGN O&M COSTS FOR IMPROVED GAS FLOTATION AT MEDIUM/LARGE FACILITIES
_< - J
C«*pOnenf * ?
tteslgif'Klow (bf
200 -
17,712
14,235
31,947
,J,000
17,993
14,235
32,228
2,000
17,993
14,235
32,228
5,000
22,864
14,235
37,099
10,000
38,343
14,235
52,578
*. <- •>
&),, *,« ,
f }
15,000
40,666
14,235
54,901
- 25,000
46,107
14,235
60,342
, 40,000
54,756
14,235
68,991
80,000
79,504
14,235
93,739
-------
• Pretreatment: EPA conservatively assumed facilities would include cartridge filtration as
pretreatment to injection.
• Cartridge Filters and Feed Pumps: Cartridge filters and feed pumps were sized based on the
design flows and the manufacturer recommended volumetric loads as follows:17
10" cartridge - 7 gpm/cartridge (240 bpd)
20" cartridge - 14 gpm/cartridge (480 bpd)
30" cartridge - 21 gpm/cartridge (720 bpd)
One module contains 4 cartridges. Where design flow exceeds 84 gpm (2,880 bpd), multiple
modules were costed. The cartridge filters are rated for a maximum pressure of 150 psig.
Filter feed pumps were sized for the required flow and a discharge pressure of 50 psig.
• Feed Pumps: Feed pumps are electrically driven from existing power (either diesel or natural
gas) for single-well injection systems or flows up to 5,000 bpd.18 For multiple well injection
systems, the filter feed pumps have natural gas driven motors.
• Injection Pump Feed Tank: After filtration, the produced water goes into an injection pump
feed tank. The capacity of the feed tank is flow dependent. For facilities processing less than
or equal to 1,000 bpd of produced water, a surge tank of 150 bbl capacity was included. This
translates into a minimum of 3.6 hrs of surge capacity for the design flow of 1,000 bpd. For
facilities processing more than 1,000 bpd but less than or equal to 5,000 bpd of produced water,
a surge tank of 1,000 bbl capacity was included. This translates into a minimum of 4.8 hrs of
surge capacity for the design flow of 5,000 bpd. For facilities processing more than 5,000 bpd
of produced water, a surge tank of 1,500 bbl capacity was included. This translates into 51
minutes of surge capacity for the design flow of 42,000 bpd [(1,500 bbl/42,000 bpd) x (24
hr/day x 60 min/hr)]. This assumption is consistent with the Walk-Haydel analysis hi which the
minimum capacity for the surge tank was assumed to be 3 minutes.19
• Injection Pumps: Injection pumps are positive displacement pumps capable of delivering the
required flow at 1,500 psig. Costs include the pump phis the motor, both skid mounted. Spare
pumps are not included because the results of the statistical analysis of the 1993 Survey show
that the majority of injection facilities in the coastal region (i.e., 58 %) do not use spare pumps.16
• Spare Wells: According to studies of producing areas of Louisiana and other areas in the U.S.
where injection wells are used to dispose of produced water, operators rarely go to the expense
of drilling a "spare" well to handle produced water when the primary disposal well is shut hi
for servicing.5-20 Instead, it is more typical for operators to respond by temporarily incurring
the costs associated with hauling produced water to commercial disposal facilities, or shutting
in the producing well(s) until the disposal well is brought back into service. If the production
facility is serving multiple wells, those with the highest water cut are more likely to be shut hi
for the duration of the injection well workover. Therefore, this analysis assumes that no spare
wells are needed.20
• Pump Engines: Injection pumps with capacities up to 500 bpd, or 12 hp, have electric motors.
For flows greater than 500 bpd, natural gas engines are used.18
• Power Generation: For electric pumps and instrumentation, no additional power generation
equipment is required. It is assumed that existing onsite power generation equipment can handle
XI-17
-------
the excess load of up to 25 hp. A regression analysis was performed to determine the
mathematical relationship between horsepower demand and produced water flow. The cutoff
produced water flow corresponding to 25 hp power requirement was 603 bpd, above which
additional power generation is necessary.
Injection Well Capacity: The average capacity for Gulf of Mexico injection wells, new or
converted, is 5,000 bpd. For flows greater than 5,000 bpd, the number of injection wells and
pumps was determined based on one injection well and one pump with a capacity of 5,000 bpd
for each 5,000 bpd of flow or portion thereof. For these cost estimates, an average injection
well capacity of 5,000 bpd has been selected based on information obtained from the 1993
survey of coastal oil and gas industry.16'21 Average injection well capacity is based on the
statistical analysis of the produced water flow data from facilities that currently inject produced
water. The statistical analysis, which took into account the effect of under utilization by spare
wells, showed that a typical injection well in the Gulf of Mexico has an average capacity of
5,000 bpd. The cost to drill an injection well is dependent on the required drilled depth, the
location of the well and to a lesser extent on the capacity of the well. Other information in the
record also supports a 5,000 bpd average injection flow rate.22-23
Average Injection Well Cost: EPA estimated, based on data obtained directly from operators,
that 90% of injection wells will be converted from previously producing wells and abandoned
wells. Ten percent will be newly drilled injection wells.24
The cost of a new well at facilities in the Gulf of Mexico region was escalated to 1995 dollars
using the ratio of 5471 (for 1995) to 4985 (for 1992) from the Construction Cost Index.13 The
1995 cost is estimated to be $329,250 for a new dedicated injection well. It has been noted that
the cost of drilling injection wells in the coastal Gulf of Mexico region does not appear to vary
significantly with well capacity for wells having the same depth.20 The cost of converting an
existing well to an injection well at facilities in the coastal Gulf of Mexico region was estimated
to be $263,400 (1995 dollars).6 Again, the well conversion cost does not appear to be affected
significantly by the injection capacity of the well.20
The average injection well cost was determined as follows:
Injection Well Cost = 0.9 x $263,400 + 0.1 x $329,250 = $270,000
The average injection well cost (i.e., average weighted cost of new and converted wells) is
$270,000 (adjusted to 1995 dollars).13
Platform/Concrete Pad Retrofit Cost: Platform costs were escalated to 1995 dollars using the
ratio of 5471 (for 1995) to 4985 (for 1992) from the Construction Cost Index equipment area
requirements. The retrofit costs were $82/ft (in 1995 dollars).25
Pipeline Cost: Pipeline costs are based on $12.74/in. of pipe diameter/ft. Although the same
Walk-Haydel report continues to be the source of the cost estimate factor, pipeline costs have
been escalated according to the appropriate year span of Construction Cost Indices.13-19 The
piping diameters used for calculating piping costs are as recommended in the Walk-Haydel
report and in engineering standards literature26 as follows:
XI-18
-------
Flows Pipe Diameter
up to 5,000 bpd 3-inch
5,001 up to 14,000 bpd 4-inch
14,001 up to 31,900 bpd 6-inch
31,901 up to 58,300 bpd 8-inch
58,301 up to 85,700 bpd 10-inch
85,701 up to 192,000 bpd 12-inch
• Average Pipeline Distance: The average pipeline distance from the separation/treatment
facility to the injection well is assumed to be 3,438 feet. This distance is five feet longer than
that listed in the Development Document for the proposed rule since it is based on the final
statistical analysis of the 1993 Coastal Oil and Gas Questionnaire as opposed to the preliminary
analysis.16-21'27
• Installed Costs: Equipment installation costs include the piping cost (15% of the purchase
cost), installation labor cost (32% of the purchase cost), and transportation cost (5% of the
purchase cost).6
• Additional Costs (Engineering, Contingency, and Insurance/Bonding Fees): These fees
were added to the equipment purchase and installation costs to develop actual capital costs.
These fees include all engineering design costs (10% of installed equipment cost), administrative
costs (4% of installed equipment cost), and any incidental costs incurred in the process of
purchasing and installing the equipment (15% of equipment installed cost).8
Table XI-7 presents the design capital costs for the selected design flows for production facilities
in the Gulf of Mexico coastal region.
3.2.2 Model Capital Cost Equations for Subsurface Injection
For the zero discharge via injection option, four independent linear cost equations were developed
for medium/large-volume facilities: two for single well injection systems (one capital cost equation and
one O&M cost equation) and two for multiple injection well systems. Again, single injection well systems
are assumed for operations with flows less than or equal to 5,000 bpd. Multiple injection well systems are
assumed for flows greater than 5,000 bpd. Table XI-8 lists the four cost equations.
The mathematical model best representing the relationship between design flow and design cost
for injection was found to be a line of the general form:
XI-19
-------
TABLE XI-7
CAPITAL AND O&M COST EQUATIONS FOR INJECTION OF PRODUCED WATER
AT MEDIUM/LARGE-VOLUME FACILITIES
Single - Well Injection Systems
Design Flow
(bpd)
200
500
1,000
5,000
Cost Equation
Capital Cost ($)
Design
453,789
456,032
475,701
602,186
Calculated
450,330
459,808
475,603
601,967
% Error
-0.76%
0.83%
-0.02%
-0.04%
444,012 + 31.59 x (flow)
O&M Cost ($)
Design
45,988
53,983
75,252
205,885
Calculated
46,085
56,090
72,765
206,168
% Error
0.21%
3.90%
-3.30%
0.14%
39,414 + 33.35 x (flow)
'•*•"*•,< -'»--. „ >* * JMiiltiptW Well Injection Systems, 'f , ," , ' • \* °: ~ '
Design Flow
(bpd)
10,000
18,000
30,000
42,000
Cost Equation
Capital Cost ($)
Design
1,025,405
1,881,955
2,646,805
3,794,079
Calculated
1,082,505
1,751,602
2,755,246
3,758,891
% Error
5.57%
-6.93%
4.10%
-0.93%
246,134 + 83.64 x (flow)
O&M Cost (S)
Design
411,029
768,651
1,235,611
1,777,276
Calculated
414,322
752,359
1,259,415
1,766,471
% Error
0.80%
-2.12%
1.93%
-0.61%
42.25 x (flow) -8,225
-------
TABLE XI-8
DESIGN CAPITAL COSTS (1995 DOLLARS) FOR PRODUCED WATER INJECTION
AT GULF OF MEXICO PRODUCTION FACILITIES
< ; ,-v-rlt- '-" ?:• >»***
*^f.-.s-> j* ,Jf « , •• •- •' f * <• ' ' f, "'
.;>;^rv*Co«jfotf||t« -;,,::,;:
.,"•'>,*'; -4,, - '-'" -*"'S- !-*!,f o
Injection Pumps
Feed Tank
Filters and Feed Pumps
Total Equipment Purchase Cost
Piping and Instrumentation (15%)
Labor (32%)
Transportation (5%)
Equipment Installed Cost
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Total Equipment Installed Cost
Platform Retrofit
(pumps, tanks, filters)
Pipeline Cost
Injection Well Cost
TOTAL CAPITAL COST:
f}f ,' , ; %<. f -
^$>f;t
5,158
13,719
2,927
21,804
3,271
6,977
1,090
33,142
3,314
4,971
1,326
42,753
9,635
131,400
270,000
453,788
v* ? 'f •' -. v ' *
.VjHMK?,!
5,912
13,719
3,296
22,927
3,439
7,337
1,146
34,849
3,485
5,227
1,394
44,955
9,676
131,400
270,000
456,031
,>„<•-', ^>,*
- '*?,,:"s^ --'
:::&&
15,259
13,719
3,813
32,791
4,919
10,493
1,640
49,842
4,984
7,476
1,994
64,297
10,004
131,400
270,000
475,701
*'Ws>i;^
J<5,0o1i,;i
47,543
14,816
6,209
68,568
10,285
21,942
3,428
104,223
10,422
15,634
4,169
134,448
66,338
131,400
270,000
602,186
IpsfcpltJ)'
^fWp'sf
95,086
14,816
12,420
122,322
18,348
39,143
6,116
185,929
18,593
27,889
7,437
239,849
70,356
175,200
540,000
1,025,405
,, ., , , » *
';;;l*t^
:!poo;.t=
190,172
19,975
24,840
234,987
35,248
75,196
11,749
357,180
35,718
53,577
14,287
460,763
78,392
262,801
1,080,000
1,881,956
< •$ * * ;• < ' t"
-'•>, if "<;-.•<
;;m?p?y
285,258
19,975
40,328
345,561
51,834
110,580
17,278
525,253
52,525
78,788
21,010
677,576
86,428
262,801
1,620,000
2,646,805
' * f 2 v ''?
'f , * -- •• ••-•
L«a»K*
427,887
19,975
63,560
511,422
76,713
163,655
25,571
777,361
77,736
116,604
31,094
1,002,796
98,482
262,801
2,430,000
3,794,079
-------
Y=mX + b
where: Y = design cost (either capital or O&M cost)
m = slope (X-coefficient)
X = design flow (in barrels per day)
b = Y-intercept (constant)
The constants (Y-intercept) and X-coefficients for each of the four equations were determined using
regression analysis with the "design" costs, and "calculated" costs are those generated by the model cost
equations for each design flow listed.14 The comparison of "design" to "calculated" costs shows an error
of no greater than ±7.0% for all systems.
Once the model capital and O&M cost equations were developed for all medium/large-volume
facilities, future flow rates were used to calculate facility-specific compliance cost estimates. The results
of these calculations are presented in Table XI-9.
3.2.2.1 Compliance Cost Methodology for Floras & Rucks, Inc.
A separate methodology was developed to estimate zero discharge compliance costs for Flores &
Rucks, Inc. Flores & Rucks submitted information in its comments on the proposed effluent limitations
which suggested its compliance costs might be significantly different than compliance costs for other
existing Gulf of Mexico operators due to size and other factors.12 These factors included operation of an
existing improved gas flotation system treating all Flores & Rucks' produced water, the presence of source
water* production and waterflooding operations, and its offshore/coastal production configuration. The
Flores & Rucks production configuration straddles the offshore and coastal subcategories. To support its
arguments that it should not be subject to zero discharge, Flores & Rucks provided EPA with highly
detailed technical and cost information regarding its production and produced water treatment operations.28
EPA also conducted a site visit to Flores & Rucks' East Bay field in December 1995.29
Description of Current Flores & Rucks' Operations
Flores & Rucks is a large and complex facility. Of the set of Gulf of Mexico facilities affected
"Source water" is the term used for subsurface waters produced from non-hydrocarbon bearing formations for
waterflooding purposes.
XI-22
-------
TABLE XI-9
GULF OF MEXICO FACILITIES CAPITAL AND O&M COSTS PRODUCED WATER ZERO DISCHARGE
VIA INJECTION (1995 DOLLARS)
3229-001 -3 Chevron Pipe Line Company
2963-006 Warren Petroleum Company
2071-004-1 Flores & Rucks, Inc. (a)
2400-001 Gulf South Operators, Inc.
2184-002-2 North Central
2184-003-1 North Central
2184-001 North Central
3407-001 Amoco
18,920
1,808
153,895
291
1,910
7,606
572
6,290
28,380.0
2,712.0
230,842.5
436.5
2,865.0
11,409,0
858.0
9435.0
2,619,754
529,687
14,431,657
457,802
534,520
1,200,350
471,117
1,035,250
791,233
99,712
7,932,898
49,120
103,114
313,164
58,491
257,557
TOTALS
191,292
$21,280,137 89,605,289
(a) Flores & Rucks costed at Case 2. Costs for Flores & Rucks may be considerably lower (see Section 3.2.2,2).
-------
by the coastal guidelines, eighty percent (80%) of the produced water is discharged from the Flores &
Rucks oil and gas production operation located in the East Bay area of the Mississippi River delta (see
Table XI-9). Flores & Rucks' production operations encompass both offshore and coastal subcategories,
extending about 40 square miles.12 Production (and therefore produced water) is predominately from
offshore subcategory wells, with some coastal subcategory production.30 Flores & Rucks currently
discharges to coastal waters, the Southwest Pass of the Mississippi River.
The Flores & Rucks production system gathers wellhead fluids (including liquid and gaseous
hydrocarbons and produced water) generated from wells in both subcategories into four centralized points,
as shown in Table XI-10. Production fluids from all of the coastal wells (with a single exception) are piped
directly to the Central Processing facility for initial hydrocarbon/produced water separation.
The three offshore FWKOb platforms listed in Table XI-10 handle production fluids from offshore
subcategory wells and one coastal subcategory well. Initial hydrocarbon/produced water separation takes
place offshore on the FWKO platforms. Following the initial hydrocarbon/produced water separation, all
four produced water streams are commingled prior to IGF treatment and discharge into the Southwest Pass
of the Mississippi River.
The East Bay field is waterflooded via a system of source water wells and injection wells. Source
water is produced, filtered, and injected into producing horizons for secondary hydrocarbon recovery. The
company does not currently utilize produced water from petroleum-bearing formations for waterflooding.12
All onshore subcategory facilities are required to comply with zero discharge. As early in the regulatory
process as the 1993 Survey, produced water was already utilized for secondary recovery in some Gulf
coastal operations.16'31 Flores & Rucks states its concern of technical difficulties (such as well plugging,
increased maintenance, and potential shortened disposal well life) which might be encountered if Flores
& Rucks attempted to inject untreated produced water.12 However, since Flores & Rucks already treats
all produced water with IGF, it may reasonably be expected that the treated produced water filtered and
given additional chemical treatments could be used in lieu of source water for waterflooding. In point of
fact, Flores & Rucks costed this scenario in its comments. The cost of mitigating potential technical
difficulties with injection of produced water (for disposal or for waterflooding) has been incorporated into
cost estimates by increasing expected compliance costs to include additional filtration, higher chemical
FWKO: Free Water Knock-Out
XI-24
-------
TABLE XI-10
FLORES & RUCKS OIL/WATER/GAS PROCESSING LOCATIONS
Produced Water Fadliiy
Central Processing
FWKO #1 Platform
FWKO #2 Platform
FWKO #3 Platform
Production Sufecategory
Coastal
Offshore and Coastal
Offshore
(except 1 coastal well)
Offshore
j Function " '" '; '
Oil/water/gas separation and processing;
produced water IGF treatment
Oil/water/gas separation and processing
OilAvater/gas separation and processing
Oil/water/gas separation and processing
costs, increased well backwash frequency, and doubled workover rates for all facilities (see Section 3.2).
Potential production benefits from the use of produced water injection as waterflood support has not been
credited against Flores & Rucks' compliance costs. Cost savings generated from shutting hi source water
production (such as fuel costs, well maintenance, and filter replacement) have also not been credited against
compliance costs for Flores & Rucks. Thus, these cost estimates are higher than might be experienced.
Potential Flores & Rucks Zero Discharge Compliance Strategies
Information acquired through the 1993 Coastal Oil and Gas Questionnaire and extensive industry
contacts indicate that Gulf of Mexico operators have used a variety of strategies to meet the zero discharge
requirement of the General Permits. In several cases, operators have combined outfalls and
drilled/converted wells for produced water injection for disposal.5'16'25'32-33'34'35-36 The 1993 Coastal Oil and
Gas Questionaire results indicate injection zones for produced water disposal are generally attainable hi
the Mississippi delta region at 2,500 to 3,500 feet, with an average disposal flow rate of 5,000 bpd
produced water.16 Information received since proposal regarding coastal Louisiana production fields
(Coquille Bay, Bayou de Fleur and Morgan City fields) demonstrate an average depth of 2,785 feet for
injection wells disposing an average of 5,812 bpd produced water.23 Operators of these fields indicated
that locating disposal zones able to accept 5,000 bpd produced water is not difficult hi the Gulf of Mexico
area. This information is strongly corroborative of the cost basis used in development of proposed
limitations. Further, this information suggests that the final rulemaking costs may be exaggerated by the
incremental cost to drill and complete deeper injection wells and because 16 percent more produced water
disposal capacity may be available per well than was used hi zero discharge compliance cost estimates.
X3-25
-------
Tlie availability of zero discharge of produced water for Flores & Rucks and other major pass dischargers
is demonstrated by the numerous facilities injecting produced water near the Mississippi River delta.37
In anticipation of a possible zero discharge limitation, some Louisiana companies have minimized
produced water volumes by segregating offshore-derived produced water. Where this occurs, offshore-
derived produced water is treated on offshore platforms and discharged under permit limits incorporating
Louisiana state water quality standards or the offshore guidelines.33-36
EPA has considered the range of available compliance strategies in development of the following
four zero discharge compliance scenarios for Flores & Rucks:
Case 1: All produced water (coastal- plus offshore-derived) is injected in dedicated
disposal wells.
Case 2: Some produced water is injected for waterflood; the remainder is injected in
dedicated disposal wells.
Case 3: Coastal subcategory produced water is disposed by injection in dedicated disposal
wells; Offshore-derived produced water is treated offshore and discharged off-
shore in compliance with state water quality standards and Offshore Guidelines.
Case 4: Coastal subcategory produced water is disposed entirely by waterflood injection;
Offshore-derived produced water is treated and discharged offshore in compliance
with state water quality standards and Offshore Guidelines.
In its comments on the proposed rule, Flores & Rucks suggested (and rejected as infeasible due
to high costs and possible strategic difficulties) an additional compliance strategy: treating the produced
water at the central facility IGF before pipelining the produced water into the offshore subcategory for
discharge in compliance with state water quality standards and the offshore guidelines.12 EPA estimated
costs for each Gulf of Mexico facility on the basis of this strategy. The cost estimation was performed to
determine whether the strategy might be a cost effective approach to compliance. EPA's analysis showed
that, except for Flores & Rucks, this strategy was more expensive than other alternatives and presented
other compliance difficulties. The capital cost estimates and discussion for the pipeline scenario are
presented in the technical support document.14
EPA selected Case 2 as the primary basis for its economic analyses because it is a reasonable
compliance scenario which is technically feasible economically comparable to Case 1, and which realizes
XI-26
-------
lower non-water quality environmental impacts than Case 1 (see Chapter XDI). Case 2 is based on
replacing source water as the waterflood fluid with treated produced water. Produced water is extensively
used for waterflooding at Alaska's North Slope, California and other onshore and coastal locations.16'21'31
Even in its own comments, Flores & Rucks presented a similar scenario costing injection of produced water
for waterflooding. Thus, it is reasonable to believe Case 2 is technically feasible.
3.2.2.2 Flores & Rucks Estimated Compliance Costs
Capital costs for each Flores & Rucks zero discharge case are the same as those developed for
other major pass dischargers presented previously in Section 3.2.2, except where different equipment was
required to fit the compliance strategy. Itemized costs showing the list of capital equipment are presented
hi Tables XI-11 and XI-12. Distinctions between these costs and those used for other coastal Gulf of
Mexico facilities are described in detail in the Technical Support Document.14
Capital costs are based on actual equipment design and cost data obtained from oil and gas
operators and equipment vendors. A cost analysis was developed for each produced water gathering
facility at Flores & Rucks (Table XI-12) before summing to arrive at its total East Bay costs. Flores &
Rucks' produced water flow rates are averages of LDEQ Discharge Monitoring Reports from calendar
years 1993, 1994 and partial year 1995." Equipment design flow is based on an assumed "future flow,"
calculated as 1.5 times the current average flow rate.7 Based on industry data, Case 1 assumes that 90
percent of the disposal wells would be converted idle production wells and 10 percent would be newly
drilled injection wells.3-16'21'24'38 Site-specific data from Flores & Rucks at the tune cost estimates were
developed indicated that ample wells are available for conversion, thus this is considered a conservative
estimate.14'39
Cases 3 and 4 offer significant cost savings compared to Case 2 and indicate that Flores and Rucks'
true costs for complying with zero discharge limitations may be much lower. Because of these cost
savings, Cases 3 and 4 are more likely to be implemented for compliance with zero discharge. However,
Cases 3 and 4 have uncertainties in the cost estimating with regard to specific platforms and what would
actually be required to structurally modify them for installing treatment equipment used to comply with
offshore BAT requirements. By basing costs on a higher cost compliance scenario, EPA has based its
decision-making on a conservative cost estimate.
XI-27
-------
TABLE XI-11
FLORES & RUCKS PRODUCED WATER
COMPLIANCE COST SCENARIOS (1995 dollars)
COASTAL INJECTION , V "- ^ - ° "" "^4
Capital Costs ;" ',< "•.::***; " f"^ <* /
Produced Water New Injection Well Volume (bpd)1
Injection Pumps
Surge Tank
Filters and Feed Pumps
Total Equipment Cost:
Piping (15%)
Labor (32%)
Transportation (5%)
Subtotal:
Engineering (10%)
Contingency (15%)
Insurance/Bonding(4%)
Subtotal:
Platform Space:
Pumps
Filters
Pipeline Cost:
Disposal Well Pipe
Waterflood Well Pipe
Subtotal
Injection Well Number
Injection Well Cost
COASTAL CAPITAL COST
Offshore volume (bpd)
OFFSHORE CAPITAL COST
TOTAL CAPITAL COST
^ .•»
COASTAL INJECTION " < ? *• >^ ,' " -'
O&MCosts s s* 4 ^3,
v VWSh. . •« X •> S
Labor
Pump Fuel Cost
Maintenance
Cartridge Filter Replacement
Produced Water Treatment Chemicals
Injection Well Backwash
COASTALO&MCOST
OFFSHORE GAS FLOTATION' ,™ -"ll ' ' ^ "v --
O&M Costs -", -,„,,;, ^ 'L,^;,**^,
OfTshore labor
Standard O&M(10%)
OFFSHORE O&M COST
TOTAL O&M COST
*" "* y ^ f
Cas-fel.. tt , f .}
230,843
2,234,521
0
363,968
2,598,489
389,773
831,516
129,924
3,949,703
394,970
592,455
157,988
5,095,117
150,306
38,540 •
1,576,804
0
6,860,768
47
12,690,000
$19,550,768
0
0
$19,550,768
< / \
1,619,089
1,163,625
129,924
421,288
5,687,394
523,345
$9,544,666
1 ' , \ ' '" i „ '
"wl-, " s- - 'i "a >',, v '
0
0
$0
$9,544,666
. •: /' "- "
'f - ^ ' J$we\
184,670
1,759,091
0
363,968
2,123,059
318,459
679,379
106,153
3,227,050
322,705
484,057
129,082
4,162,892
118,326
38,540
1,314,004
4,678,128
10,311,892
37
9,990,000
$20,301,892
0
0
$20,301,892
"
< < x
f j
1,274,602
941,000
106,153
421,288
5,687,394
935,340
$9,365,778
' ••'•' ' ' "^
"' * '\ -' s' £''
0
0
$0
$9^65,778
a) Future produced water volumes are used for equipment design. Future flow equals 1.5 times current flow.
XI-28
-------
TABLE XI-12
FLORES & RUCKS PRODUCED WATER
COMPLIANCE COST SCENARIOS (1995 dollars)
b&MAU&Ecoow ~* %' *
Capital Cos^s - ,,,,,,.. , ^ , -
Coastal Ihj. PW Volume (bpd),(a)
Injection Pumps
Surge Tank
Filters and Feed Pumps
Total Equipment Cost:
Piping~(15%)
Labor (32%)
Transportation (5%)
Subtotal:
Engineering (10%)
Contingency (15%)
Insurance/Bonding(4%)
Subtotal:
Platform Space:
Pumps
Filters
Pipeline Cost
Disposal Well Pipe
Waterflood Well Pipe
Segregation Cost (b)
Subtotal
Injection Well Number
Injection Well Cost
COASTAL CAPITAL COST
ONSHORE GAS ECQTAMON
CapitatCosts , ,, , , ,
Average PW Volume (bpd),(a)
Gas Flotation
Generator
Feed Pumps
Total Equipment Purchase Cost
Piping & Instrumentation (15%)
Discharge Piping
Installation (32%)
Equipment Installed Cost
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Total Equipment Installed Cost
Satellite Platform
OFFSHORE CAPITAL COST
TOTAL CAPITAL COST
C,OA5TAl,tK»ECnON ~
O&MCoSts ,, ,,,
Labor
Pump Fuel Cost
Maintenance
Segregation O & M
Cartridge Filter Replacement
Produced Water Treatment Chemicals
Injection Well Backwash
COASTAL O & M COST
OFFSHORE GAS.FL0TATjrON
O&MCssts y- , K >
StandardO&M(10%)
Offshore labor
OFFSHORE O & M COST
TOTAL O&M COST
, ,, '
, -,,.i' ,'," £?*e3 ,,,
45,057
427,077
0
69,696
496,773
74,516
158,967
24,839
755,095
75,509
113,264
30,204
974,072
31,980
7380
525,601
0
780,000
2319,034
9
2,430,000
$4,749,034
'- ", i^kbgt '"
/-.Platform
68,576
206,238
176,896
36,125
419,259
62,889
72,557
134,163
688,868
68,887
103,330
27,555
888,639
122,229
$1,010,868
$8,729,164
" , " ; ' , -,
' ^ ,
310,038
222,825
24,839
78,000
82,229
1,110,092
100,215
$1,928,238
""""'"'•FWK.Qifff
' Piatfotm
88,864
42,705
$131,569
$2323,215
,
'
•pvfKom
PlMforw ,
24,878
143,220
80,448
19,476
243,144
36,472
0
77,806
357,422
35,742
53,613
14,297
461,074
296,730
$757,804
% \ % -.
.. •••• ' *
FWEQS2
Platform"
46,107
42,705
$88,812
' , t i ••.' % - PAtfbon. '" '
131,891
42,705
$174^96
, , ',
, C,ase4
45,057
0
0
69,696
69,696
10,454
22303
3,485
105,938
10,594
15,891
4,238
136,660
31,980
7,380
0
4,678,128
780,000
5,634,148
0
0
$5,634,148
'- ' fwf/wfi
,PJatfotm
68,576
206^38
176,896
36,125
419,259
62,889
72,557
134,163
688,868
68,887
103330
27,555
888,639
122,229
$1,010,868
$9,614,278
^ ,
t V
0
22,475
0
78,000
82,229
1,110,092
512,210
$1,805,006
BMCOSI
, v , , Platform.' '
88,864
42,705
$131,569
$2,199,983
-i" - -^
, •• ,« ,
•Bwko#2? -
Platfonn
24,878
143,220
80,448
19,476
243,144
36,472
0
77,806
357,422
35,742
53,613
14,297
461,074
296,730
$757,804
- - 5 A
-
,FWKO#2
Platform
46,107
42,705
$88,812
'V. Trf,
"* t -V
&n&ai& "
Platform
92,332
341,439
242,746
49,523
633,708
95,056
90,862
202,787
1,022,413
102,241
153,362
40,897
1,318,912
892,545
$2,211,457
,,
•. -v
.. " ,r ••
Platfom
J31.891
42,705
$174,596
Future produced water volumes are used for equipment design. Future flow equals 1.5 times current flow.
Coastally generated fluids costed for segregated oil/water separation at FWKO #1. After separation the produced water fraction goes through existing pipeline to
the Central Facility for treatment and injection.
XI-29
-------
As discussed above, by developing compliance costs using the total produced water flow at the
facility, EPA has unnecessarily included compliance costs for that 20 percent of produced water derived
from coastal subcategory wells. Since this produced water is required to comply with EPA Region 6 zero
discharge requirements by January 1, 1997, it is reasonable to reduce the total facility costs developed by
EPA by 20 percent. In doing so, the capital costs for Case 2 are reduced from $20.3 million to $16.2
million, and the O&M costs are reduced from $9.4 million per year to $7.5 million per year. Since the
volume of coastally-derived produced water is equal to that volume assumed under Case 2 to be injected
into waterflood wells, the cost for waterflood pipeline is appropriately due to existing permit requirements
and not the coastal guidelines. A review of the Case 2 capital costs shows that by eliminating the
waterflood well pipeline cost, a savings of more than 20 percent of the total costs is achieved. In addition,
since filtration system costs and produced water treatment chemical costs are based on total facility flow,
these costs should also be reduced by 20 percent, thus realizing more than 20 percent reduction in total
costs by excluding costs attributable to existing permit requirements for the coastally-derived produced
water. The other cases for FRI are similarly over-estimated because they include costs attributable to
coastally-derived produced water.
Subsequent to development of compliance cost estimates, on August 5, 1996, EPA received
comments and information from Hores & Rucks that presented additional cost information.40 This
information was submitted very late in the regulatory process, over 14 months after the close of the
comment period (initially established as May 1995 in the Federal Register notice, later extended to June
1995). These late comments are discussed in the Response to Comments document.42
3.2.3 Gulf of Mexico Baseline Options 2 and 3 O&M Cost (Zero Discharge by Subsurface
Injection)
Design O&M costs for produced water injection are presented in Table XI-9, with Flores & Rucks
under compliance Case 2. The bases for the design O&M costs for injection are presented hi Table XI-13,
as follows:
Labor: Labor costs are based on an hourly rate of $39.00 per hour (1995 dollars). This is an
increase from $20 per hour which was used in the proposal compliance cost estimates. Bureau
of Labor Statistics data and information from commenters and other operators support the
increase to $39.00 per hour.15 Labor is estimated at 2 person-hours per day for the operation
of single-well injection systems. Labor costs for multiple-well injection systems are based on
2.42 person-hours per day.16
XI-30
-------
TABLE XI-13
DESIGN O&M COSTS (1995 DOLLARS PER YEAR) FOR PRODUCED WATER INJECTION
AT GULF OF MEXICO PRODUCTION FACILITIES
„ >"-> . ,, f/1 * t"i'(, C\J ! - *,'•*•> f,f-.'"
' '-' ,,^r~;!£feiftCowiid«lfcrti' » . o- '-,
Labor
Pump Fuel Cost
Maintenance Materials (5%)
Cartridge Filter Replacement
Produced Water Treatment Chemicals
Injection Well Backwash
TOTAL O&M COST:
;s& ?£.?A>-lv. £.J:U* £H -; -* -l^feidj Ff; ' : ' • ' H^«^S1;i;*:^H* ': '• ;::;
*,U.*5-«%
:!;:»:
28,470
0
1,090
365
4,928
11,135
45,988
, < - >, v y '•„ i
t'"':*Ki
28,470
0
1,146
913
12,319
11,135
53,983
^WS^ "••
W -.-V -^ A
28,470
7,545
1,640
1,825
24,638
11,135
75,253
*' s;oi»olV't
28,470
30,539
3,428
9,125
123,188
11,135
205,885
UVjfc&itr)t
56,940
61,078
6,116
18,250
246,375
22,270
411,029
;', :i8,o'0f:s;,
113,880
122,157
11,749
32,850
443,475
44,540
768,651
:^3«)KY:'
170,820
186,828
17,278
54,750
739,125
66,810
1,235,611
-,5-J42Mf;;',
256,230
283,835
25,571
76,650
1,034,775
100,215
1,777,276
-------
• Fuel: Fuel cost was calculated based on the maximum pumping horsepower required above 25
hp, continuous operation (365 days per year), and a natural gas unit cost of $2.50 per 1,000
cubic feet.6-16 Information obtained from the Department of Energy confirms gas unit costs have
dropped and recovered since proposal.43 Thus, proposal natural gas costs are used herein.
• Maintenance Materials: Maintenance materials represent 5% of the equipment purchase cost.
• Cartridge Filter Replacement: The cost to replace filters within the cartridge filtration system
were not included in the 1995 Coastal Development Document and were added to the current
list of O&M costs as $0.005/bpd.44 Cost of replacement was based on vendor quotes and
industry comments on frequency of replacement as a function of produced water flow.44
• Chemicals: Total chemical cost for treating produced water for injection is $24.6375/yr (in
1995 dollars) multiplied by the daily flow rate in barrels.44
• Well Backwash: The well backwash unit cost rate was based on the results of the statistical
analysis of the 1993 Coastal Oil and Gas Questionnaire. Well backwash cost is $11,135
(adjusted to 1995 dollars) per job.16 In response to comments received on the proposed
mlemaking, the backwash frequency has been increased from bi-annually in the proposal (based
on the statistical analysis of the 1993 EPA Coastal Oil and Gas Questionnaire),16 to once per
year in this analysis.
As discussed in Section 3.0, EPA based capital costs on assuming future produced water flow 1.5
times the current flow. O&M costs estimate first year expenditures, which may be expected to rise as
produced water flow rates increase. This future escalation in O&M costs due to produced water flow
increases is addressed in the economic impact model.2
4.0 COOK INLET COMPLIANCE COST METHODOLOGY
EPA determined that oil and gas are produced from 13 of 15 existing platforms in Cook Inlet.
Two platforms are shut in. Eight platforms pipe the production fluids (oil, gas, and water) to three shore-
based facilities for separation and treatment. Produced water from the three shore-based facilities is
discharged to Cook Inlet after treatment. The remaining five platforms separate and treat the production
fluids at the platform. Produced water from each of the five platforms is discharged directly overboard
after treatment. Facility-specific information such as the average daily produced water flow and current
treatment technology employed was evaluated for each facility and compared to the treatment technology
required for complaince with each of the regulatory options. Incremental capital and O&M costs were
estimated specifically for each discharging facility.
Costs for each option were developed separately for the three shore-based facilities and for the five
platforms that discharge overboard, as presented in Table XI-14. The following sections present the
XI-32
-------
TABLE XI-14
SUMMARY CAPITAL AND O&M COSTS FOR
COOK INLET PRODUCED WATER BAT OPTIONS
' ; '-. « i
- , „ '•-"•-, - « '-' '* - , -•>-
..V/ " tWBftf -» * '---- ' ::
',-:,*'. - .*• A 6r , "-; '"';-
o,.*;; .;. >>yform; ;-\- ;-n- :*
,'*,',- ,^,, -,- /'" - -';-' ' v ,,,-\-' ' ",'•
Trading Bay Production Facility
Granite Point Treatment Facility
East Foreland Treatment Facility
Anna
Dillon
Bruce
Baker
Tyonek
TOTAL
' '< » , Options 1 and 2
• *- .,' /ImprdyedOpeicationQf, / •
'*- , *;;* ' 6as'pi8«forii|; -;>•""- ,
% 'Capital Caste
--: aw5$) -'•;•.
0
1,297,003
1,297,003
1,713,256
1,914,317
1,297,626
1,713,256
0
9,232,461
> O&M Costs
,-_ a«i?S$/yr>- -;
245,579
129,700
129,700
171,326
191,432
129,763
171,326
0
1,168,826
*'\ ' * " '"' Option3i '" ; '''.-,,
- t°< Subsurface Injection '• "\
-: * Capifal Costs:*,
;,% (199^$) ' \
51,117,826
5,603,072
24,045,167
2,195,407
2,396,472
4,592,766
2,195,407
4,809,976
96,956,093
, -O&MCo^ts, -
0995 Sfo#"
15,183,281
556,615
2,742,016
393,459
693,719
445,857
644,658
301,363
20,960,966
E
-------
detailed methodologies used to calculate the produced water regulatory compliance costs based on
improved gas flotation (Options 1 and 2) and subsurface injection (Option 3).
Table XI-15 lists the produced water treatment equipment known or assumed to be currently
present at the Cook Inlet operations. In the cost analysis, no costs were added for the equipment listed hi
Table X3-15. Capital costs were incurred only for the incremental equipment required to treat and/or inject
produced water according to the options described in Section 2.0. Table XI-15 lists only the platforms for
which costs were incurred. Monopod, Steelhead, Granite Point, Spurr, and SWEPI "A" are projected to
incur no costs due to the final rule. Produced water from Monopod and Steelhead goes to the Trading Bay
Production Facility (TBPF) and is not returned to those platforms for injection (see Table F/-3) for the
current locations of produced water discharge). Granite Point pipes produced water to Granite Point
Treatment Faculty and does not treat or inject produced water onsite. Spurr platform is currently shut in.
Because the volume of treated produced water from the East Foreland treatment facility is less than the
waterflooding demand at both SWEPI "A" and "C" platforms, only SWEPI "C" incurred injection costs.
The following sections present lists of incremental equipment that was included in the capital cost analysis
as needed for each platform and treatment facility.
4.1 COOK INLET OPTIONS 1 AND 2 COMPLIANCE COSTS (IMPROVED OPERATION OF GAS FLOTATION)
The technology basis for Options 1 and 2 is treatment of produced water with gas flotation under
improved operating conditions. For those platforms or facilities that do not have gas flotation units, the
installation of new flotation units was assumed necessary in the analysis to achieve compliance with the
limitations of Options 1 and 2.
Of the three onshore treatment facilities, Granite Point and East Foreland were assumed to require
additional gas flotation equipment. No capital costs were assigned to the Trading Bay Production Facility
due to the presence of existing gas flotation equipment, although such costs were estimated hi order to
calculate O&M costs for operating a gas flotation unit at this facility, since O&M costs are based on capital
costs.
Of the five platforms that currently discharge produced water, only Tyonek platform is equipped
with gas flotation units. For Options 1 and 2, the Tyonek platform did not incur any compliance costs.
The other four dischargers (Dillon, Bruce, Anna, and Baker) were assumed to require gas flotation units.
XI-34
-------
TABLE XI-15
EXISTING EQUIPMENT AT SELECTED
COOK INLET TREATMENT FACILITIES AND PLATFORMS45
Facility or Flatf&rnt
si V.* -. •. V.-.
•,-,•• v. "• _, v, "• •• s s(l>t>1
Trading Bay
Production Facility
Granite Point
Treatment Facility
East Foreland
Treatment Facility
King Salmon
Grayling
DoUy Varden
Spark
SWEPI "C"
Dillon
Bruce
Anna
Baker
Tyonek "A"
Basic Gravity •;
1 Separation'0 "
"Equipment'" %
/
/
/a
/
/
/
/
/
/
/
/
/
/
5-' -Return- - -"
Pipeline from
Facility to
" Platform :...
/
- - --Gas 5
,Poia&m =
/
/
Granular '
Filtration ,
/
/
/
/
/
/
/
/
/
Injection
Wells and
- Associated - -
Equipment
/
/
/
/
The current treatment equipment at East Foreland Treatment Facility consists of basic separation, skim tanks, and a
corrugated plate interceptor.4*
4.1.1 Cook Inlet Options 1 and 2 Capital Cost Estimates
Tables Y through EE in Appendix XI-1 present the detailed capital costs developed for Options
1 and 2 for each discharging Cook Inlet facility and platform. Capital costs were adjusted from 1992
dollars to 1995 dollars using the Engineering-News Record Construction Cost Index (ENR-CCI) ratio of
XI-35
-------
5471/4985 (1.0975).13 It is important to note that because O&M costs for Options 1 and 2 are calculated
as 10 percent of the capital costs, and because the Trading Bay Production Facility has existing gas flotation
equipment, the capital costs for the Trading Bay Production Facility in Table Y were developed only to
determine the incremental O&M costs due to operating improved gas flotation. Table XI-16 lists the
summary capital and O&M costs for all facilities and platforms included in this analysis.
The following bases were applied to the capital cost analysis for the three onshore treatment
facilities and the four platforms included in the gas flotation compliance cost analysis (see Appendix XI-1
for details):
Materials and Equipment: The equipment purchase cost for all production facilities includes:
gas flotation skid-mounted, complete electrical systems, oil and water outlets brought to the
edge fo the skid, and sufficient instrumentation for proper operation. Available gas flotation unit
sizes include 1,000 bpd, 5,000 bpd, 10,000 bpd, and 40,000 bpd.1 The size of the equipment
varies with flow.
Most gas flotation units were sized assuming a peak produced water flow of 2.3 times the
average produced water flow of each production facility.47-48
Piping and Instrumentation: Piping and instrumentation costs were assumed to be 15 % of the
equipment purchase cost. This cost includes any additional valves, fittings, piping, cables,
conduits, instrumentation, and instrumentation wiring (see Section 3.1.1.1).
Geographic Area Multiplier: Total equipment costs were multiplied by a "geographic area
multiplier" of 2.O.1 This factor is the ratio of the equipment installation costs in a particular
region compared to the costs for the same equipment installation hi the Gulf of Mexico region.
Installation Costs: Installation costs added to the three onshore facilities are equal to the total
materials and equipment (M&E) costs. Installation costs added to the platforms are 2.5 times
the M&E costs.9
Main Equipment Building: The main equipment building was added to Granite Point and East
Foreland treatment facilities to house the additional gas flotation and associated equipment. This
cost was not added to the TBPF for Options 1 and 2 because TBPF's capital costs were used
only to estimate O&M costs associated with the use of gas flotation equipment. The cost for
this building was estimated by Cook Inlet operators.49 The cost was $325,532 in 1995 dollars.48
Platform Modification Cost: Platform modification costs were added to the four platforms to
accommodate space requirements for the gas flotation equipment. The square footage required
is: 112 square feet for a 1,000 bpd unit; 210 square feet for a 5,000 bpd unit; 266 square feet for
a 10,000 bpd unit.1 The cost for additional platform space50 was adjusted to $658.5 per square
foot in 1995 dollars using the ENR-CCI ratio of 5471/4985 (1.0975).13
XI-36
-------
TABLE XI-16
CAPITAL AND O&M COSTS FOR GAS FLOTATION
(OPTIONS 1 AND 2)
PER COOK INLET FACILITY/PLATFORM
•*
Category ' *
ff -. f •*•'' j > %
1. Capital Cost ($)
Installed Equipment
Main Equipment
Bldg.
Engineering (10%)
Contingency (15%)
Ins.-Bonding (4%)
Platform Modifica-
tions
Total Capital Cost
2. O&M Cost
($/yr)
, "' \ ' ' -.
Trailing Bay'
0
0
0
0
0
0
0
245,579
" '•'"-, ",
. Granite Pt,"
679,897
325,532
100,543
150,814
40,217
0
1,297,003
129,700
- - , / tmnw oft
' Ei Fortrand" -<
679,897
325,532
100,543
150,814
40,217
0
1,297,003
129,700
WschargingFaci
',,Annalry
1,189,820
0
132,811
199,216
53,124
138,285
1,713,256
- 171,326
IKies or Platfoei
- ''';Dffl»n** *
1,308,807
0
148,396
222,595
59,358
175,161
1,914,317
191,432
?'
««*"*"!*
- Brn'ct11"- -
932,159
0
100,591
150,887
40,237
73,752
1,297,626
129,763
; . -. •• , '*
Baker* * •
1,189,820
0
132,811
199,216
53,124
138,285
1,713,256
171,326
, -
.- , tyonek11' •
0
0
0
0
0
0
0
0
* ,/ <•
GfaAdTotoJ,,
5,980,400
651,064
715,695
1,073,542
286,277
525,483
9,232,461
1,168,826
E
-4
a Shore-based treatment facility
b Platform
-------
Additional Costs (Engineering, Contingency, and Insurance/Bonding): These fees were
added to the equipment costs to develop actual capital costs. These fees include all engineering
design costs, administrative costs, and any incidental costs incurred in the process of purchasing
and installing equipment.1
4.1.2 Cook Inlet Options 1 and 2 Operating and Maintenance Costs
All O&M costs for Options 1 and 2 were calculated as 10 percent of the capital costs. This
percentage is commonly used for estimating O&M costs in process industries, and is within the range of two
to 11 percent cited in the literature.51 These O&M costs include labor, maintenance, spare parts, and standard
treatment chemicals.9 Table XI-16 lists the O&M costs calculated for all facilities and platforms included
in this analysis.
4.2 COOK INLET OPTION 3 COMPLIANCE COSTS (ZERO DISCHARGE BY SUBSURFACE INJECTION)
This option is based on the injection of produced water into available subsurface formations. For
Cook Inlet facilities, if zero discharge were required, the least costly basis for compliance would be to inject
produced water into production zones as part of the ongoing waterflood operations or into dedicated disposal
wells where waterflooding operations do not exist The substitution of produced water for the seawater that
is currently used in Cook Inlet waterflood operations was included in EPA's analysis for two reasons:
1) using existing injection technology results in significant cost savings over the purchase of new equipment,
and 2) concerns regarding limited available geologic formations for produced water disposal.49'52 In
particular, injection of produced water at the onshore treatment facilities is not technically possible because
the geology of the underlying formations cannot accept the large volumes of produced water that must be
disposed.49-53 In Cook Inlet, unlike states along the Gulf Coast, only the production formation is generally
available for injection. For platforms that pipe produced fluids to shore for separation and treatment, Option
3 assumes that the produced water is piped back to selected platforms for injection as part of the waterflood
operations. This assumption is based on information provided in the Marathon/Unocal report which asserts
that piping produced water back to the platforms "is considered the most viable" injection scenario.49 For
platforms that separate and treat at the platform, Option 3 assumes that the produced water is injected into
production zones as part of the waterflood operations or requires that disposal wells be installed. Two
platforms, Bruce and Tyonek, do not have waterflooding operations and therefore incurred costs for disposal
wells and injection equipment under this option. In addition, Spark has waterflooding equipment that is not
currently in use, and so incurred costs for the recompletion of service wells for produced water disposal.
XI-38
-------
Table XI-17 presents an inventory of the incremental equipment added and modifications made to
the treatment facilities and platforms as needed to comply with Option 3. These are general equipment
categories; specific items and capital costs are detailed in the technical support document.48
To allow for the continuance of waterflooding and to prevent long-term damage to the injection
wells and reservoirs, produced water must be treated for removal of oil and grease and total suspended solids
(TSS). Compliance costs were estimated assuming that gas flotation and multi-media filtration is the
treatment train necessary to pretreat produced water for injection.48
EPA reviewed the effects of produced water injection and concluded that downhole problems such
as calcium carbonate scale precipitation and bacterial growth can be mitigated through the use of proper
operating procedures.46 These procedures consist of pretreatment of the produced water for oil and grease
and TSS, and continued chemical treatment of the injection stream. The proper usage of scale inhibitors can
minimize scale deposits in the injection equipment, tubing flow lines, and injectors. The usage of biocides
can minimize bacterial growth, thus reducing the formation of hydrogen sulfide. In addition to chemical
treatment, annual well workovers can minimize scale build-up. Therefore, the cost analysis presented herein
includes separate O&M costs for standard O&M activities (i.e., 10 percent of capital costs for standard labor,
maintenance, spare parts, and treatment chemicals) as well as "additional" treatment chemicals and well
workovers (see Section 4.2.2).
To manage the increase in filter backwash due to the pretreatment of produced water prior to
subsurface injection, a centrifuge was added to every location that filters produced water, as well as
additional O&M costs for the transport and disposal of the dewatered backwash sludge. These costs are
presented in Sections 4.2.1 and 4.2.2.
4.2.1 Cook Inlet Option 3 Capital Cost Estimates (Subsurface Injection)
Tables A through K in Appendix XE-2 present the detailed capital costs developed for Option 3 for
each of the three onshore treatment facilities and the 10 platforms included in the zero discharge
compliance cost analysis. Table XI-18 presents the summary capital and O&M costs for all facilities and
platforms included in this analysis. Assumptions regarding standard equipment and costs, including the
geographic area multiplier, installation, main equipment building, and fees for engineering, contingency,
and insurance/bonding were also included in the capital cost analysis for Option 3. These assumptions are
XI-39
-------
TABLE XI-17
SUMMARY OF EQUIPMENT AND MODIFICATIONS ASSUMED NECESSARY
FOR COMPLIANCE WITH OPTION 3: ZERO DISCHARGE VIA INJECTION
Facility or Platform
Trading Bay Production
Facility
Granite Point Treatment
Facility
East Foreland Treatment
Facility
King Salmon
Grayling
Dolly Varden
Spark
SWEPI *C"
Dillon
Bruce
Anna
Baker
Tyonek "A"
Return Pipeline
from Facility to
Platform
/
/
Connecting
Return Pipeline
at Platform
/
/
/
/
/
Gas
Flotation
/
/
/
/
/
/
Granular
JWration
/
/
Filtration
Backwash
Centrifuge
/
/
/
/
/
/
/
/
/
/
Injection Wells
and Associated
Equipment
/
/
/
-------
TABLE XI-18
CAPITAL AND O&M COSTS FOR OPTION 3
PER COOK INLET FACILITY/PLATFORM
-I,,.-,,,--.! ,-<.<-, •.«, » » »
'" -,-, HV-- ,»„,,«; •-•
", *"* Cat6goty; - 1'' '
CAPITAL COSTS
Installed Equip.
Main Building
Engineering (10%)
Contingency (15%)
Ins. + Bonding (4%)
Pipeline
Platform Modification
Injection Equipment
Injection Well
Total Capital Cost
O&M COSTS
Standard O&M
Well Workover
Treatment Chemicals
Filtration O&M
Total O&M Costs
- ,•: }> ,• ,tf ' >>*•
' ^Trading Bay-'
FridtictiofWiof''-
9,862,859
325,532
1,018,839
1,528,259
407,536
33,143,900
4,830,901
0
0
51,117,826
5,111,783
2,400,000
4,611,467
3,060,031
15,183,281
<,„>*<**"
' Granite Point :
'.TfialFac!'* >
1,993,878
325,532
231,941
347,911
92,776
0
1,058,958
70,451
1,481,625
5,«03,072
405,100
100,000
30,966
20,549
556,615
4:'-~»-, <• - -n
-; - - < i-
*-E.-Fordai|-|i*>
5,416,656
325,532
574,219
861,328
229,687
15,297,055
1,340,690
0
0
24,045,167
2,404,517
100,000
140,000
97,499
2,742,016
^ , '$*<•• * \ t /,
•-.', «*•*•> ~« ^ ^ v, < * '
^"BUtoafv
1,682,569
0
168,257
252,385
67,303
0
225,958
0
0
2,396,472
239,647
100,000
103,867
250,205
693,719
^ >•;•••• <> '
•*• ,-*, v ^ ^ '"' <>
' 'Brutfe''' ! "
1,305,920
0
130,592
195,888
52,237
0
95,140
185,194
2,627,795
4,592,766
177,978
100,000
3,966
163,913
445,857
'*,*"*'•,", 3 ,->
su/,*. .-^.;
Biker- "*
1,563,581
0
156,358
234,537
62,543
0
178,388
0
0
2,195,407
219,541
100,000
195,433
129,684
644,658
* % <• -. -. > "• > ^
' "-' Tyonet " " "
1,284,652
0
128,465
192,698
51,386
0
339,786
185,194
2,627,795
4,809,976
199,699
100,000
1,000
664
301,363
^ ^; -..«• v$ -$ f '••
V ^ ", * & ;, V^
>>iTOTAL^'(
24,673,696
976,596
2,565,029
3,847,543
1,026,011
48,440,955
8,248,209
440,839
6,737,215
96,956,093
8,977,804
3,100,000
5,131,132
3,752,030
20,960,966
a) Costs in this column includes combined capital and O&M costs for TBPF, King Salmon, Grayling, and Dolly Varden platforms.
b) Costs in this column includes combined capital and O&M costs for Granite Point treatment facility and Spark platform.
c) Costs in this column includes combined capital and O&M costs for East Foreland treatment facility and SWEPI "C" platform.
-------
presented in Section 3.1.1 under the gas flotation capital costs analysis. Additional assumptions developed
specifically for the Option 3 analysis are as follows.
4.2.1.1 Return Pipeline from Facility to Platform
Of the three onshore treatment facilities, Trading Bay and East Foreland incurred costs for
pipelines to return produced water to selected platforms for injection. The Granite Point facility has an
existing return pipeline to Spark platform where all the facility's produced water is currently discharged.
Thus, no capital costs related to a return pipeline were incurred by the Granite Point facility. As presented
in the Marathon/Unocal report, Trading Bay is assumed to return treated produced water to King Salmon,
Grayling, and Dolly Varden platforms.15 Based on industry information, each of the three 8-inch pipelines
is determined to be 6.5 miles long.49 The Marathon/Unocal pipeline cost estimates, also used in this
analysis, include pipeline and riser material costs, pipe laying costs, mobilization/demobilization costs, and
project management costs. The specific total pipeline cost cited in the Marathon/Unocal report was
$31,562,519 (1993 $). The cost per foot of pipeline is $306.55 (1993 $). The pipeline cost hi 1995 dollars
for TBPF is $33,143,900 or $321.91 per foot using an ENR-CCI ratio of 5471/5210. Applying this cost
per foot to the nine miles of pipeline assumed to connect the East Foreland facility to the SWEPI "C"
platform, a pipeline cost of $15,297,055 (1995 $) was incurred.
In addition to pipelines, TBPF and East Foreland incurred costs for equipment associated with the
pipeline, as presented in the Marathon/Unocal report.* The assumptions used to develop these costs are
as follows:
* Shipping pumps were included, one per pipeline plus one spare. For TBPF, four pumps were
included; for East Foreland, two pumps were included. Each pump is rated for 1460 gpm at
700 psig with a 1000 hp motor.49 The pump costs which were originally presented to 1993
dollars were adjusted to 1995 dollars using the ENR-CCI ratio of 5471/5210.
• One booster pump was included for each pipeline: three pumps for TBPF and one pump for
East Foreland. Booster pumps are required to pump the water from storage tanks to 150 psig
to satisfy the net positive suction head of the shipping pumps. Each pump is rated for 2120 gpm
at 150 psig with a 300 hp motor.49 The pump costs which were originally presented hi 1993
dollars were adjusted to 1995 dollars using the ENR-CCI ratio of 5471/5210.
The Marathon/Unocal report presented three zero-discharge compliance cost scenarios, including 1) piping treated
produced water from TBPF to three Cook Inlet platforms for waterflooding operations, 2) installing hydrocyclones
at the platforms for onsite treatment prior to injection, and 3) installing injection wells at 1BPF,49 The report stated
that the first scenario was "the most technically viable re-injection alternative," citing technical limitations of tire
other two alternatives. EPA selected the first scenario as the basis for its analysis.
XI-42
-------
• All motors are electric. Electricity for these motors is supplied by a natural gas driven
generator. The cost of the power generation equipment is included, as provided by Marathon/
Unocal.49
• Two 15,000-barrel storage tanks were included for TBPF; one 15,000-barrel tank was included
for East Foreland.49 The storage tanks which were originally presented hi 1993 dollars were
adjusted to 1995 dollars using the ENR-CCI ratio of 5471/5210.
• One pig launcher was included for each pipeline: three for TBPF and one for East Foreland.
Each pig launcher is an eight-inch standard 600 ANSI.49 The pig launcher costs which were
originally presented in 1993 dollars were adjusted to 1995 dollars using the ENR-CCI ratio of
5471/5210.
• Piping and instrumentation costs were assumed to be 15 percent of the equipment purchase cost.
This cost includes any additional valves, fittings, piping, cables, conduits, instrumentation, and
instrumentation wiring.9
4.2.1.2 Connecting Return Pipeline at the Platform
The five platforms assumed to receive produced water from onshore treatment facilities are King
Salmon, Grayling and Dolly Varden (associated with TBPF), Spark (associated with Granite Point), and
SWEPI "C" (associated with East Foreland). These platforms incur costs for equipment and services related
to retrofitting the platforms to accommodate the return pipeline to the existing produced water injection
systems. These costs primarily consist of pipeline installation and replumbing existing piping to the injection
system. The basis for these costs is the Marathon/Unocal report, which states that the costs were developed
using engineering data from other platform modification projects.49 The specific items included in these
modifications are listed in Tables D, E, and F in Appendix XI-2. The only difference between the platforms
with regard to return pipeline modifications is that Spark does not incur the cost of a pig receiver, because
the existing pipeline would be equipped with one.
4.2.1.3 Improved Gas Flotation
The assumptions developed for incremental gas flotation equipment costs are the same as those
presented in Section 4.1.1 for Options 1 and 2. Table XI-17 indicates which facilities and platforms incur
these costs, and Tables B, C, and G through J in Appendix XI-2 list the specific equipment sizes and costs
incurred.
XI-43
-------
4.2.1.4 Granular Filtration
As shown in Table XI-17, granular media filtration equipment was added to only two operations:
Granite Point treatment facility and Tyonek platform. All other facilities and platforms at which produced
water is treated have existing granular filtration units.45 The assumptions regarding the size and cost of
granular filters were adopted from the Offshore rulemaking effort, as follows:
• Available granular filtration unit sizes include 200 bpd, 1,000 bpd, 5,000 bpd, 10,000 bpd, and
40,000 bpd. These sizes and their capital costs were originally developed for the Offshore
rulemaking effort.9
• Granular filtration units were sized assuming a peak produced water flow of 2.3 times the
facility's average produced water flow.47-48
• Platform modification costs were added to Tyonek platform to accommodate space requirements
for the filtration (and additional injection) equipment. The square footage required is 400
square feet.9 The cost for additional platform space was $658.5 per square foot in 1995
dollars.13
• All capital costs were adjusted from 1992 dollars to 1995 dollars using the ENR-CCI ratio of
5471/4985 (1.0975)."
4.2.1.5 Filtration Backwash Centrifuge
With one exception, a centrifuge for dewatering filtration backwash solids was added to all
platforms that were assumed to inject produced water in the Option 3 zero discharge cost analysis. Spark
platfomi did not receive a centrifuge in this analysis because all the treatment equipment is located at the
Granite Point facility. Centrifuges would concentrate the solids removed from the filtered produced water,
thus allowing the liquid portion of the backwash to be injected. The dewatered solids would be disposed
of by transport to a landfill, as is reflected in the operating and maintenance costs in Section 4.2.2. The
assumptions regarding the size and cost of centrifuges were adopted from the Offshore rulemaking effort,
as follows:1
Centrifuge costs are based on a centrifuge sized to process 75 barrels of filtration backwash
concentrate for all the platforms. The Offshore development document presents the assumptions
behind calculated volumes of concentrated backwash ranging from 1 bpd (for a 200 bpd
produced water flow) to 200 bpd (for a 40,000 bpd produced water flow).1 Two centrifuges
were assumed adequate for systems treating more than 40,000 bpd of produced water. Thus,
King Salmon, Grayling, and Dolly Varden each received two centrifuges while all other
operations received only one.
The centrifuge cost was adjusted from its 1981 price of $30,000 to $46,430 in 1995 dollars
using the ENR-CCI ratio of 5471/3535 (1.548).13
XI-44
-------
4.2.1.6 Injection Wells and Associated Equipment
For this costing effort, new injection wells were added to Bruce and Tyonek platforms, and
recompletion of two existing service wells were assumed for Spark platform. The existing injection wells
and supporting equipment at all other platforms are assumed to be adequate to meet the requirements of
Option 3. This assumption is based on the use of existing injection equipment and wells in the
Marathon/Unocal "zero discharge analysis."49 The following assumptions were developed for incremental
injection requirements:
• Two injection wells were assumed to be added to each of Bruce and Tyonek platforms. One
well is necessary as a spare. Each injection well has a capacity of 6,000 bpd.9
• The cost to drill an injection well is $1,313,897. This cost was adjusted from its original cost
in 1992 dollars46 to 1995 dollars using the ENR-CCI ratio of 5471/4985 (1.0975).13
• Two 1,000 bpd injection pumps were assumed for each of Bruce and Tyonek, with one pump
acting as a spare. The selected pump is a Meyers model C35-20 rated for 1800 psia. The motor
for this pump is a 42 hp model VSG-413, 4 cylinder, 79 CID, natural gas drive. The total cost
of the pump and motor is $14,600 in 1995 dollars adjusted from their cost in 1992 dollars44
using the ENR-CCI ratio of 5471/4985 (1.0975).13
• Two former waterflood wells were assumed to be recompleted for use as produced water
disposal wells on Spark platform, with one well as a spare.
• The cost to recomplete each well was assumed to be $740,813. This cost was adjusted from its
original cost in 1992 dollars44 to 1995 dollars using the ENR-CCI ratio of 5471/4985 (1.0975).13
• Two 3,000 bpd injection pumps were assumed for Spark platform, with one pump acting as a
spare. The pump selected is a Meyers model DP90-18AB, 1700 psia. The motor for the pump
is a 100 hp model CSG-649, 6 cylinder, 300 CID, natural gas drive. The cost of the pump and
motor is $32,023 in 1995 dollars adjusted from their cost in 1992 dollars46 using the ENR-CCI
ratio of 5471/4985 (1.0975).13
4.2.2 Cook Inlet Option 3 Operating and Maintenance Costs
Operating and maintenance costs for Option 3 consist of four parts: standard O&M, well
workovers, additional treatment chemicals, and filtration O&M. Table XI-18 lists the O&M costs
calculated for all facilities and platforms included in this analysis. Standard O&M costs were calculated
as 10 percent of the capital costs. Standard O&M costs include the necessary labor, maintenance, spare
parts, and treatment chemicals to manage the incremental equipment required under this option.9 Annual
well workdver costs were $100,000 per workover.44-48-54
As stated earlier in Section 4.2, additional O&M costs were included to address the increased need
for chemicals to treat produced water for injection. For this analysis, additional chemical costs include the
XI-45
-------
biocide, corrosion inhibitor, and scale inhibitor needed to treat produced water prior to injection. The cost
for these chemicals is derived from information submitted by Cook Inlet operators. At an estimated cost
of $5 million per year and an annual produced water discharge rate of 54,750,000 bpy (150,000 bpd x
365), the unit cost for these chemicals is $0.0913/bbl.48-49 All locations that treat the produced water prior
to injection in this analysis incur additional treatment chemical costs.
The filtration O&M costs consist of labor to operate the filtration unit(s), maintenance costs, and
dewatered backwash sludge disposal. Combinations of these costs were applied to the locations that have
granular filtration, depending on whether equipment is existing or new, and whether a platform is
waterflooding. Table XI-19 presents the various costs assigned to the platforms and treatment facility that
require filtration O&M costs. Only Dillon and Bruce incur filtration labor and maintenance costs because
the existing filtration equipment on these platforms is not currently in use. Labor and maintenance costs
for platforms acquiring new filtration equipment are incurred as part of the standard O&M costs associated
with the capital cost of new equipment. All filtration systems in this analysis incur O&M costs for
dewatered sludge disposal. Filtration enhancing polymers are not included in these costs because they are
either accounted for in standard O&M costs for new equipment or are already in use at existing filtration
units. The following assumptions apply to the filtration O&M costs presented in Table XI-19:
• Labor is based on two man-hours per day,1 at a rate of $78 per hour, calculated as twice the
Gulf of Mexico labor rate.15
• Maintenance costs are 10 percent of the capital costs, and include energy, unit clean out,
inspection and replacement of filter media.1
• Sludge disposal costs are based on the estimated backwash sludge volume of 0.06 percent of the
total volume filtered.1 The unit disposal costs (hi $/bbl) were developed for the drilling waste
compliance cost analysis in which wastes are transported from the platforms to a landfill.55
4.3 COOK INLET MODEL NEW SOURCE COMPLIANCE COST ANALYSIS
EPA performed an analysis for a model new source platform to estimate compliance costs for
potential new sources in Cook Inlet. The platform profile was modeled after the Steelhead Platform, the
most recently constructed platform. The model platform profile was based on information from the
Offshore Economic Impact Assessment which states that Steelhead had 36 wells that had been drilled as
of 1988.56 (Current information shows only 15 wells in use. See Table IV-3 for current status of Cook
Inlet platforms.) The two injection wells currently used for waterflooding on Steelhead were subtracted
from the baseline of 36 wells hi order to determine the numbers of producing oil and gas wells expected
XI-46
-------
TABLE XI-19
COOK INLET FILTRATION O&M COSTS
(1995 $/YR)
FacaMty/PlatEtem
Granite Point Treat-
ment Facility
King Salmon
Grayling
Dolly Varden
SWEPI "C"
Dillon
Bruce
Anna
Baker
Tyonek
Totals
- " 5 "Labor
—
—
—
—
—
56,940
56,940
—
—
—
113,880
Maintenance
—
—
—
—
—
124,342
104,341
—
—
—
228,683
Sludge Disposal
20,549
1,018,956
1,180,867
860,208
97,499
68,923
2,632
29,485
129,684
664
3,409,467
Total,
20,549
1,018,956
1,180,867
860,208
97,499
250,205
163,913
29,485
129,684
664
3,752,030
to be present on the model platform after five years of development. Based on the proportion of 30 percent
oil wells to 70 percent gas wells currently on Steelhead, the remaining 34 wells were designated as 10 oil
wells and 24 gas wells. Using the profile and current oil, gas, and water production data for all active
Cook Inlet platforms (see Table IV-3), an average daily produced water flow rate of 7,353 bpd was
estimated for the model platform. Table A in Appendix XI-3 presents the details of this calculation.
Capital and O&M costs for the treatment and injection of produced water at the model platform
were then calculated based on the estimated daily produced water flow rate. The costs and methodologies
presented in Section 4.2 for the zero-discharge via injection option were used in the model platform
analysis. The items included in the capital cost calculations are the incremental equipment required to meet
zero discharge by injection, as follows:
XI-47
-------
• one 10,000 bpd granular filtration unit
• one 75 bpd centrifuge for dewatering filtration backwash
• three 6,000 bpd injection wells
• two injection pumps.
No gas flotation unit was added in the analysis because it was assumed to be part of the baseline
equipment installed on the new platform. That is, gas flotation units are already commonly in use to treat
produced water prior to discharge, so this does not represent incremental treatment. The total capital cost
for the above treatment and injection system was estimated to be $8,098,375 in 1995 dollars. Table B in
Appendix XI-3 presents the detailed calculations for this estimate.
Total operating and maintenance costs are the sum of standard O&M costs, annual injection well
workovers, additional treatment chemicals, and sludge disposal costs, based on the information presented
in Section 4.2.2. These costs total $1,517,578 annually (1995 dollars) as shown in Appendix XI-3,
TableB.
5.0 GULF OF MEXICO ALTERNATIVE BASELINE COMPLIANCE COST METHODOLOGY
The Alternative Baseline introduces additional oil and gas production facilities in the Gulf of
Mexico region to the Baseline industry profile (see Chapter IV - Industry Description). These additional
facilities include operations seeking individual permits from EPA as well as Louisiana facilities identified
in "Risk Assessment for Produced Water Discharges to Louisiana Open Bays" by the U.S. Department of
Energy .S7'58 Compliance costs associated with the additional facilities have been estimated separately as
described below, then added to the Baseline compliance costs and Cook Inlet compliance costs. The Cook
Inlet industry profile, cost estimates and pollutant reductions are not affected by the Alternative Baseline.
Some distinctions between the cost bases for the Alternative Baseline and Baseline analyses should
be noted. In the absence of facility-specific information (as was available for Baseline facilities),
Alternative Baseline facilities with multiple outfalls were assumed to combine produced water volumes to
acheive compliance. This assumption was used at proposal and was not criticized by commenters. Other
differences in the cost estimating process included addressing uncertainties with regard to some Louisiana
facilities' produced water flow rates. Louisiana produced water flow rates that were omitted or were
reported to the Louisiana Department of Environmental Quality (LDEQ) as zero or intermittent, have been
provided with the average Louisiana produced water flow rate (4,621 bpd) as an estimating tool. As in the
XI-48
-------
proposal analysis, Louisiana Alternative Baseline facilities were consided to be water-access for cost
estimating purposes.
Those Texas produced water flow rates that were reported as zero or omitted have been confirmed
by the Railroad Commission of Texas as having no produced water.59-60-61 Thus, these particular Texas
Alternative Baseline facilities incur no compliance costs or O&M costs for facilities having reported zero
flow. As in the proposal analysis, Texas Alternative Baseline facilities were assumed to be land-access for
cost estimating purposes.
5.1 GULF OF MEXICO ALTERNATIVE BASELINE OPTION 1 CAPITAL COSTS
Option 1 Capital costs for Alternative Baseline facilities were determined using the same
methodology presented in Section 3.1. For Louisiana Alternative Baseline facilities with future produced
water flow rates below 70.5 bpd, barging costs were incurred hi addition to commercial IGF treatment
costs. The 70.5 bpd cutoff rate was determined by cost parity between barging/commercial treatment and
on-site IGF treatment at water-access facilities. For Texas Alternative Baseline facilities with furture flow
rates below 76.5 bpd, trucking costs were incurred in addition to commercial IGF treatment costs. The
76.5 bpd cutoff rate was determined by cost parity between trucking/commercial treatment and on-site IGF
treatment at land-access facilities.
For Alternative Baseline facilities with future produced water flows between 70.5 and 5,000 bpd,
the step cost method was used to determine the captital costs as described in Section 3.1.1.2. The flow rate
was used to determine capital costs from Table XI-4. For future produced water flow rates above 5,000
bpd, the capital cost equation in Table XI-4 was used. Tables XI-20 and XI-21 present capital costs
estimated for Alternative Baseline facilities. Table XI-22 presents total capital costs for Option 1 including
Alternative Baseline facilities, Baseline facilities and Cook Inlet facilities.
5.2 GULF OF MEXICO ALTERNATIVE BASELINE OPTION 1 O&M COSTS
Estimated design O&M costs for IGF treatment are presented in Tables XI-20, XI-21 and XI-22,
alongside capital costs. Standard operating and maintenance costs were estimated to be ten percent of the
total capital equipment cost.8 In addition, labor costs were estimated based on one person-hour per day
at a rate of $39.00 per hour (in 1995 dollars).15 Typical operating and maintenance costs, other than
increased labor, include: polymer and/or flocculation enhancement chemicals, fuel cost, and feed pump
XI-49
-------
TABLE XI-20
LOUISIANA OPEN BAY DISCHARGERS COSTS3
Permit
Number
2827
2856
3023
2479
2857
1870
3032
2915
2952
2704
2901
3072
3002
2816
2825
2898
1866
2273
2995
3014
4206
2881
2523
2860
2672
2859
3063
2142
1856
1934*
2084
2618
3320
2134*
2504
2072
190!
TOTAL
', Current x/;£
Volume ;
(fobl/8ay}^£ • • ' /•
, ''': "- '.'• ""fi
1.0
3.0
3.4
10.0
20.0
49.0
50.0
130.0
223.0
524.0
1,076.0
1,489.0
2,017-0
2^71.0
2,910.0
3,617.0
4,621.0
4,621.0
4,621.0
4,621.0
4,621.0
5,010.0
5^64.0
6,800.0
8,366.0
10,807.0
11,500.0
12,076.0
15,000.0
15,675.0
16,743.0
22,500.0
22,579.0
23^33,0
37,113.0
37,750.0
41,700.0
329,814.4
-'. • \ S^-lilf •'•::$;&; w' w!i$TO|!«!ji;i
J Jl^gJtfSftf^lli
i'i 'iil§b1$liay5^?"
1.5
4.5
5.1
15.0
30.0
73.5
75.0
195.0
334.5
786.0
1,614.0
2,233.5
3,025.5
3,406.5
4,365.0
5,425.5
6,931.5
6,931.5
6,931.5
6,931.5
6,931.5
7,515.0
8,046.0
10,200.0
12,549.0
16,210.5
17,250.0
18,114.0
22,500.0
23,512.5
25,114.5
33,750.0
33,868.5
34,999.5
55,669.5
56,625.0
62,550.0
494,721,6
iite^^^iiH
Ipi^iPyifliji
iiijfj&&$j!^$jify3ltK:
$35,131
$35,131
$35,131
$35,131
$44,566
$187,405
$187,405
$187,405
$190,223
$190,223
$190,223
$247,000
$247,000
$247,000
$247,000
$378,445
$388,904
$388,904
$388,904
$388,904
$388,904
$392,957
$396,645
$411,604
$427,919
$453,348
$460,568
$466,568
$497,030
$504,062
$515,188
$575,163
$575,986
$583,841
$727,397
$734,033
$775,183
$13,126,433
B^«Sl^ll^l
!i|if;pp§l;||f||
!i^$lH|sl!!!t5
$980
$2,940
$3,332
$9,800
$19,601
$31,947
$31,947
$31,947
$32,228
$32,228
$32,228
$37,099
$37,099
$37,099
$37,099
$49,183
$50,075
$50,075
$50,075
$50,075
$50,075
$50,421
$50,735
$52,01!
$53,403
, $55,572
$56,188
$56,700
$59,298
$59,898
$60,847
$65,962
$66,032
$66,702
$78,947
$79,513
$83,023
$1,672^83
'|llp^ijjtij!pllft:::S
$35,131
$35,131
$35,131
$35,131
$44,566
$91,609
$91,609
$450,172
$454,579
$468,843
$495,000
$514,570
$539,590
$551,627
$581,907
$699,907
$825,865
$825,865
$825,865
$825,865
$825,865
$874,667
$919,078
$1,099,232
$1,295,696
$1,601,933
$1,688,874
$1,761,136
$2,127,968
$2,212,651
$2,346,638
$3,068,885
$3,078,796
$3,173,390
$4,902,168
$4,982,083
$3,477,633
$49,864,657
sII?I$ltiSi*3li^i&»i
J
Wyjs$$ij$!!iiii$$if$l} |
$980
$2,940
$3,332
$9,800
$19,601
$48,021
$49,001
$45,918
$50,570
$65,628
$93,242
$113,903
$140,317
$153,023
$184,990
$221,027
$284,663
$284,663
$284,663
$284,663
$284,663
$309,319
$331,756
$422,772
$522,029
$676,744
$720,668
$757,176
$942,505
$985,288
$1,052,980
$1,417,870
$1,422,877
$1,470,667
$2,344,072
$2,384,446
$2,634,805
$21,021,582
For outfalls indicated in Meinhold, et al., "Final Report: Risk Assessment for Produced Water Discharges to Louisiana
Open Bays," March 1996.51
For permit numbers with multiple outfalls, volumes were combined.
Average Louisiana PW flow rate (4,621 bpd) was used for outfalls with zero, intermittent, or omitted discharge rates.
Future Volume «1.5 x Current Volume
Small Volume facilities will barge their produced water to a commercial facility for injection. The cut-off volume
between barging and on-site gas flotation is 70.5 bbl/day.
The cut-off volume between barging to a commercial facility for injection and on-site injection is 108.4 bbl/day.
Produced water flow rates for permits 1934 and 2134 provided by Carl Sayer, Callon Petroleum, to Keni Kennedy,
Avanti, OB June 20,1996.**
XI-50
-------
TABLE XI-21
TEXAS DISCHARGERS SEEKING INDIVIDUAL PERMITS COSTS1
04CCC
1
14
18
127
215
217
595
674
711
747
825
9Q3«
233
282
690
723
972
119
71
13
*
663
693
37
214
284
628
752
924
41
199
939
236
926
104
919
925
582
905
675
*
927
242
264
*
552
922
605
202
684
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
1.0
1.0
1.0
1.0
1.0
2.0
3.0
5.0
7.0
10.0
10.0
15.0
16,0
22.0
24.0
29.0
31.0
40.0
40.0
43.0
44.0
48.0
49.0
60.0
69,0
75,0
86.0
92.0
93.0
95.0
104.0
114.0
115.0
140.0
143.0
150.0
153.0
165.0
Hi
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
1.5
1.5
1.5
1.5
1.5
3.0
4.5
7.5
10.5
15.0
15.0
22.5
24.0
33.0
36.0
43.5
46.5
60.0
60.0
64.5
66.0
72.0
73.5
90.0
103.5
112.5
129.0
138.0
139.5
142.5
156.0
171.0
172.5 '
210.0
214.5
225.0
229.5
247.5
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
so
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$182,605
$182,605
$182,605
$182,605
$182,605
$182,605
$182,605
$182,605
$182,605
$182,605
$185,423
$185,423
$185,423
$185,423
$185,423
g^^$;¥#;fr:^^>*>:$SS¥??S;it*t^''«^'-,«$?i«:
;-:^^;;:;5:^;;ii;;;^^:::::^:;:S%S::-S::
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$996
$996
$996
$996
$996
$1,993
$2,989
$4,982
$6,975
$9,965
$9,965
$14,947
$15,943
$21,922
$23,915
$28,897
$30,890
$39,858
$39,858
$42,847
$43,844
$47,830
$48,826
$25,723
$25,723
$25,723
$25,723
$25,723
$25,723
$25,723
$25,723
$25,723
$25,723
$26,005
$26,005
$26,005
$26,005
$26,005
p.Sii£MI8Sg;8l-iiltfc?:i
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$31,290
$165,750
$165,787
$166,188
$166,517
$166,736
$167,137
$167,356
$167,393
$167,466
$167,794
$168,159
$168,196
$169,108
$169,218
$169,473
$169,583
$170,021
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$996
$996
$996
$996
$996
$1,993
$2,989
$4,982
$6,975
$9,965
$9,965
$14,947
$15,943
$21,922
$23,915
$28,897
$30,890
$39,858
$39,858
$42,847
$43,844
$24,907
$24,947
$25,395
$25,761
$26,005
$26,453
$26,697
$26,738
$26,819
$27,185
$27,592
$27,633
$28,650
$28,772
$29,057
$29,179
$29,667
XI-51
-------
TABLE XI-21
TEXAS DISCHARGERS SEEKING INDIVIDUAL PERMITS COSTS3 (Continued)
Permit
Number
694
637
822
970
710
174
967
921
679
124
238
619
968
666
105
937
60
167
166
20
904
85
45
969
80
*
90
68
81
77
164
813
952
113
954
953
TOTAL
Current
Volume
Obbl/day)**
185.0
200.0
200.0
250.0
358.0
384.0
397.0
410.0
454.0
455.0
515.0
536.0
540.0
628.0
650.0
659.0
685.0
690.0
1,029.0
1,151.0
,360.0
,379.0
,400.0
,480.0
,492.0
1,500.0
1,800.0
2,185.0
3,090.0
3,552.0
4,353.0
4,893.0
4,980.0
5,127.0
7,384.0
9,316.0
67,764.0
•• »- **
,<- % .,
^f' J
Volume^ „";
(bbl/day)ds
277.5
300.0
300.0
375.0
537.0
576.0
595.5
615.0
681.0
682'.5
772.5
804.0
810.0
942.0
975.0
988.5
1,027.5
1,035.0
1,543.5
1,726.5
2,040.0
2,068.5
2,100.0
2,220.0
2,238.0
2,250.0
2,700.0
3,277.5
4,635.0
5,328.0
6,529.5
7,339.5
7,470.0
7,690.5
11,076.0
13,974.0
101,646.0
«$£•£&
f '$„""<,„ '{ ,,4cjs&
*• ? ••••._;• •• ,-k •"
Plot&tjE0nr ** *"
"' „ o" ' '. , '
" ''"" '''
'Q&tyt ,Qost (*/xr)
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$26,005
$30,876
$30,876
$30,876
$30,876
$30,876
$30,876
$30,876
$30,876
$30,876
$42,902
$43,614
$44,093
$44,171
$44,301
$46,307
$48,024
$1,940,078
"• .. j-y iw
' ,' '
' *\
,' Cap^Cosfr($) - __
$170,751
$171,299
$171,299
$173,124
$177,066
$178,015
$178,490
$178,-964
$180,570
$180,607
$182,797
$183,563
$183,709
$186,922
$187,725
$188,053
$189,002
$189,185
$201,559
$206,012
$213,641
$214,335
$215,101
$218,022
$218,460
$218,752
$229,702
$243,756
$276,790
$307,814
$362,622
$399,572
$405,525
$415,583
$570,019
$702,216
$12,379,593
»'-•*;, ' '-'
ischarge s , '
f "" * f ff f\
' " ' A'\ * "••
p^dM C.«st (*/y.r)/
$30,480
$31,091
$31,091
$33,125
$37,519
$38,577
$39,105
$39,634
$41,424
$41,465
$43,906
$44,761
$44,923
$48,503
$49,398
$49,765
$50,822
$51,026
$64,818
$69,781
$78,284
$79,057
$79,911
$83,166
$83,654
$83,980
$96,185
$111,848
$148,667
$167,859
$202,905
$226,532
$230,338
$236,770
$335,521
$420,052
$4,352,171
RRC Permit Pending.
Railroad Commission of Texas Individual Permit Application Intake Log, May 15, 1996. (Information for Permit
Numbers 903,919,921,927,937, 970 updated per fax from Kevin McClary, Railroad Commission of Texas, May 31,
1996.)60 Permit numbers 708, 731, 732, 733 were deleted from this profile because they are located in the Offshore
Subcategory in the Gulf of Mexico. (Memorandum to the Record, R. Montgomery, June 7, 1996)6'
For permit numbers with multiple outfalls, volumes were combined.
RRC confirms that permits reporting zero barrels per day are not discharging (Kerri Kennedy telecons with Carlos
Villamarin and Kevin McClary of RRC, May 31, 1996.)60
Future Volume = 1.5 x Current Volume
Small Volume facilities will truck their produced water to a commercial facility for injection. The cut-off value between
trucking to a commercial facility for injection and on-site gas flotation is 76.5 bbl/day.
The cut-off volume between trucking to a commercial facility for injection and on-site injection is 70.5 bbl/day.
Permit Number 903 was canceled at the request of the applicant. (Telecon with Kevin McClary, Railroad Commission
of Texas, May 31,1996.)60
XI-52
-------
TABLE XI-22
TOTAL CAPITAL AND O&M COSTS FOR
PRODUCED WATER BAT OPTIONS
ALTERNATIVE BASELINE
-Optio
*
ons
*
V * ••.•.
Capital -($)
13,126,433
1,672,383
12,020,306
1,940,078
1,818,604
286,259
9,232,461
1,168,826
36,197,804
5,067,546
49,864,657
21,021,582
12,379,593
4,352,171
21,280,137
9,605,289
9,232,461
1,168,826
92,756,848
36,147,868
49,864,657 21,021,582 12,379,593 4,352,171 21,280,137 9,605,289 96,956,093 20,960,966 180,480,480 55,940,008
'Costs for Gulf of Mexico Baseline Facilities are from Tables XI-5 and XI-9.
"Costs for Cook Inlet Baseline Facilities are from Table XI-14.
-------
and agitator maintenance and replacement costs. Alternative Baseline O&M costs were calculated in the
same way Baseline O&M costs were estimated, as presented in Section 3.1.2. O&M costs estimate first
year expenditures, which may be expected to rise as produced water flow rates increase.
5.3 GULF OF MEXICO ALTERNATIVE BASELINE OPTIONS 2 AND 3 CAPITAL COSTS
Capital costs for Options 2 and 3 for Alternative Baseline facilities were determined using the same
methodology presented in Section 3.2. For Louisiana Alternative Baseline facilities with future flow rates
below 108.4 bpd, barging costs were incurred in addition to commercial subsurface injection costs. The
108.4 bpd cutoff rate was determined by cost parity between barging/commercial injection and on-site
injection.7 For Texas Alternative Baseline facilities with future produced water flow rates below 70.5 bpd,
trucking costs were incurred in addition to commercial subsurface injection costs. Again, this cutoff figure
was determined by cost parity with onsite injeciton.7
For Alternative Baseline facilities with future produced water flows above the cutoff flow rate,
capital costs were estimated according to the appropriate regression in Table XI-8. Tables XI-20 and XI-21
present capital costs estimated for Alternative Baseline facilities. Table XI-22 presents total capital costs
for Options 2 and 3, including Alternative Baseline facilities, Baseline facilities and Cook Inlet facilities.
5.4 GULF OF MEXICO ALTERNATIVE BASELINE OPTIONS 2 AND 3 O&M COSTS
Estimated design O&M costs for subsurface injection are presented in Tables XI-20, XI-21 and
XI-22, alongside capital costs. Standard operating and maintenance costs were estimated to be ten percent
of the total capital equipment cost.8 In addition, labor costs were estimated based on one person-hour per
day at a rate of $39.00 per hour (in 1995 dollars).13 Typical operating and maintenance costs, other than
increased labor, include: biocides, scale inhibitors, and replacement cartridge filters. Alternative Baseline
O&M were calculated in the same way Baseline O&M costs were estimated, as presented in Section 3.2.3.
O&M costs estimate first year expenditures, which may be expected to rise as produced water flow rates
increase.
6.0 POLLUTANT REMOVALS
The pollutant removals for Options 1, 2, and 3 were calculated as the difference between the
effluent levels associated with typical BPT treatment (gas flotation or gravity separation) and the levels after
treatment by the BAT technology options (improved performance gas flotation and injection). Specifically,
XI-54
-------
the pollutant removals were calculated by multiplying the annual average produced water flow rate by the
difference in pollutant concentrations in BPT effluent relative to BAT technology effluent. Detailed
calculations of the pollutant removals for produced water regulatory options for the Gulf of Mexico and
Cook Inlet are presented in three supporting technical documents: 1) "Compliance Costs and Pollutant
Removals for Coastal Gulf of Mexico Produced Water Assuming Compliance with Zero Discharge Under
the EPA Region 6 General Permit,"14 2) "Compliance Costs and Pollutant Removals for Produced Water
Generated at Oil and Gas Production Platforms Located hi Cook Inlet, Alaska,"48 and 3) a memorandum
to the record regarding "Texas Dischargers Seeking Individual Permits and Louisiana 'Open Bays'
Dischargers: Costs and Loadings."63 Table XI-23 presents me baseline pollutant removals for the Gulf
of Mexico and Cook Inlet, and Table XI-24 presents the alternative baseline pollutant removals. Note that
the removals for Cook Inlet are identical in both tables, while those of the Gulf of Mexico differ between
baselines.
7.O BCT COST TEST
The three regulatory options developed in the produced water compliance cost analysis were also
evaluated according to the BCT cost reasonableness tests. The BCT cost test methodology for produced
water is the same as that described hi Chapter X. The pollutant parameters used in this analysis are total
suspended solids (TSS) and oil and grease. Table XI-23 lists incremental conventional pollutant removals
for each regulatory option.
All of the produced water options considered for BCT regulation fail the BCT cost test. The ratio
of cost of pollutant removal to pounds of pollutant removed (POTW Test) exceeds the POTW benchmark
of $0.586 per pound (the 1986 benchmark of $0.46 per pound adjusted to 1992 dollars). Table XI-25
presents the BCT Cost Test analysis for conventional pollutants removed from produced water hi both the
Gulf of Mexico and Cook Met.
XI-55
-------
TABLE XI-23
ANNUAL BAT POLLUTANT REMOVALS FOR PRODUCED WATER IN THE
GULF OF MEXICO AND COOK INLET
Option 1
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
Option 2
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
Option 3
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
,x , GttfcotMesteo-
545,933
37,240
4,527
193,419
781,119
1,855,319
108,018
33,877
1,490,602,961
1,492,600,175
1,855,319
108,018
33,877
1,490,602,961
1,492,600,175
", - Cook Inlet
855,054
70,367
14,755
560,011
1,500,186
855,054
70,367
14,755
560,011
1,500,186
1,781,074
120,587
51,089
1,054,589,456
1,056,542,206
'• ) "*'
Total
1,400,453
107,607
19,282
753,430
2,281,305
2,710,373
178,385
48,632
1,491,162,972
1,494,100,361
3,636,393
228,605
84,966
2,545,192,417
2,549,142,381
XI-56
-------
TABLE XI-24
ANNUAL BAT POLLUTANT REMOVALS FOR PRODUCED WATER IN THE
GULF OF MEXICO AND COOK INLET
(ALTERNATIVE BASELINE)
;, •-- ,, ,
Option 1
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
Option 2
Conventionals
Priority Organics.
Priority Metals
Non-Conventionals
Total
Option 3
Conventionals
Priority Organics
Priority Metals
Non-Conventionals
Total
Gulf of Mexico
6,349,904
433,145
52,663
2,249,709
9,085,421
10,380,698
651,027
143,014
4,590,303,908
4,601,478,647
10,380,698
651,027
143,014
4,590,303,908
4,601,478,647
/ , CookJWet
855,054
70,367
14,755
560,011
1,500,186
855,054
70,367
14,755
560,011
1,500,186
1,781,074
120,587
51,089
1,054,589,456
1,056,542,206
, :, - woM ,/-- <•'--
7,204,958
503,512
67,418
2,809,720
10,585,607
11,235,752
721,394
157,769
4,590,863,919
4,602,978,833
12,161,772
771,614
194,103
5,644,893,364
5,658,020,853
XI-57
-------
TABLE XI-25
PRODUCED WATER BCT COST TEST ANALYSIS
• Options v:;'::-:-!:t!:%-
: -- ''-..;.;•;;' v"V|V-i{';' i,' ',
• ' •••,'::•? '!i&i>8t
Option1; Zero discharge except (a)
major pass facilities and (b) Cook
Met facilities = 29/42 mg/1 oil and
grease
3,028,508
1,400,987
2.162
N
Qptjon2: Zero discharge except
Cook Inlet facilities = 29/42 mg/1
oil and grease
15,118,423
2,710,373
5.578
N
Option 3: Zero discharge all
facilities
47,400,434
3,636,393
13.035
N
Hie total compliance costs presented in Table XI-1 were amuaiized at 7% over 10 years (Le., (capitals x 0.1424) + O&M$/yr).
XI-58
-------
8.0 REFERENCES
1. U.S. EPA, Development Document for Effluent Limitation Guidelines and New Source
Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source
Category, EPA 821-R-93-003, January 1993.
2. Eastern Research Group, "Economic Impact Analysis for Final Effluent Limitations Guidelines
and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category,"
1996.
3. U.S. EPA, "Final NPDES General Permits for Produced Water and Produced Sand discharges
from the Oil and Gas Extraction Point Source Category to Coastal Waters in Louisiana and
Texas," 60 Fed. Reg. 2387 (January 9, 1995).
4. Kennedy, K., Avanti, Memorandum to the record regarding, "Development of Inventory of
Coastal Gulf States Producd Water Dischargers for Final Effluent Limitation Guidelines,"
September 12,1996.
5. Kennedy, K., Avanti, telecon with Mike Lemrod, North Central, regarding configuration South
Pass Block 24 Field, May 14, 1996.
6. SAIC, "Produced Water Injection Cost Study for the Development of Coastal Oil and Gas Effluent
Limitations Guidelines," January 27, 1995.
7. SAIC, "Gulf of Mexico Coastal Oil and Gas: Produced Water Treatment Options Cost Estimates,''
January 5, 1995.
8. Energy Information Agency, "Water Treatment Technology Costs Associated with Offshore Oil
and Gas Production," July 1992.
9. SAIC, "Offshore Oil and Gas Industry - Analysis of the Cost and Pollutant Removal Estimates for
the Final BCT, BAT, and NSPS Produced Water Treatment Options," January 13, 1993.
10. Jordan, R., EPA, Memorandum to the record regarding, "Discharges of Offshore Subcategory
Water into Coastal Waters of Texas and Louisiana," February 8, 1996.
11. Kennedy, K., Avanti, Letter to Jordan, R., EPA, with attachment summarizing data from 1993-
1995 Louisiana Discharge Monitoring Reports (DMRs), march 28, 1996.
12. Bourgeois, D., Flores & Rucks, Inc., Letter with attachments to A. Wiedeman, U.S. EPA,
"Comments on Proposed Coastal Guidelines for East Bay," June 30, 1995.
13. Kennedy, K., Avanti, Memorandum to the record (with attachment) regarding, Cost Adjustment
Ratios to 1995 Dollars, April 8, 1996.
14. Avanti Corporation, "Compliance Costs and Pollutant Removals for Coastal Gulf of Mexico
Produced Water Assuming Compliance with Zero Discharge under the EPA Region 6 General
Permit," September 16, 1996.
XI-59
-------
15. Kennedy, K., Avanti, Memorandum to the record regarding, Gulf of Mexico Oil and Gas
Extraction Labor Rates, April 2, 1996.
16. SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire (Final)," January 31, 1995.
17. Filtration Systems, Filtration Equipment Specifications and Costs, 1992.
18. W-H-B- Pumps, Inc., Pump Specifications and Costs, January 10, 1994.
19. Walk, Haydel & Associates, Inc., "Potential Impact of Proposed EPA BAT/NSPS Standards for
Poduced Water Discharges form the Offshore Oil and Gas Industry," January 1984. (Offshore
Rulemaking Record Volume 116)
20. Kerr and Associates, Inc., "Review of Report Titled, 'Economic Impact of Restricted Produced
Water Discharges in Louisiana [by Walk, Haydel],'" prepared for the Louisiana Department of
Environmental Quality, September 1990.
21. U.S. EPA, Development Document for Proposed Effluent Limitations Guidelines and Standards
for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category, EPA 821-R-95-
009, February 1995.
22. Sunda, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Injection Well Capacity,
April 26, 1994.
23. Kennedy, K., Avanti, Memorandum to the record regarding, Louisiana Injection Well Capacities
and Depths, April 2, 1996.
24. Sunda, J., SAIC, Telephone contact with Jeff Smith, EPA, regarding, New and Converted Wells
and AORs, February 3, 1994.
25. Scaife, W., Amoco, Letter to Matt Clarke, EPA, regarding, recent purchase of Grand Bay
facility, April 22, 1996.
26. American Society of Heating, Refrigerating and Air-Conditioning Engineers, "ASHRAE
Handbook 1981 Fundamentals," 1981.
27. SAIC, "Final Report: Statistical Analysis of Settling Effluent from Coastal Oil and Gas Extraction
Facilities," June 27, 1996.
28. Jordan, R., U.S. EPA, Letter (with attachments) to Doss Bourgeois, Flores & Rucks, Inc.,
November 20, 1995.
29. Horstman, J., Radian Corporation, "Flores & Rucks, Inc. East Bay Complex Mississippi River
Delta, Louisiana Site Visit," February 13, 1996. (Confidential Business Information)
30. Jones, A., ERG, Fax regarding, "Flores & Rucks' Coastal/Offshore Delineation," February 14,
1996.
31. American Petroleum Institute, "Subsurface Saltwater Injection and Disposal, Book 3 of Vocational
Training Series," October 1995.
XI-60
-------
32. Kennedy, K., Avanti, Telephone record to David Metzz, Gulf South Operators regarding, Coastal
ELG Comment Response-Main Pass Dischargers, January 29, 1996.
33. Kennedy, K., Avanti, Telecon with Jay Welsch, Chevron, April 9, 1996.
34. Horstman, J., Radian Corporation, "Chevron Pipe Line Company Main Pass 69 Terminal Main
Pass 41 Terminal - Romere Pass Mississippi River Delta, Louisiana Site Visit," March 29, 1996.
(Confidential Business Information)
35. Wiygul, R., Sierra Club Legal Defense Fund, Memorandum to Kennedy, K., Avanti, regarding,
"Settlement Agreements in Clean Water Act Citizen Suits," July 25, 1996.
36. Wiygul, R., Sierra Club Legal Defense Fund, Memorandum to Kennedy, K., Avanti, regarding,
"Additional Information on Produced Water Discharges," July 29, 1996.
37. Mclntyre, J., Avanti, Memorandum to the Record regarding "Coastal Gulf of Mexico Production
Facilities Currently at Zero Discharge for Produced Water," September 30, 1996.
38. U.S. EPA, "Oil and Gas Extraction Point Source Category; Offshore Subcategory Effluent
Guidelines and New Source Performance Standards; Final Rule," 58 Fed. Reg. 12454 (March 4,
1993).
39. Bourgeois, D., Flores & Rucks, Inc., Letter (with attachments) to Jordan, R., EPA, regarding,
"Coastal Effluent Guidelines Rulemaking Additional Technical Information for East Bay,"
December 20, 1995.
40. Reeves, R., Flores & Rucks, Inc., Letter to White, C., EPA, "Comments of Flores & Rucks, Inc.
to EPA's Proposed Coastal Produced Water Guidelines," August 2, 1996.
41. Kennedy, K., Avanti, Memorandum to Ron Jordan, EPA, regarding, "Flores & Rucks Sensitivity
Analysis," September 12, 1996.
42. U.S. EPA, "Response to Public Comments on Effluent Limitations Guidelines and New Source
Performance Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source
Category," October 1996.
43. Kennedy, K., Avanti, Memorandum to the record regarding, "Gulf of Mexico Natural Gas Cost,"
April 5, 1996.
44. Mason, T., Avanti, Memorandum regarding, Confidential Business Information Supporting Costs
and Loadings Determination, September 12, 1996. (Confidential Business Information)
45. Erickson, M., SAIC, "Oil and Gas Exploration and Production Wastes Handling Methods in
Coastal Alaska," January 6, 1995.
46. Dawley, J., Memorandum to Allison Wiedeman, "Preliminary Cost Estimates for Cook Inlet BAT
Produced Water Options," June 27, 1994.
47. Mclntyre, J., Avanti, Memorandum to the record regarding, calculation of peak flow factor, June
14, 1996.
XI-61
-------
48. Avanti Corporation, "Compliance Costs and Pollutant Removals for Produced Water Generated
at Oil and Gas Production Platforms Located in Cook Inlet, Alaska," September 16, 1996.
49. Marathon Oil Company and Unocal Corporation, "Zero Discharge Analysis: Trading Bay
Production Facility," March 1994.
50. Schmidt, R., Unocal, Letter to Manuela Erickson, SAIC, regarding, "Drill Cuttings and Fluid
Discharges; Additional Information," April 21, 1994.
51. Peters, M. and K. Timmerhaus, Plant Design and Economics for Chemical Engineers, third
edition, McGraw-Hill Book Company, New York, 1980.
52. Brady, J., Alaska Oil and Gas Association, Letter with attachments to Allison Wiedeman, U.S.
EPA, regarding, comments on proposed guidelines, July 16, 1995.
53. Dawley, J., SAIC, Telephone Contact Report with Bob Crandall, Alaska Oil and Gas
Conservation Commission, regarding, "the technical feasibility [of] produced [water] hi onshore
disposal wells hi the Cook Inlet area," April 19, 1994.
54. Beitia, J., Unocal, Letter with attachments to Allison Wiedeman, U.S. EPA regarding comments
on proposed guidelines, June 19, 1995.
55. Avanti Corporation, "Compliance Costs and Pollutant Removals for Drilling Fluids and Drill
Cuttings," September 16, 1996.
56. Eastern Research Group, "Economic Impact Analysis of Proposed Effluent Limitations Guidelines
and Standards of Performance for the Offshore Oil and Gas Industry," February 1991. (Offshore
Record Volume 137)
57. McClary, K., Railroad Commission of Texas, Facsimile to Kerri Kennedy, Avanti, regarding chart
of discharge permit numbers and operators, May 13, 1996.
58. Meinhold, A., et al, Brookhaven National Laboratory, "Final Report: Risk Assessment for
Produced Water Discharges to Louisiana Open Bays," prepared for Bartlesville Project Office,
U.S. Department of Energy, March 1996.
59. Kennedy, K., Avanti, Telephone contact with Carlos Villamarin, Railroad Commission of Texas
regarding "Texas Open Bay Produced Water Discharges," May 24, 1996.
60. Kennedy, K., Avanti, Telephone contact with Carlos Villamarin and Kevin McClary, Railroad
Commission of Texas, regarding "Texas Individual Permit Applicants Produced Water (PW)
Volumes," May 31, 1996.
61. Montgomery, R., Avanti, Memorandum to the record regarding individual analysis of lat/longs
submitted by RRC for applicants seeking individual permits, June 7, 1996.
62. Sayers, Carl D., Gallon Offshore Production, Facsimile to Kerri Kennedy, Avanti, regarding
additional information for Chandeleur Sound Block 25 and Main Pass Block 35 produced water
discharges, June 20,1996.
XI-62
-------
63. Mason, T., Avanti, Memorandum to the record regarding "Texas Dischargers Seeking Individual
Permits and Louisiana 'Open Bays' Dischargers: Costs and Loadings," September 30, 1996.
XI-63
-------
-------
CHAPTER XII
COMPLIANCE COST AND POLLUTANT REMOVAL DETERMINATION-
WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
1.0 INTRODUCTION
This chapter presents the compliance costs and pollutant removals for various regulatory options
regarding effluent limitations guidelines and standards for well treatment, workover, and completion
(TWC) fluids from coastal Gulf of Mexico oil and gas facilities.
Section 2.0 presents a detailed discussion of affected facilities. Compliance costs and pollutant
removal developed for the final regulatory options are presented in Sections 4.0 and 5.0. The cost and
pollutant removals analyses presented in these sections apply only to the Gulf of Mexico coastal area. For
Cook Inlet, Alaska operations, waste TWC fluids are currently commingled with produced water prior to
treatment and/or disposal,1 and thus TWC costs to comply with Cook Inlet limitations are included in the
costing of the produced water options presented in Chapter XI. California coastal oil and gas sources
already meet zero discharge of TWC fluids, so there are no incremental costs or pollutant reductions
associated with these effluent limitations.2
2.0 OPTIONS CONSIDERED AND SUMMARY COSTS
For the final rule, EPA considered for TWC fluid treatment and/or disposal the regulatory options
identified for produced water:
Option 1: Option 1 prohibits all coastal oil and gas facilities from discharging TWC fluids except:
Gulf of Mexico facilities discharging into major deltaic passes of the Mississippi River, and Cook
Inlet, Alaska. Excluded facilities are required to comply with new BAT effluent limitations and
NSPS for oil and grease at 29 mg/1 monthly average, and 42 mg/1 daily maximum based on
improved performance gas flotation (IGF).
Option 2: Option 2 prohibits all coastal oil and gas facilities from discharging TWC fluids with
the exception of coastal facilities in Cook Inlet, Alaska which are required to comply with new
BAT effluent limitations and NSPS for oil and grease at 29 mg/1 monthly average, and 42 mg/1
daily maximum based on improved performance gas flotation.
xn-i
-------
Option 3: Option 3 prohibits discharges of TWC from all coastal oil and gas facilities. For coastal
areas outside Cook Inlet, Option 3 is identical to Option 2.
Compliance cost estimates for coastal gulf states are based on the current practice of commingling
TWC fluids with produced water for treatment and disposal.
Discharges of TWC fluids in the Gulf of Mexico are covered by the 1993 Region 6 General
Permits for drilling activities and associated wastes [58 FR 49126 (September 21, 1993)]. The 1993
general permits prohibit discharges to freshwater and place limitations on discharges to brackish and saline
waters.3 EPA's analysis estimated the volume of TWC fluids being discharged in the Gulf of Mexico using
data collected in the 1993 Coastal Oil and Gas Questionnaire.4 EPA used the 1993 general permits and
information collected in the Coastal Oil and Gas Questionnaire to establish the baseline profile of existing
discharges, then calculated the incremental compliance costs incurred in meeting limitations based on either
improved gas flotation or zero discharge.
Issuance of the 1995 Region 6 General Permits [60 FR 2387 (January 9, 1995)] placed zero
discharge limitations on produced water and produced sand, except for major pass facilities.5'" As a result
of the 1995 general permits, many coastal oil and gas facilities have now ceased discharges of produced
water, or are expected to do so by January 1997. Since TWC fluids are typically commingled with
produced water for treatment,4 EPA believes that the zero discharge provision of the 1995 general permits
has resulted in TWC fluids generated at many coastal gulf facilities to be now achieving zero discharge
along with produced water, with the exception of major pass facilities.5 Since EPA is unable to confirm
the degree to which this may be taking place, EPA is continuing to use the data collected hi the Coastal Oil
and Gas Questionnaire to determine the volumes of TWC fluids incurring costs to meet zero discharge. It
is worth noting, however, that using the same TWC volumes as in the proposal analysis likely overstates
the true cost of compliance with the TWC limitations of the final effluent guidelines.
Major pass faculties not already discharging at effluent levels representative of IGF treatment incur
compliance costs under Option 1. All major pass facilities incur costs under Options 2 and 3. Compliance
cost estimates for major pass facilities are discussed in detail in Section 4.0, Compliance Cost
Methodology.
Major Pass Facilities are coastal oil and gas facilities discharging offshore subcategory produced water to the main deltaic
passes of the Mississippi River or to the Atchafalaya River below Morgan City including Wax Lake Outlet (see discussion in
Chapter IV).
xn-2
-------
Table XIf-1 summarizes the BAT and NSPS compliance costs for the three regulatory options.
Detailed spreadsheets containing the calculation of these estimates are included in Appendix XII-1.
TABLE XH-1
TOTAL ANNUAL COMPLIANCE COST ESTIMATES FOR
TREATMENT, WORKOVER, AND COMPLETION FLUIDS (1995 $)a
„ Option - , ;
Option 1:
Zero discharge except Major Pass
Panilitipc anH fnnlr Tnlpt — *70/A9
mg/1 oil and grease based on IGF
Option 2:
Zero discharge except Cook Inlet
on IGF
Option 3:
Zero discharge all
i-
Workover/Treatment
Completion
Total
Workover/Treatment
Completion
Total
Workover/Treatment
Completion
Total
B^gSoilW
$492,713
$172,597
$665,310
$496,354
$173,829
$670,183
$496,354
$173,829
$670,183
5 •. :
- New Sources" ,;
$61,529
$24,380
$85,909
$61,863
$24,500
$86,363
$61,863
$24,500
$86,363
This table includes TWC compliance costs for facilities in the states bordering the Gulf of Mexico. Alaska TWC
compliance costs are included in Cook Inlet produced water cost estimates presented in Chapter XI.
3.0 BASIS FOR ANALYSIS
For Gulf of Mexico coastal facilities, the baseline requirements for TWC fluids were established
in the 1993 Region 6 General Permits for drilling activities [58 FR 49126 (September 21, 1993)].3 These
permits allow TWC discharges into saline waters with prohibitions on the discharge of toxic pollutants and
free oil, and a limited pH range of 6 to 9. Because TWC fluids would be commingled with produced water
prior to treatment and discharge or injection, the proposal TWC compliance cost analysis included the same
Gulf of Mexico population as the produced water cost analysis. Under the 1995 Region 6 General
Permits,5 much of the original coastal population is now prohibited from discharging produced water.
Thus, the total TWC population has been subdivided into the following distinct facilities according to their
produced water flow rates:
xn-s
-------
1) Medium/Large Facilities: Those facilities producing large enough amounts of produced
water to make it cost effective to develop and operate on-site treatment technology. Because
the 1995 Region 6 General Permits do not cover all of these facilities, EPA used separate
baselines for facilities covered and facilities not covered by the 1995 General Permits:
a) General Permit Facilities—Those medium/large facilities covered by the 1995 Region 6
General Permits requiring zero discharge of produced water.5 TWC compliance costs
for disposal at medium/large general permit facilities are based on incremental on-site
subsurface injection costs for commingled TWC fluid volumes for all options.
b) Major Pass Facilities—Those facilities which are not covered by the 1995 Region 6
General Permits because they treat and discharge offshore subcategory produced waters
into major passes of the lower Mississippi or to the Atchafalaya River.5'6 TWC
compliance costs under Option 1 for treatment at major pass facilities are based on
incremental costs for treatment and discharge of commingled TWC fluid volumes by
unproved operating performance of gas flotation produced water treatment systems.
TWC compliance costs for Options 2 and 3 (zero discharge at major pass facilities) are
based on incremental on-site subsurface injection costs for commingled TWC volumes.6
2) Small Facilities: Small facilities find it less expensive to meet zero discharge by using
commercial treatment/disposal facilities than to inject on-site. All produced water small
facilities are covered by the zero discharge provisions of the 1995 General Permits requiring
zero discharge of produced water.5 Thus, TWC compliance costs for small facilities are
based on incremental commercial injection.
The distribution between medium/large facilities and small facilities was based on a detailed
analysis of on-site treatment versus commercial disposal costs at various produced water discharge flow
rates. The analysis is presented in a separate document entitled "Gulf of Mexico Coastal Oil and Gas:
Produced Water Treatment Options Cost Estimates."7
TWC fluid compliance cost and pollutant removal analyses were based on the volume of
treatment/workover and completion fluids generated at medium/large (i.e., major pass and general permit
facilities) and small facilities for each regulatory option. The annual TWC fluid volume discharged was
calculated from the annual number of wells having treatment/workovers or completions performed and the
average volume of fluids generated per job. The Coastal Oil and Gas Questionnaire provided information
described below and in Section 4.1.1 to derive the number of wells and the average volume per job of
TWC fluids used in the cost and removals analyses.4
Annual Number of Existing Wells Discharging Workover/Treatment Fluids The number of wells at
medium/large facilities and the number of wells at small facilities discharging workover/treatment fluids
was derived from the responses to the 1993 Oil and Gas Questionnaire.4 EPA determined that there were
350 wells in the coastal subcategory discharging workover/treatment fluids annually. Of these wells, 270
xn-4
-------
wells were located at medium/large facilities (inclusive of 58 coastal subcategory wells estimated for the
major pass facilities), and 80 wells were at small facilities.8 The number of wells discharging workover/
treatment fluids from major pass facilities was calculated by comparing the total number of wells at major
pass facilities to the total number of coastal wells. The calculation based on this ratio resulted in an
estimate of 58 major pass wells discharging workover/treatment fluids annually:
Refs:
6,8,9
Total wells at all Major Pass Facilities x Total wells discharging workover/treatment fluids Uai°* Pa™ we/to with
* =—= = workover/treatment
Total Coastal wells discharging TWC fluids fluids
= 58 Major Pass wells with workover/treatment fluids
4675
Because all major pass facilities are medium/large facilities,6 all 58 major pass wells are included in the
inventory of medium/large wells.
Annual Number of Existing Wells Discharging Completion Fluids The number of wells located at
medium/large facilities and the number of wells located at small facilities were also derived from the
responses to the Coastal Oil and Gas Questionnaire.4 EPA determined that there were 334 wells
discharging completion fluids annually. Of these 334 wells, 257 wells were located at medium/large
facilities (inclusive of 55 coastal subcateogry wells discharging completion fluids estimated for major pass
facilities), and 77 wells were located at small facilities.8 The annual number of major pass wells
discharging completion fluids was calculated from the ratio of:
Refe:
6.8,9
Total wells at all Major Pass Facilities * Total wells discharging completion fluids _ Wells discharging]
Total Coastal wells discharging TWC fluids completion flvids\
= 55 wells discharging completion fluids]
4,675 J
xn-s
-------
Because all major pass facilities are medium/large facilities,6 all 55 wells estimated to be discharging
completion fluids at major pass facilities are included in the inventory of medium/large wells. Table Xtt-2
presents a summary of the annual TWC jobs at existing Gulf of Mexico sources.
The volumes of TWC fluids per job used in the cost and removals calculations are based on the
statistical results of the Coastal Oil and Gas Questionnaire.4 The questions in the questionnaire asked for
the discharged volumes of workover/treatment fluids (Question a42a) and completion fluids (Question
b32a) in units of barrels per well for the year 1992. For the purposes of cost and removals calculations,
these units are used as barrels per job, assuming that the volumes reported in the survey represent single
TWC job volumes. This assumption is based on the statistical responses to survey question a40 that
indicate the frequency of workover/treatment jobs. The greater number of respondents (27) reported
generating workover/treatment fluids approximately once every three years, while only five respondents
reported a job frequency of about twice per year. Thus, it is assumed that the volumes reported for 1992
statistically represent single-job volumes rather than the totals from multiple jobs.
Annual Number of New Wells Discharging TWC Fluids The number of new wells discharging TWC
fluids was derived from the Coastal Oil and Gas Questionnaire data. The Questionnaire results indicate
that 187 new production wells were drilled in 1992.4 EPA determined that due to the existing prohibition
of TWC fluid discharges to fresh water areas imposed by the 1993 Region 6 General Permit for drilling
activities and associated wastes [58 FR 49126], a proportion of the 187 new wells would not be affected
by the proposed regulation. Data used to identify the population of coastal operators to be included in the
Coastal Oil and Gas Questionnaire were used to determine the proportion of new wells that would be
located in fresh versus saline water areas. Table XH-3 lists the data and results of this analysis, and shows
that approximately 76% of the wells in the coastal Gulf of Mexico region that were completed since 1990
are located in fresh water areas and 24% are located hi saline water areas. The calculation of the number
of wells located in saline water areas, and hence subject to the proposed regulations, is as follows:
(187 wells discharging TWC fluids in 1992) x (24% saline water areas) = 45 new source wells/year
In the analysis, 45 new sources were included in each of the calculations for workover/treatment
fluids and completion fluids. Table XH-4 presents a summary of annual TWC jobs at new Gulf of Mexico
sources.
xn-6
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TABLE XH-2
SUMMARY OF ANNUAL TWC JOBS AT EXISTING GULF OF MEXICO SOURCES
s^P:
Workover/Treatment
Completion
Total
^^l^^i&m^i::*:.:, :„:*>
r^dLm/L^£kcftyeli, i
25a
23"
48
ilsl
212
202
414
< Small ->,-> "-
'»: Facilities- ^
80
77
157
-1^ r;:*';bpTi^ii^^^;;;Sv5
'^'•^^a^uai^ Hi
58
55
113
[;^JSt:l
212
202
414
80
77
157
1 Based on CBI data, it is estimated that 33 workover/treatment jobs are currently treated through IGF. ' Thus, 33 jobs incur no cost and achieve no pollutant
reduction incremental to IGF. These 33 jobs are excluded from the analysis as follows:
(58 total jobs at Major Pass Facilities) - (33 jobs achieving IGF) = 25 workover/treatment jobs incurring annual costs.
b Based on CBI data, it is estimated that 32 completion jobs are currently treated through IGF. ' Thus, 32 jobs incur no costs and achieve no pollutant reduction
incremental to IGF. These 32 jobs are excluded from the analysis, as follows:
(55 total jobs at Major Pass Facilities) - (32 jobs achieving Option 1) = 23 completion jobs incurring annual costs.
-------
TABLE XII-3
NUMBER OF WELLS LOCATED IN FRESH VERSUS SALINE WATERS IN THE
COASTAL GULF OF MEXICO REGION 4-a
Major
Small Independent
Other
Total
174
14
287
475
65
80
147
* The values in this table are the sum of the values in Tables 2, 6, and 7 in the source document,
only for wells completed during or after 1990.4
4.0 COMPLIANCE COST METHODOLOGY
The following sections describe the bases, data and methodology used to develop the cost estimates
in Table Xn-1.
4.1 GENERAL ASSUMPTIONS AND INPUT DATA
The technology basis used for developing compliance cost estimates for TWC fluids is either
commingling of TWC fluids with produced water for on-site treatment and/or disposal (major pass and
general permit medium/large facilities) or commercial disposal (small facilities). Costs for on-site
treatment and/or disposal of TWC fluids are based on operating and maintenance (O&M) costs developed
for produced water at medium/large facilities as presented in Chapter XI and in Sections 4.1.1 and 4.1.2.
Costs for small facilities are based on the transportation of TWC fluids for off-site commercial disposal.
Disposal cost information was obtained directly from industry sources as listed below in Section 4.1,3.
Because TWC fluids are commingled with produced water which is already required to meet zero
discharge, no additional capital expenses are included for handling TWC fluids under all three options.
Since TWC operations are occasional occurrences rather than continuous, all necessary tankage
and equipment would be brought on-site at the time of the job as a matter of standard operating procedure,
and would be removed at the conclusion of the job. In some cases TWC fluids might be captured for reuse
xn-s
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TABLE XII-4
SUMMARY OF ANNUAL TWC JOBS AT NEW GULF OF MEXICO SOURCES
1 ' ^ "* ' * %
-" ;" , ,' v
' ' / ' ?"/„•"
Workover/Treatment
Completion
Total
f -.'^ 'j^' ^ *
, - Mediiun/Lai
*
Major Pass
6
6
12
„ OFTioKr,
•gefadliiils,,;
\-, General '
29
29
58
*. ? \ ",-:---
,,T.i v-;' ;,-;
4 .Facilities ' --
10
10
20
• ' I >• -. *
^Medfiim/La
,Maj|>rPass ':
6
6
12
OFTiONS2'&;
General ,'^
Permit ;,
29
29
58
* ' *'*•'. '
^ rt «'
, -Small
t * >
10
10
20
-------
or separate disposal after the job (e.g., oil-based fluids), TWC fluids can be left in the hole and brought
up with the produced fluids when the well is brought back on-line, thus requiring no additional fluids
management equipment to be purchased.10 EPA compliance cost estimates do not include credit for TWC
reuse and therefore tend to be conservatively high.
4.1.1 Assumptions and Input Data Derived from the Results of the 1993 Coastal Survey
• Annual Number of Existing Wells Discharging TWC Fluids: The numbers of existing wells
currently discharging workover/treatment fluids and completion fluids were derived from the
Coastal Oil and Gas Questionnaire results and state Discharging Monitoring Report (DMR)
data. The survey results indicate that in 1992, 219 wells discharged workover/treatment fluids
and 209 wells discharged completion fluids.4 A comparison of the number of wells hi the
survey to the number of wells for which DMR data are available revealed that the survey count
of wells must be increased by a factor of 1.6 for an accurate count of existing wells. Thus, the
estimates of 219 wells discharging workover/treatment fluids and 209 wells discharging
completion fluids were increased to 350 and 334, respectively. Calculation of the number of
wells for each facility type is presented in Section 3.0.
• Annual Number of New Source Wells Discharging TWC Fluids: The number of new source
wells discharging TWC fluids was also derived from the Coastal Oil and Gas Questionnaire
data.4 The survey results indicate that 187 new source production wells were drilled in 1992.4
As presented in Section 3.0, EPA determined that 24 percent of the wells or 45 new source
wells/year are located hi saline water areas.4
• Percentage of Land- versus Water-Access Facilities: The 1995 Coastal Development Document
lists responses to three 1993 Questionnaire questions that relate to facility location (i.e., over
water or on land).4-8 Using the response data, it was estimated that the percentage of water-
access facilities is 65.6 percent and land-access facilities represent 34.4 percent. This
assumption is used to distinguish which facilities will incur barge versus truck transportation
costs for those facilities that must dispose of thek TWC fluids at commercial off-site disposal
facilities.
• Average Volume of TWC Fluids Discharged Per Well: The annual volumes of workover/
treatment fluids and completion fluids discharged per well were reported hi the statistical results
of the Coastal Oil and Gas Questionnaire as 587 bbl and 209 bbl, respectively.4
4.1.2 Assumptions Adopted from the Produced Water Cost Estimate Methodology
• Percentage of Large versus Small Facilities: Two categories of facilities were developed based
on produced water flow rate: 1) medium/large facilities that would employ on-site treatment
technology,b and 2) small facilities that would utilize commercial disposal based on injection.0
b On-site treatment technology for general permit facilities includes injection for all options, and IGF for major pass facilities
in Option 1.
c All small facilities are encompassed in the zero discharge provisions of Options 1,2, and 3.
xn-io
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EPA calculated the distribution of facilities and determined that 23 percent were small facilities
(which use commercial off-site disposal facilities) and 77 percent were medium/large facilities
(which use on-site treatment/disposal technology).
• Costs to Inject TWC Fluids: These costs were calculated from the O&M costs (normalized to
a per barrel basis) that were developed for injection of produced water at medium/large
facilities. The normalized cost was multiplied by the TWC volume to obtain TWC incremental
injection costs. Detailed design O&M costs for produced water (and therefore commingled
TWC fluids) injection are presented hi Chapter XI. The assumptions used to develop design
O&M costs for injection are as follows:
• Labor: Labor costs are based on an hourly rate of $39.00 per hour (1995 $).n-12 Labor
is estimated at 2 person-hours per day for the operation of single-well injection systems.
Labor costs for multiple-well injection systems are based on 2.42 person-hours per day.
• Fuel: Fuel cost was calculated based on the maximum pumping horsepower required
above 25 hp, continuous operation (365 days per year), and a natural gas unit cost of $2.50
per 1,000 cubic feet (1995 $).13
• Maintenance Materials: Maintenance materials represent 5 percent of the equipment
purchase cost.11
• Cartridge Filter Replacement: The cost to replace filters within the cartridge filtration
system was is $0.005/bpd.9>11 Cost of replacement was based on vendor quotes and
industry comments on frequency of replacement as a function of produced water flow.9-11
• Chemicals: Total chemical cost for treating produced water for injection is $24.64/yr
(1995 $) multiplied by the daily flow rate in barrels.9
• Well Backwash: The well backwash unit cost rate was based on the results of the
statistical analysis of the Coastal Oil and Gas Questionnaire.4 Well backwash cost is
$11,135 (adjusted to 1995 $) per job and the backwash frequency is once per year.11'14
• Costs to Treat TWC Fluids with Improved Performance Gas Rotation (Option 1): The cost to
treat TWC fluids using IGF at water-access sites were calculated from the O&M costs and
volumes that were developed for IGF treatment of produced water at major pass facilities. As
described hi Section 3.0, under Option 1, only major pass facilities are considered for a
discharge option based on IGF. All other medium/large facilities comply with the Region 6
general permit zero discharge requirement for produced water.
Major Pass Facilities: Improved operation of gas flotation TWC treatment costs for
medium/large facilities were based on the costs at a water-access site. The cost
of $0.021/bbl was derived using produced water IGF operating and maintenance
costs and average annual coastal Gulf of Mexico produced water flow rate.11 For
this option, the flow did not include the flow generated by Flores & Rucks because
' Flores & Rucks already uses IGF and thus would not incur incremental compliance
costs. For one outfall at North Central, only O&M costs are incurred because that
particular facility is expected to upgrade operation of an existing gas flotation
system to IGF performance through operational improvements.6
xn-ii
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General Permit Facilities (medium/large facilities excluding major pass facilities):
Medium/large facilities typically commingle TWC fluids with produced water.4
Since these facilities will be required to cease produced water discharges effective
January 1997, capital investment for injection wells and ancillary equipment has
already been made. As a result, only incremental O&M injection costs are
incurred for disposal of TWC fluids (see Section 4,1.2 for details).
Small Facilities: Small facilities typically commingle TWC fluids with produced water.4
Since these facilities will be required to cease produced water discharges effective
January 1997, only incremental costs for commercial disposal of TWC fluids are
incurred (see Section 4.1.3 for details).
4.1.3 Additional Assumptions and Data
* Barge Capacity and Cost: Water-access facilities mat were determined to utilize commercial
disposal rather than on-site treatment and/or disposal were assumed to require a portion of a
small capacity (1,500 bbl) barge to transport the waste TWC fluids to a land-based commercial
disposal facility. These barges are divided into four equivalent and separate sections. The cost
for the use of a barge was derived by assuming that a portion of me barge would be dedicated
to TWC fluids while other wastes would be transported in the remainder of the barge.
Although it is recognized that TWC fluids would likely be mixed with other field wastes with
comparable disposal costs, such as spent drilling fluid, this approach reflects the fraction of the
barge cost attributable to the TWC volumes. Each 587-bbl volume of workover/treatment fluid
would require one-half of a single barge's capacity (750 bbl). Each 209-bbl volume of
completion fluid would require one-fourth of a barge (375 bbl). The transportation cost for a
single barge and tug is $1,097.50 (1995 $). The costs for barge transportation are estimated to
be $548.75 (1995 $) per job for workover/treatment fluids, and $274.38 (1995 $) per job for
completion fluids.14-15-"
* Truck Capacity and Cost: Land-access facilities that were determined to utilize commercial
disposal rather man on-site treatment and/or disposal were based on requiring 120-bbl capacity
vacuum trucks to transport the waste TWC fluids to a land-based commercial disposal facility
for injection.7 The cost for a vacuum truck is $1.92/bbl and was scaled (using ENR Index
numbers of 5471 to 4985)14 to 1995 dollars from the 1992 dollar cost.
* Commercial Disposal Cost for TWC Fluids: The disposal cost for disposal for TWC fluids at
a commercial disposal facility is $8.78/bbl (1995 $). The cost in 1992 dollars was scaled to
1995 dollars using ENR Index numbers of 4985 to 5471, respectively.14 This cost was obtained
from a commercial disposal company for completion fluids,17 and is applied to all TWC fluids
based on the fact that completion and workover fluids are similar types of fluids and typically
weigh nine pounds per gallon or more.
4.2 COMPLIANCE COST METHODOLOGY
Tables A-l through A-8 in Appendix XII-1 were developed to calculate the compliance cost
estimates for existing and new sources of TWC fluids. For each option and for each source category
(existing or new), two spreadsheets were created: one for workover/treatment fluids and one for
xn-12
-------
completion fluids. The input data (described in Section 4.1) applicable to each scenario are listed in each
spreadsheet. Within each spreadsheet, several different costs were calculated. Three costs were calculated
for Option 1: treatment based on improved operation of gas flotation costs at major pass facilities,
treatment based on injection for all other medium/large facilities, and commercial disposal costs at small
facilities.
For Options 2 and 3 two costs were calculated. First, on-site incremental injection costs were
calculated for all medium/large facilities (i.e., major pass facilities and general permit facilities). Second,
costs for incremental commercial disposal at small facilities were calculated. The treatment costs,
determined separately for water- and land-access facilities, consist of the following calculations:
• Number of workover/treatment or completion jobs per year
• Number of jobs injected or treated by IGF per year
• Total volume treated per year
• Treatment cost based on IGF or injection cost per year.
The commercial disposal costs, also determined for water- and land-access facilities, consist of the
following calculations:
Number of workover/treatment or completion jobs per year
Number of jobs disposed commercially per year
Total volume disposed commercially per year
Transportation cost per year
Commercial disposal cost per year
Total transportation and disposal cost per year.
The total costs presented in Table XH-1 are the sum of the costs presented in Appendix XII-1.
5.0 POLLUTANT LOADINGS AND REMOVALS
The following sections describe the bases, data and methodology used to develop pollutant
removals estimates for each regulatory option.
5.1 GENERAL ASSUMPTIONS AND INPUT DATA
Total TWC volumes are presented in Table XII-5. These volumes are based on the volume per
job for well treatment/workover (587 bbl/job) and for well completions (209 bbl/job) as described in
Section 4.1.1.4 Development of the total number of jobs is detailed in Section 3.0, and summarized in
Tables XH-2 and XH-4.
xn-is
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TABLE XH-5
TOTAL TWC VOLUMES
<*v
: x-t
Job Type
*
'; From Existing Sources
" ^{frJbytf
From New Sources
(bbl/yr) *
OPTION 1"
Treatment/Workover
Completion
Total
186,079
63,118
249,197
26,415
9,405
35,820
OPTIONS 2 & 3
Treatment/Workover
Completion
Total
205,450
69,806
275,256
26,415
9,405
35,820
" Excludes volume already meeting IGF.
The concentration data for TWC fluids used to calculate pollutant removals from settling effluent
were from an Office of Solid Waste sampling effort designed to characterize TWC fluids. 18'19i2° This
information represents the best data currently available about the characteristics of TWC fluids. These data
are presented and summarized in Chapter IX and are used hi the cost effectiveness analysis as the best
available representation of the characteristics of TWC fluids as they are currently discharged.18-19'20
Furthermore, since TWC fluids can be commingled and treated without upsetting the treatment system,
concentration data for effluent from IGF treatment is the basis for characterizing TWC fluids following
commingling and treatment with produced water.4
5.2 METHODOLOGY
The tables presented in Appendix XH-2 were developed to calculate the pollutant removal estimates
for existing and new sources of TWC fluids. For each option and for each source category (existing or
new), two tables were created: one for workover/treatment fluids and one for completion fluids. The
annual volumes discharged, injected, treated, or disposed in these tables are those calculated in the corre-
xn-w
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spending compliance cost tables in Appendix XII-1. A summary of the pollutant removal estimates is
presented in Table XII-6.
TABLE Xn-6
TOTAL ANNUAL POLLUTANT REMOVALS FOR
TREATMENT, WORKOVER, AND COMPLETION FLUIDS
(pounds/year)
"' Option ,, ; -/,, ,
Option 1:
Zero discharge except
Major Pass Facilities and
Cook Met = 29/42 mg/1
oil and grease based on IGF
Option 2:
Zero discharge except Cook
Tn1f*t — '7Q/4.'? mo/1 nil nnH
grease based on IGF
Option 3:
Zero discharge all
JftMntsmt TVnA- ^ % •.-. ..
' s? "•••? ";>,„ " f •• '
Conventionals
Priority Pollutant Organics
Priority Pollutant Metals
Non-Conventionals
Total
Conventionals
Priority Pollutant Organics
Priority Pollutant Metals
Non-Conventionals
Total
Conventionals
Priority Pollutant Organics
Priority Pollutant Metals
Non-Conventionals
Total
Existing Sources
65,179
363
260
2,818,074
2,883,876
67,665
407
281
3,372,530
3,440,883
67,665
407
281
3,372,530
3,440,883
' ^
New Sources ]
8,750
51
33
380,804
389,638
8,838
53
36
438,676
447,603
8,838
53
36
438,676
447,603
6.0 BCT COST TEST
This section presents the results of the BCT cost test for the zero discharge and treatment followed
by discharge options. The methodology for the BCT cost test is presented in Chapter X.
The compliance costs and pollutant reductions presented in Sections 4.0 and 5.0 are all considered
to be incremental to BPT-level costs and reductions because they were based on costs and pollutant
characteristics that are additional or supplemental to BPT-level treatment.
xn-is
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Table XH-7 presents the BCT cost test for the three regulatory options. All three options fail the
POTW test.
TABLE XH-7
BCT COST TEST FOR TREATMENT, WORKOVER, AND COMPLETION FLUIDS
Option - Pollutants
Removed 0bs)
65,179
67,665
67,665
POTW Cost
Ratio ($/ib)
10.2
9.9
9.9
PassEQTW
- Test?' ,
«$0.586/lb)
N
N
N
xn-16
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7.0 REFERENCES
1. Alaska Oil and Gas Association, "Miscellaneous Discharges in Cook Inlet: What Are They?"
Technical Fact Sheet No. 93-6, August 1993.
2. Wiedeman, A., EPA, Memorandum to file regarding "Coastal Oil and Gas Activity in CA,
AL, MS, and FL," September 6, 1994.
3. U.S. EPA, "Final NPDES General Permits for the Coastal Waters of Louisiana (LAG330000)
and Texas (TXG330000)," 58 Fed. Reg. 49126 (September 21, 1993).
4. SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31, 1995.
5. U.S. EPA, "Final NPDES General Permits for Produced Water and Produced Sand Discharges
from the Oil and Gas Extraction Point Source Category to Coastal Waters in Louisiana (LAG
290000) and Texas (TXG 290000)," 60 Fed. Reg. 9428 (January 9, 1995).
6. Kennedy, K., Avanti, Memorandum to the Record regarding "Development of Inventory of
Coastal Gulf States Produced Water Dischargers for Final Coastal Oil and Gas Effluent
Limitations Guidelines," September 30, 1996.
7. Erickson, M., SAIC, "Gulf of Mexico Coastal Oil and Gas: Produced Water Treatment
Options Cost Estimates," January 5, 1995.
8. U.S. EPA, "Development Document for Effluent Limitations Guidelines and Standards for the
Coastal Subcategory of the Oil and Gas Extraction Point Source Category," EPA 821-R-95-
009, February 1995.
9. Mason, T., Avanti, Memorandum regarding "Confidential Business Information Supporting
Costs and Loadings," June 6, 1996. (Confidential Business Information)
10. Wiedeman, A., EPA, Memorandum to Marv Rubin, EPA, regarding "Supplementary
Information to the 1991 Rulemaking on Treatment/Workover/Completion Fluids,"
December 10, 1992.
11. Avanti, "Compliance Costs and Pollutant Removals for Coastal Gulf of Mexico Produced
Water Assuming Full Compliance with Zero Discharge Under the Region 6 General Permit,"
September 16, 1996.
12. Kennedy, K., Avanti, Memorandum to the record regarding "Gulf of Mexico Oil and Gas
Extraction Labor Rates," April 2, 1996.
13. Kennedy, K., Avanti, Memorandum to the record regarding "GOM Natural Gas Cost," April
5, 1996.
14. Kennedy, K., Avanti, Memorandum to the record (with attachment), regarding "Cost
Adjustment Ratios to 1995 Dollars," April 8, 1996.
15. Avanti, "Compliance Costs and Pollutant Removals for Coastal Gulf of Mexico Oil and Gas
Well Treatment, Workover, and Completion Fluids," September 16, 1996.
xn-i?
-------
16. U.S. EPA, "Trip Report to UNOCAL, Intracoastal City, Louisiana, September 8-9, 1993,"
Freshwater Bayou, Vermilion Parish, Louisiana, January 25, 1994.
17. Mclntyre, J., SAIC, Communication with Kathy Cavalier, Campbell Wells, regarding waste
disposal cost information, May 12, 1994.
18. Strauss, M.A., Director, Waste Management Division, EPA Office of Solid Waste,
Memorandum to Thomas P. O'Farrell, Director, Engineering and Analysis Division, EPA
Office of Water, regarding "Use of OSW Oil and Gas Exploration and Production Associated
Waste Sampling and Analytical Data," October 4, 1994.
19. Sunda, J., SAIC, Memorandum to Allison Wiedeman, EPA Office of Water, regarding "The
exclusion of certain samples from compilation of OSW TWC data," December 1, 1994.
20. Souders, S., EPA Office of Solid Waste, Memorandum to Allison Wiedeman, EPA Office of
Water, regarding "1992 OSW Oil and Gas Exploration and Production Associated Wastes
Sampling—Facility Trip Reports," October 27, 1994.
xn-is
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CHAPTER XIII
NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND
OTHER FACTORS
1.0 INTRODUCTION
The elimination or reduction of one form of pollution has the potential to aggravate other
environmental problems, an effect frequently referred to as cross-media impacts. Under sections 304(b)
and 306 of the Clean Water Act, EPA is required to consider non-water quality environmental impacts in
developing effluent limitations guidelines and new source performance standards. Accordingly, EPA has
evaluated the effect of these regulations on air pollution, energy consumption, solid waste generation and
management, and consumptive water use. Safety, impacts of marine traffic on coastal waterways, and
other factors related to implementation were also considered. EPA evaluated the non-water quality
environmental impacts associated with these regulations for each wastestream.
Regulatory options were developed to analyze the costs and pollutant removals for drilling wastes,
produced water and treatment, workover and completion fluids (see Chapters X, XI, and XII). The non-
water quality environmental impacts (NWQI) were determined for the technologies considered to be the
bases for each of the selected regulatory options. Therefore, the control options established for each
wastestream are the same as those used in the cost and removals analyses. Table XHI-1 presents the non-
water quality environmental impacts in terms of air emissions and energy requirements for each
wastestream and option.
The produced water NWQI presented in Table Xffl-1 are the sum of the impacts of treatment
and/or disposal as they apply to Cook Inlet, Alaska and Gulf of Mexico operations. Gulf of Mexico
operations include those facilities not included in the 1995 Region 6 General Permits governing discharges
of Gulf Coastal production wastes (60 FR 2387, January 9, 1995) and are referred to in the cost, pollutant
removal and NWQI analyses as the current requirements baseline (see Chapter XI).
xra-i
-------
TABLE Xra-1
ANNUAL ENERGY REQUIREMENTS AND AIR EMISSIONS FOR
THE REGULATORY OPTIONS BY WASTESTREAM
Waste Stream Options
,*'.-
"' -*% S V? ^-"' < A „ „ »
, J * »Pri«ing Wastes
Option I: Cook Inlet = no free oil, no diesel, and
limits of 30,000 ppm SPP, 1 mg/1 Hg and 3
mg/lCd
Option 2: Zero discharge via
Scenario 1: Landfill
Scenario 2: Injection
Fuel" (BO%r)
>
S->' C
0
5,183
7,024
Air Emissions'3
(ton$/yr) !
-
0
36.37
10.58
Produced Water (Current Requirements Baseline) - /'•<'-
Option I: Zero discharge except: major pass dischargers and
Cook Inlet, Alaska operators at 29/42 mg/1 oil and grease
limitations.6
Option 2: Zero discharge except: Cook Inlet, Alaska
operators at 29/42 mg/1 oil and grease limitations.11
Option 3: Zero discharge for all.d
3,428
92,252
187,269
28.03
(17.71)
1,098.11
(356.02)
1,241.19
(499.10)
«• ff: t *> -, * "• V f: V *• *• s J * ''^f f
Treatment, Workover, Sand Cootpletion Fluids "•' '-"
Option 1: Zero discharge except: major pass dischargers and
Cook Inlet, Alaska operators at 29/42 mg/1 oil and grease
limitations.6
Option 2: Zero discharge except: Cook Met, Alaska
operators at 29/42 mg/1 oil and grease limitations.*1
Option 3: Zero discharge for all.d
1,360
1,414
1,414
14.86
15.52
15.52
BOB (barrels of oil equivalent) is the total diesel volume required converted to equivalent oil volume (by
the factor 1 BOB = 42 gal diesel) and the volume of natural gas required converted to equivalent oil volume
(by the factor 1,000 scf = 0.178 BOB).1
Air emissions calculated using emission factors for uncontrolled sources. Values in parentheses are the sum of air
emissions from Gulf of Mexico controlled sources and Cook Inlet uncontrolled sources (see Sections 3.1.2 and 3.2.2).
Flores & Rucks, Inc. (FBI) and North Central permit #2184, outfall #003-1 are not included in Option 1 analyses due
to existing gas flotation units at these facilities.
Flores & Rucks, Inc. (FRI) NWQIs at Case 2 for Options 2 and 3. FRI air emissions and energy requirements may
be considerably lower (see Section 3.1.1.2).
xm-2
-------
As discussed in Chapters IV and XI, EPA also assessed impacts of the Gulf of Mexico produced
water regulatory options for a larger population of facilities. This "alternative baseline" includes Texas
dischargers seeking individual permits (TDSIPs) and Louisiana open bay dischargers (LOBDs).
Table Xffl-2 presents the non-water quality environmental impacts calculated for the alternative baseline
requirements. NWQIs for the current requirements baseline listed in Table XDI-1 were summed with the
NWQIs for the TDSIPs and LOBDs to obtain the total NWQI for the alternative requirements baseline.
TABLE Xin-2
AIR EMISSIONS AND ENERGY REQUIREMENTS FOR PRODUCED WATER OPTIONS
(ALTERNATIVE BASELINE)
'? ^
]fr-t * Regulatory Options !" "'"
Option 1: Zero discharge except: major pass river
dischargers and Cook Inlet, Alaska operators at
29/42 mg/1 oil and grease limitations.6
Option 2: Zero discharge except: Cook Inlet,
Alaska operators at 29/42 mg/1 oil and grease
limitations. d
Options 3: Zero discharge for all.d
- fuel" " * -
,/(BQE/yr),, , ,
32,771
322,496
417,513
,'-, - - (tops/yr) ,
393
(261)
3,870
(1,294)
4,013
(1,437)
a BOE (barrels of oil equivalent) per year is the total diesel volume required converted to equivalent oil volume (by the
factor 1 BOE = 42 gal dieset) and the volume of natural gas required converted to equivalent oil volume (by the factor
1,000 scf= 0.178 BOE).1
b Aii emissions calculated using emission factors for uncontrolled sources. Values in parentheses are the sum of air emissions
from Gulf of Mexico controlled sources and Cook Inlet uncontrolled sources (see Sections 3.1.2 and 3.2.2).
c Flores & Rucks, Inc. (FBI) and North Central permit #2184, outfall #003-1 are not included in Option 1 analyses due to
existing gas flotation units at these facilities (see Section 3.1.1.1).
d Flores & Rucks, Inc. (FRI) NWQIs at Case 2 for Options 2 and 3. FRI air emissions and energy requirements may be
considerably lower (see Section 3.1.1.2).
2.0 DRILLING WASTES - COOK INLET
This section presents the energy requirements and air emissions calculated for waste management
control options for drilling wastes generated by oil and gas extraction operations hi Cook Inlet, Alaska.
In the final rule, and as detailed elsewhere in this document, EPA determined that zero discharge of drilling
wastes was not technologically available in Cook Inlet. EPA has, nevertheless, calculated the non-water
quality environmental impacts of both the selected option and of zero discharge, assuming it were available.
xm-3
-------
The NWQI analyses presented herein follow directly from the assumptions and data used in the cost and
removals analyses presented in Chapter X.
Table Xffl-1 lists two control options for management of drilling fluids and drill cuttings (drilling
waste). Option 1 allows the discharge of drilling fluid and drill cuttings with limitations requiring toxicity
of no less than 30,000 ppm (SPP), no discharge of free oil or diesel, and no more than 1 mg/kg mercury
and 3 mg/kg cadmium in the stock barite. Because Option 1 reflects current practice hi Cook Inlet, there
are no incremental NWQIs associated with this option. Option 2 requires zero discharge of drilling wastes.
The NWQIs were calculated in two scenarios for Option 2, as described below.
The two control technology bases for compliance with the zero discharge option considered for
drilling wastes hi Cook Inlet are:
Scenario 1: Waste minimization via closed-loop solids control followed by transportation of
drilling wastes to shore for disposal.
Scenario 2: Grinding followed by subsurface injection at the platform.
Appendices Xffl-1 and XUI-2 present the detailed energy requirements and air emissions calculated for
each of these compliance scenarios, respectively. The calculations for Scenario 1 are based on the total
estimated volume of drilling waste generated in the period of analysis (1996 through 2002), as calculated
for a system featuring closed-loop solids control technology. This seven-year volume, 431,988 barrels
(bbls) of waste drill cuttings and drilling fluid, was calculated as part of the compliance cost analysis
presented in Chapter X. The seven-year waste volume basis for Scenario 2 is 689,370 bbls, also presented
in Chapter X, reflecting current waste generation rates without closed-loop solids control technology. The
total 689,370 bbl comprises 626,070 bbl of waste generated from new wells and recompletions plus 63,300
bbl generated by drilling disposal wells. Hence, all drilling waste NWQI calculations presented hi the
following sections represent totals for the same seven-year period on which the compliance cost calculations
are based. The following sections discuss the bases and methods used in these calculations.
2.1 ENERGY REQUIREMENTS
Energy requirements were calculated by identifying the energy-consuming activities involved in
the two zero discharge scenarios described above and assessing the energy requirements for all fuel-driven
xra-4
-------
equipment. Table Xm-3 lists the equipment, horsepower demands (where applicable), and associated fuel
consumption calculated for each scenario, as detailed in the following discussions.
2.1.1 Closed-Loop Solids Control and Landfill
The assumptions developed for calculating fuel consumption for Scenario 1 (landfill disposal) were
based on three general activities: 1) improving the efficiency of solids control systems with a decanting
centrifuge; 2) transporting drilling wastes to landfills via boats, barges, cranes, and trucks; and 3) using
earthmoving equipment at landfills. Zero discharge of drilling wastes by landfill disposal was found to be
not technologically available in Cook Inlet (see Chapter XTV). Chapter X describes the use of boats,
barges and trucks in terms of logistics, frequency, and transport capacity. The NWQIs for waste
transportation activities are based on the data developed for the unit landfill cost analysis (see Appendix
XIH-2). The energy-specific bases used to assess Scenario 1 are as follows:
Decanting Centrifuge: A 40 horsepower decanting centrifuge2 was added to the existing solids control
equipment to increase efficiency and reduce the waste volume by 69 percent (see Chapter X). A detailed
description of decanting centrifuges and other solids control equipment is presented in Chapter VTI.
Supply Boats: Regardless of the landfill location, drilling wastes must be transferred from the platform
to the east side of Cook Inlet as the first leg of the trip. Four modes of supply-boat operation are
considered in the accounting of fuel consumption:
• Transit Fuel Consumption: Supply boats consume 130 gallons of diesel per hour while in
transit.3 Average supply boat speed is 11.5 miles per hour.4 Supply boat fuel use and speed
data are from Gulf of Mexico sources; vessels serving Gulf of Mexico platforms are considered
comparable to those serving Cook Inlet platforms. The average round-trip distance for the
supply boats to go from platforms to the East Forelands dock on the east side of Cook Inlet is
50 miles.5
• Maneuvering Fuel Consumption: Supply boats maneuver at the platform for an average of one
hour per visit. The maneuvering fuel use factor is 15 percent of full throttle fuel consumption,
or 25.3 gallons of diesel per hour.6
• Loading Fuel Consumption: Due to ocean current and wave action, boats must maintain
engines idling while at platforms unloading empty cuttings boxes and loading drilling fluids and
boxes. The total average time idling on station at the drill site for loading is 4.15 hours per
visit. This is based on the crane operating time of 3.15 hours to transfer empty cuttings boxes
to the platform and loading the full cuttings boxes onto the supply boat (i.e., 2 x 1.575 hours.
See discussion of cranes below). The average idling time includes an additional one hour to
account for potential delays in the transfer process.
xm-s
-------
TABLE Xm-3
POWER AND FUEL REQUIREMENTS FOR DRILLING WASTE
ZERO DISCHARGE OPTION SCENARIOS3
, i
,. f
Equipment -.-, J ' *
• j- ,yt
•"< fk \^,"-
s* > s,\^ * a v* '''
'"• •«.
'" Total hp-hrs^
•Xftrt- X^;s/v <$ s* ' & •>* ^+ f
i. ^ , ..f ;, *> '-- -
vX „ "/' '••' //'
"V - '' FaelUse * ' , "
' \ Natural Gas ,
'.. LCUP'JBCO
4 '•» Diesel' '
' '-- (lO'gal) '-
•* "• s ^ % w. *rX v. •> •.'"•' •, •• J < f
'- ^S(^A&G&I>jt^--mSPQS&L:^ " '„ ;, *" ' "
Closed Loop Solids Control
• Decanting Centrifuge
Transport to Landfill
• Supply Boats
• Barges
• Supply Boat Cranes
• Barged Cranes
• Trucks to/from Temporary
Storage
• Trucks to Oregon
Equipment at Landfill
• Wheel Tractor
• Dozer/Loader
TOTAL FUEL
38,920
914,400
544,068
103,027
—
—
369.74
—
—
369.74
533.09
31.56
33.32
6.31
7.89
886.65
0.81
21.47
1,521.11
TOTAL FUEL (BOE)C = 36,283
• SCENARld 2:^ GRINDING AHB INJECTION ; ' ' * I
Grinding and Processing/
Equipment
Injection Equipment
TOTAL FUEL
27,926,595
1,148,950
—
265,303
10,915
276,218
—
..
—
TOTAL FUEL (BOE)C =49,167
a All values shown are cumulative totals for the seven-year period following promulgation (1996 - 2002).
b Hp-hr requirements are only reported for equipment whose air emission factors are based on these data. Air emission
factors for other equipment are based on rates of fuel consumption.
c BOB (barrels of oil equivalent) is the total diesel volume required converted to equivalent oil volume (by the factor 1 BOE
= 42 gal diesel) and the volume of natural gas required converted to equivalent oil volume (by the factor 1,000 scf = 0.178
BOE).1
xra-6
-------
• Auxiliary Electrical Generator: An auxiliary generator is needed for electrical power only
when propulsion engines are shut down. Since the supply boats remain at the drill site only for
the length of time necessary to conduct loading/unloading evolutions and the propulsion plant
remains idling at the drill site, the auxiliary generator is only used while in port.
The average in-port time for unloading drilling wastes, tank cleanout, and demurrage is 24
hours per supply boat trip.4 The boat engines are shut down during this period. It is assumed
that while in port, the boat operator relies on the auxiliary generator for electrical power.
Estimates of fuel requirements and air emissions are based on the auxiliary generator rating at
120 horsepower, operating at 50 percent load,6 and consuming 6 gallons of diesel per hour.4
Barges: Barges consume fuel at a rate of 24 gallons of diesel per hour.3 Average barge speed is 6 miles
per hour.7 Barge fuel use and speed data are from Gulf of Mexico sources; vessels serving Gulf of Mexico
platforms are considered comparable to those serving Cook Inlet platforms. The average round-trip
distance for barges to go from the east side of Cook Inlet to the west side is 50 miles.8
Cranes: Cranes used to load and unload cuttings boxes at the drill site and in port are diesel powered,
require 170 horsepower operating at 80 percent load,6 and consume 8.33 gallons of diesel per hour.3
Cranes make 10 lifts per hour.4 For supply boats, cranes will lift four boxes at a time (see
Appendix XIII-1). Given that a supply boat will carry 12 boxes of cuttings plus 51 box-equivalents of
waste drilling mud during each trip (see Appendix X-2), and that the cranes must load and unload empty
boxes as well as full boxes within one round trip, each supply boat round trip requires 6.3 hours of crane
time, calculated as follows:
Crane lifts per boat load = 63 box-equivalents per boat load / 4 boxes per lift = 15.75 lifts/boat load
Crane hours per boat load = 15.75 lifts per load / 10 lifts per hour = 1.575 hours/boat load
Crane hours per round trip = 1.575 hrs/boat load x 4 boat loads/per round trip = 6.3 hours per round trip
For barges, cranes will lift 10 boxes per lift because the boxes are loaded into shipping containers that hold
10-12 boxes.8 Also, no empty boxes are loaded onto or unloaded from barges. Therefore, crane time for
a single barge round trip is 4.8 hours, based on a barge capacity of 240 boxes.8
Operator "B" Trucks: In the drilling waste compliance cost analysis, Operator "B" uses trucks to
transport wastes to and from the temporary storage area located on the east side of Cook Inlet and from
the barges to the disposal facility located on the west side of Cook Inlet (see Chapter X). These trucks
travel approximately four miles per gallon of diesel consumed4 and hold 12 drilling waste boxes per trip.
The round trip distance from the East Foreland dock to the temporary storage facility is four miles.9 The
round trip distance from the barge landing area to the disposal site is six miles.9 Appendix XIII-1 shows
energy consumption calculations for a 10-mile round trip, which represents the total distance for trucks
used by Operator B.
Trucks to Oregon: In the drilling waste compliance cost analysis, Operators "A" and "C" use trucks to
transport wastes to a commercial land disposal facility located in Arlington, Oregon (see Chapter X).
These trucks travel approximately four miles per gallon of diesel consumed4 and to hold 22 tons of waste
per trip.10 The one-way distance between the east-side docking facility and the land disposal facility is
estimated to be 2,200 miles.
xm-7
-------
Land Disposal Equipment: The bases supporting estimates for the use of land disposal equipment have
not changed since the proposal. These are as follows:
• Wheel Tractor: Wheel tractors are used at the facility for grading. One day (8 hours) of tractor
operation is required to grade the drilling waste volume from one well. The estimated fuel
consumption rate for a wheel tractor is 1.67 gallons of diesel per hour.4
• Track-Type Dozer/Loader: A track-type dozer is required at the facility for waste spreading.
Two days (16 hours) of dozer operation are required to spread drilling wastes generated from
one well. The estimated fuel consumption rate for a dozer is 22 gallons of diesel per hour.4
2.1.2 Grinding and Injection
Zero discharge of drilling wastes in Cook Inlet by grinding and injection was found to be not
technologically available (see Chapter XIV). The results of the NWQI analysis are presented here,
nevertheless, for informational purposes. The NWQI analysis for the second scenario of the zero discharge
option consists of determining the power and fuel requirements of the grinding and injection (G&I)
equipment. The volume of wastes injected include wastes generated from the drilling of injection wells
as well as wastes generated from the drilling of new production wells and recompletions. The volume of
waste generated from the drilling of an injection well, 5,275 barrels per well, was derived from industry
data obtained in the 1993 Coastal Oil and Gas Questionnaire, as presented hi Appendix X-l. The number
of injection wells to be drilled in the seven-year period following promulgation (12) was derived from
industry-supplied information as noted in Appendix X-l. The energy-specific basis for the Scenario 2
NWQI analysis is as follows:
Waste Processing Equipment: The waste processing equipment power and fuel requirements were
estimated based on the following horsepower requirement information submitted by the industry:11
• Grinder (500 KVA Transformed:
2 x 150 hp motors at 480V
1 x 10 hp auger motor
Additional lights/heating 100 KVA
• Cuttings Transfer Equipment:
2 x 30 hp disk flow motors
1 x 10 hp hydraulic pump
Steam as required
xra-s
-------
* Dewatering Unit:
2 x 5 hp shaker motors
1 x 10 hp agitator
1 x 45 hp dewatering centrifuge
1 x 10 hp underflow pump
2 x 30 hp disk flow pumps
1 x 30 hp Galliger pump
4 x 1/2 hp motors
For the purpose of calculating energy requirements, a total of 747 horsepower per well was used for the
above equipment.
Injection Equipment: The power and fuel requirements for the injection equipment were calculated based
on one 500 horsepower injection pump rated at 5 barrels per minute.9
Hours of Operation: The grinding and injection equipment usage (hours per well) was calculated based
on the average time required to drill a new well (733 hrs), a recompleted well (240 hrs), or an injection
well (211 hrs). These data are derived from information presented in Appendix X-l. For a 4,000-foot
injection well, the following equation was used:
(11 days x 13 hrs/day)(2500 ft/2533 ft) + (25 days x 14 hrs/day)(1500 ft/7348 ft) = 211 hours
The above equation is the sum of the hours required to drill a well in two intervals, the first being 2,500
feet deep and the second being 1,500 feet deep. The time data are relative to the first two intervals of the
model production well presented in Chapter X, whose first two intervals are 2,533 feet and 7,348 feet
deep, respectively.
Fuel Requirements: Fuel requirements were calculated for gas turbines using an average heating value
of 1,050 Btu per standard cubic foot (scf) of natural gas and an average fuel consumption of 10,000 Btu
per horsepower-hour (hp-hr), or 9.5 (10,000/1,050) scf/hp-hr.12
2.2 AIR EMISSIONS
The total air emissions for Scenarios 1 and 2 presented in Table Xni-1 were calculated using the
total system energy utilization rate (horsepower-hours or miles traveled) and emission factors developed
for different types of engines and fuels used. Emission factors were determined for uncontrolled sources.
The term "uncontrolled* refers to the emissions resulting from a source which 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 disposal of drilling wastes
in Cook Inlet. Table Xffl-4 presents the uncontrolled emission factors for different types of diesel and
natural gas driven engines used to calculate air emissions from activities related to onshore disposal and
injection of drilling wastes. Note that the factors are not all based on the same units. Detailed calculations
of the air emissions from each type of engine used are presented in Appendix Xffl-1.
xm-9
-------
TABLE Xm-4
UNCONTROLLED EMISSION FACTORS FOR
DRILLING WASTE MANAGEMENT ACTIVITIES
Equipment
Supply Boats* Idle
Ob/1,000 gal) .
Transit
Supply Boat Auxiliary
Generator (g/bhp-hr)c
Barges Ob/1,000 gal)»
Cranes (g/bnp-hr)d
Trucks (g/mile)e
Wheel Tractor Ob/hr)f
Track-type Dozer Ob/hr)f
Natural Gas Turbine Engine
(g/hp-hr)*
Auxiliary Diesel Engines
Ob/1,000 gal)c
-,v' •''" "" •.
•. •..• t
- Nttrqgen
". Oxides^
. fcrcto 1L
j •% f %
419.6
391.7
14.0
391.7
14.0
11.23
1.269
0.827
1.3
469.0
.. / ^ _.
s, ;' *. «
.Toiai; „ -
Hydrocarbons'
^ PHC>>,;;
22.6
16.8
1.12
16.8
1.12
2.49
0.188
0.098
0.18
37.5
/Sulfur
Dioxide
; (SO^
28.48b
28.48b
0.931
28.48"
0.931
NA
0.090
0.076
0.002"
31.2
•> '
; ' Carbon ;-
Monoxide
),
33.0
33.0
1.0
33.0
1.0
NA
0.136
0.058
NA
33.5
Source: Table H-3.3, AP-42 Volume n, September 1985."
Based on assumed 0.20 percent sulfur content of fuel and fuel density of 7.12 Ibs/gal (AP-42 Vol. n, September 1985).l3
Source: Table 3.3-1, AP-42 Volume I, January 1975.14 Note: bhp is brake horsepower.
Source: Table 3.3-1, AP-42 Volume I, Supplement F, July 1993." Note: bhp is brake horsepower.
Source: Table 1.7.1, AP-42 Volume H, September 1985."
Source: Table H-7.1, AP-42 Volume H, September 1985.l3
Source: Table 3.2-1, AP-42 Volume I, Supplement F, Jury 1993.15
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).n
NA = Not Applicable
Table Xffl-5 summarizes the contribution of air pollutants from each type of activity associated
with disposal of drilling wastes in Cook Inlet. For example, a seven-year total of 635 supply boat trips is
needed to transport the volume of drilling wastes under the Scenario 1 (landfill) zero discharge option. For
a boat in transit, a NOX emission factor of 391.7 lbs/1,000 gallons of diesel was used. The seven-year total
fuel requirement for supply boats in transit was calculated to be 358,913 gallons (see Appendix XIII-1).
XIII-10
-------
TABLE Xm-5
AIR EMISSIONS ASSOCIATED WITH ZERO DISCHARGE SCENARIOS
FOR EXISTING SOURCES OF DRILLING WASTES IN COOK INLET
(Total Tons for 1996 - 2002)
Equipment
-HKV
rTHC<:
S02
CO
TS>
Total,
•* "" "" '• Scenario It Closed-Loop Sotids Control aad Landfill - ""
' "",« ,,,,,',,"" , \s - , , , V - *„
Supply Boatsa
Barges
Supply Boat Cranes
Barge Cranes
Trucks for Operator B
Trucks to Oregon
Wheel Tractor
Dozer/Loader
Decanting Centrifuge
Total
101.75
6.18
8.39
1.59
0.39
43.86
0.31
0.40
0.06
162.93
5.07
0.27
0.67
0.13
0.09
9.73
0.05
0.05
0.01
16.07
7.23
0.45
0.56
0.11
0.00
0.00
0.02
0.04
0.00
8.41
19.57
1.24
1.82
0.34
0.30
33.32
0.88
0.10
0.04
57.61
8.30
0.52
0.60
0.11
0.00
0.00
0.03
0.03
0.00
9.59
141.92
8.66
12.04
2.28
0.78
86.91
1.29
0.62
0.11
254.61
^ " ., "^ iT
•• , > * ^ _ ww •. •, S-.S- ' -.%•.-.•.', -. z
Grinding/Processing Equipment
Injection Equipment
Total
39.98
1.64
41.62
5.54
0.23
5.77
0.06
0.00
0.06
25.53
1.05
26.58
NA
NA
NA
71.11
2.92
74.03
a The values given for supply boats are the sum of emissions from fuel used in transit, maneuvering, loading, and auxilliary
generator use while in port. See Appendix XHI-1 for detailed calculations.
The total annual NOX emissions resulting from this activity are:
(391.7 lb/1000 gal) x (358,913 gal) x (1 ton/2000 lbs/7 yrs) = 10 tons NOX per year.
The operation of the grinding and injection equipment to dispose of the drilling wastes under the
Scenario 2 zero discharge option requires a total of 29,075,545 hp-hr over seven years (see
Xffl-11
-------
Appendix Xffl-2). For a natural gas driven turbine, an NOX emission factor of 1.3 g/hp-hr was used. The
total annual NOX emissions resulting from this activity are:
(1.3 g/hp-hr) x (29,075,545 hp-hr/7 years) x (1 ton/908,000 g) = 5.95 tons NOX per year.
2.3 SOLID WASTE GENERATION AND MANAGEMENT
The limitations selected for drilling wastes in the final rule will not cause generation of additional
solids. As discussed below, if zero discharge were available in Cook Inlet, spent drilling fluids and the
associated cuttings would be disposed of at onshore disposal sites or injected underground.
There are currently no commercially operating disposal sites in Cook Inlet accepting coastal drilling
wastes. The only land disposal facility accepting drilling wastes from Cook Inlet operations is privately
owned and operated. The lack of commercial disposal sites would require operators that do not own a land
disposal facility to either transport the drilling wastes to the nearest known commercial disposal facility
located in Oregon or inject the drilling wastes into underground formations if available.
Capacity estimates for the disposal facility at Kustatan show that this landfill has enough storage
capacity to accept the volume of drilling wastes (303,022 bbl/7 years) that would be generated under the
no discharge limitation, from the platforms that it now serves. The solid waste disposal facility at Kustantan
has 86 cells, each with a storage capacity of 2,000 yd3 (9,620 bbl).16-17 The total capacity is 827,320 bbl.
Under a zero discharge requirement, the volume of drilling wastes generated by the operators that
own/operate the Kustatan landfill represents about 37 percent of the excess available capacity at Kustatan.
Under the zero discharge limitations of Option 2, the volume of drilling wastes estimated in
Scenario 1 as requiring land disposal is 431,988 bbl (see Appendix Xffl-1). Of this total volume of drilling
•wastes, 128,966 bbl over the next seven years, or 18,424 bbl/yr (see Chapter X) were estimated for
disposal to commercial facilities in the lower 48 states. The Arlington, Oregon landfill has an available
capacity of about 4.8 x 10s bbl.18 The Cook Inlet drilling waste that would be transported to Oregon
represents about 0.03 percent of the available capcity at the Arlington, Oregon site.
xm-12
-------
2.4 CONSUMPTIVE WATER USE
Since little or no additional water is required above that of usual consumption, no consumptive
water loss is expected as a result of the final rule.
2.5 OTHER FACTORS
2.5.1 Impact of Marine Traffic on Coastal Waterways in Cook Inlet
EPA does not expect any incremental increase hi vessel traffic as a result of the drilling waste
requirements in the coastal guidelines. EPA did evaluate the number of boat trips that would result from
zero discharge limitations, if available, and estimated that 635 supply boat trips and 158 barge trips would
occur for a total of 793 additional vessel trips over seven years (see Section 2.1.1). This is equivalent to
approximately 113 trips per year as a result of compliance with a zero discharge requirement.
2.5.2 Safety
In 1992, EPA evaluated data associated with personnel casualties that occurred on mobile offshore
drilling units (MODUs) and offshore supply vessels (OSV) for the years 1981 through 1990. The
personnel casualty data was compiled from the U.S. Coast Guard's Personnel Casualty file (PCAS). The
study focused on accidents related to the handling and transportation of material, since this would be most
similar to the additional activities required should a zero discharge limitation be imposed in Cook Inlet.19
EPA reviewed the data to determine the number of accidents related to activities similar to those
taht would occur during the handling of drill cuttings. The following types of accidents were selected from
the database as indicators of injuries that may have resulted from the handling of drill cuttings:
• Struck by falling object
• Struck by flying object
• Stuck by moving object
• Struck by vessel
• Struck by object - Not Otherwise Classified
• Bumped fixed object
• Cargo handling - Not Otherwise Classified
• Line handling
• Caught in lines
xm-i3
-------
• Pinched/crushed
• Unknown
• Not classified
The PCAS file is composed of U.S. Coast Guard 2692 forms and contains the following
information: case number, last name, first name, date of birth, status, nature of the accident, nature of the
injury, the body part injured, result, cause, office, location of the person at the time of accident, the
activity of the person at the time of the accident, the body of water, the year the vessel was built, the date
of the casualty, industry time, company time, name of the vessel, operating company, vehicle identification
number, flag, service, use, design, length, gross tonnage, time on duty, and case year. Form 2692 is
entitled, "Report of Marine Accident, Injury or Death." The 2692 form is included in the PCAS file based
on the occurrence of the following:
• A death
• An injury to five or more persons in a single incident
• An injury causing any person to be incapacitated for more than 72 hours.
The actual injury report forms were not reviewed, therefore the specific number of casualties
resulting from the handling of drilling waste is not known. The casualties evaluated in this report are the
total number of casualties for general types of accidents and may include casualties resulting from other
drilling activities as well as the handling of drilling waste.
In addition to the type accident, the survey identified the cause of the accidents. The cause of
accidents was further classified into "safety related" and "not safety related" categories. Safety related
causes were results of accidents that could be avoided through some form of increased safety awareness.
Non-safety related causes were those accidents considered unavoidable. Table Xin-6 presents the primary
causes and classification of accidents on MODUs and OSVs.
Evaluation of the database revealed that the majority of the accidents were caused by human factors
related to safety practices and procedures. Accident reports from one oil and gas company "showed that
more than 80 percent of all injury accidents were caused by human behavior or more specifically,
xin-i4
-------
TABLE Xffl-6
PRIMARY CAUSES AND CLASSIFICATION
OF ACCIDENTS ON MODUs AND OSVs
Primary Cause" ,™, _ r ,
Adverse Weather
Carelessness, Another or Self
Chemical Reaction
Deck Cluttered or Slippery
Equipment or Material Failure
Failure to use Safety Equipment
Improper Loading/Storage
Improper Maintenance or Supervision
Improper Tools/Equipment
Inadequate/Missing Guarding or Railing
Inadequate Training
Misuse of Tools/Equipment
Mooring Line Surge
Physical Factors, Self
Unsafe Movement, Another or Self
Unsafe Practice, Another or Self
Vessel Casually
Unknown
Not Elsewhere Classified
Classifieafior >
unavoidable
avoidable
unavoidable
avoidable
unavoidable
avoidable
avoidable
avoidable
avoidable
avoidable
avoidable
avoidable
unavoidable
avoidable
avoidable
avoidable
unavoidable
unavoidable
unavoidable
by unsafe practices."20 The evaluation of the personnel casualty data concluded the following:
Greater than 75 percent of the accidents occurring on MODUs from 1981 through 1990
were caused by human error or unsafe practices or procedures.
Greater than 60 percent of the accidents occurring on OSVs from 1981 through 1990 were
caused by human error or unsafe practices or procedures.
Over the last three years of the study (1988 to 1990), the number of casualties on MODUs
decreased while the drilling activity remained fairly constant.
From the data examined it is not possible to predict the effect of transportation of drilling
waste to shore on the number of personnel casualties.
The number of casualties occurring on supply vessels does not appear to be directly related
to drilling activity.
xm-is
-------
• Since the number of increased crane handling events is very small in relation to the total
number of handling operations occurrring at drilling and production sites, no discernable
increase in casualties attributable to onshore disposal of drilling wastes is anticipated.
The technology basis for compliance with zero discharge limitations of drilling fluids and cuttings
is to either bulk load the material onto barges or load individual containers onto offshore service vessels
(OSV). Typically, OSVs in Cook Inlet are used to transport wastes from the platform to shore, then barges
are used in summer to transport drilling wastes across the Inlet to the Kustatan landfill for disposal.
Containers or boxes are used to hold the excess and/or used drilling fluids and cuttings and have
approximate capacity of 8 barrels. Cranes load these containers onto and off of offshore service vessels.
A zero discharge limitation for drilling wastes would be expected to increase crane-related and vessel
transport activity because of the need to deliver drilling fluids and cuttings wastes to shore for disposal.
3.0 PRODUCED WATER
In assessing non-water quality environmental impacts for produced water, EPA projected energy
requirements and air emissions associated with the regulatory options considered and evaluated the potential
for degradation of underground sources of drinking water. The annual energy requirements and air
emissions for the produced water control technologies considered by EPA for the Gulf of Mexico and Cook
Inlet are presented in Table Xffl-1 and Table XLtt-2 for the current and alternative baselines, respectively.
The following sections describe the bases and methodologies for the NWQI analyses performed for Gulf
of Mexico and Cook Inlet regions and for both the current and alternative baselines.
3.1 GULF OF MEXICO BASELINE
Annual energy requirements and air emissions for the produced water control technologies
considered by EPA for the Gulf of Mexico are presented in Table Xffl-7. These estimates are incremental
to current NPDES permit requirements and thus represent the expected increase above current emissions
levels and energy consumption. Only the incremental NWQIs resulting from additional requirements for
to current NPDES permit requirements and thus represent the expected increase above current emissions
levels and energy consumption. Only the incremental NWQIs resulting from additional requirements for
facilities discharging offshore produced water into major passes of the Mississippi River are presented hi
the following sections.
xm-i6
-------
TABLE XHI-7
GULF OF MEXICO AIR EMISSIONS AND ENERGY
REQUIREMENTS FOR PRODUCED WATER OPTIONS
(CURRENT REQUIREMENTS BASELINE)
^ " "^ - ^" '5 ' " >' <
Regulatory Options ;
Option 1:
Options 2
Zero discharge except: major
pass river dischargers at 29/42
mg/1 oil and grease limitations.0
and 3: Zero discharge for all Gulf of
Mexico facilities/
= Fuel8
;
-------
calculated by identifying the specific activities that are necessary for the treatment and injection of
produced water.
3.7.7.7 Improved Gas Flotation
Energy requirements for improved gas flotation represent the power required to operate an
improved gas flotation system designed for compliance with oil and grease limitations in produced water
discharged to surface waters. The following assumptions were made in calculating the energy requirements
for improved gas flotation:
• Gas flotation equipment including the feed pumps will be run by electricity.21
• Electric power will be supplied by existing diesel-fueled power sources for systems requiring
less than or equal to 25 horsepower.21
• Electric power will be supplied by natural gas-fueled generators for systems requiring power
greater than 25 horsepower.22
• Fuel requirements and air emissions for improved gas flotation are based on either the additional
electricity required above 25 horsepower or the additional incremental load on existing power
sources less than or equal to 25 horsepower.
Energy requirements for commercially available IGF systems were obtained from equipment
vendors for systems of four different sizes ranging in treatment capacity from 1,700 to 77,000 barrels per
day (bpd).23 Electricity requirements in kilowatts (kW) for each unit were calculated using 0.75 kW/hp
as a conversion factor. Fuel requirements were calculated for natural gas turbines assuming a heating value
of 1,050 Btu/scf of natural gas and an average fuel consumption of 10,000 Btu/hp-hr, or 9.5(10,000/1,050)
standard cubic feet (scf) of natural gas per horsepower-hour (hp-hr).12 The usage rate for these systems
is assumed to be 365 days per year or 8,760 hours per year. An example calculation of the natural gas fuel
requirement for a 1,700 bpd IGF unit is:
Natural gas fuel (million standard cubic feet) = 12.25 hp x 8,760 hrs/yr x 9.5 scf/hp-hr = 1.02 MMscf
Table Xffi-8 presents energy and fuel requirements for the four IGF units evaluated.
xra-is
-------
TABLE Xm-8
FUEL REQUIREMENTS FOR GAS FLOTATION UNITS24
Feed Rate (bpd), ;
Power Required (hp)
Electricity Required (kW)
Fuel Required (scf/yr)
, iTOQ
12.25
9.2
1.02xl06
t
-------
TABLE Xm-9
IMPROVED GAS FLOTATION ENERGY REQUIREMENT CALCULATIONS
Design
Flow
200
1,000
2,000
5,000
10,000
15,000
25,000
40,000
80,000
Improved Gas
Flotation
Calculated .•
Horsepower
. •. '"•' „„ "
11.9
11.9
12.3
15.8
21.7
27.6
39.4
57.1
104.2
•• ,. -,••. > ••'• "•. <•
•• ^ ••.. •? ,• t "•
" ^eeclBiinp^ "
Calculated
JforeeipoVer -
, - ^V<,, } VX/J
, s S ;• '^
0.3
1.5
3.0
7.0
.14
21
35
57
113
S As ** •> f .-'•..•> * ^^ f " '- *'••$•'*
%• \ *" ^" "'' f ^ ' ' Ju '* * * '* ,vc s-y *•
„**-; ,.t . r^*^^^,,,r,; : ^ ^
\; : ,. > f
Xfiesd-I^efed :
'-;. Efccfric
' ^ov^er (hpf
12.2
13.4
15.3
22.8
—
—
—
_ _
—
' .Njatoral Gas-
Fueled laectric
s Powet^ Jltael s
s
-------
TABLE XIII-10
POWER AND FUEL REQUIREMENTS FOR PRODUCED WATER
GAS FLOTATION IN THE GULF OF MEXICO
f,S -**>-'• vf"
tr&utfeif i
3229-001-3
2963-006
2071-004-1
2400-001
2184-002-2
2184-003-1
2184-001
3407-001
TOTAL
">,- -' - Operator y* * '.» -
^. ;)'•%. ••;. t ^J-fe •--.•. }'*„•**
Chevron Pipe Line Co.
Warren Petroleum Co.
Flores & Rucks, Inc. (b)
Gulf South Operators
North Central
North Central (b)
North Central
Amoco
't--W:^
18,920
1,808
153,895
291
1,910
7,606
572
6,290
191,292
''*',-<••. , y - * ~ * -. ' *
-V, f,v Electric Power',, * ;
^^
15.38
—
11.96
15.61
12.59
134,719
104,731
136,735
110,286
486,471
3$S
<5fe>
8,891
6,912
9,025
7,279
32,107
:KaW«il
4
-------
and North Central (permit #2184, outfall #003-1) do not incur any incremental energy requirements since
they have existing gas flotation systems.
3.1.1.2 Subsurface Injection
Energy requirements for produced water injection systems were estimated based on produced water
being pretreated by cartridge filtration and then injected into a well with a capacity of 5,000 bpd at an
injection pressure of 1500 psig.21 The following list summarizes the bases used in calculating the energy
requirements for injection:
• Fuel Sources: For facilities with total energy requirements for their injection systems of less
than 25 horsepower, existing diesel-fueled power is available.21 For facilities with total injection
system energy requirements of 25 horsepower or more, the first 24 horsepower of electrical
energy requirements is supplied by existing natural gas-fueled power sources.21 All injection
equipment that exceeds the first 24 horsepower of energy requirements is powered by natural
gas-fueled engines.22 .
• Feed Pumps: For feed pumps included hi injection systems whose total power demand is less
than 25 horsepower (up to the design produced water flow rate of 500 bpd), electricity will be
supplied by existing diesel-fueled power sources.21 Feed pumps that are included in systems
whose total power demand is 25 horsepower or greater will be powered by electricity or natural
gas-fueled engines, depending on the produced water flow rate. For design flow rates of 1,000
bpd to 18,000 bpd, all feed pumps are electric. For produced water flow rates of 30,000 and
42,000, both electric and natural gas engine feed pumps are used. The electric pumps used in
these larger injection systems are included to take advantage of the existing source of electricity
that supplies up to 24 horsepower.
• Injection Pumps: Injection pumps included hi injection systems whose total power demand is
less than 25 horsepower21 will be powered by existing diesel-fueled power sources. For
injection systems with total power demands of 25 horsepower or greater, the injection pumps
will be powered by natural gas-fueled engines.22 One natural gas driven injection pump
(reciprocating internal combustion engine) is required per every 5,000 barrels of produced water
per day.25 According to one operator, reciprocating internal combustion engines are more
prevalent in the Gulf of Mexico operations than gas turbine engines.27
To determine the produced water flow rate at which a power demand of 25 hp is reached, a
regression analysis was performed using the data in Table Xin-11. Using data for the four design flows
between 200 bpd and 5,000 bpd, the total horsepower resulted in the following equation:26
HP = 4.204 + 0.035 x (flow, bpd)
xra-22
-------
For 25 horsepower, the corresponding calculated produced water flow was 603 bpd. It was
assumed that the existing electric power for facilities below 603 bpd was diesel generated for both the feed
and injection pumps. For facilities with flows above 603 bpd, both the incremental electric load for the
feed pumps and the engines for the injection pumps were assumed to be supplied by natural gas. This is
based on the assumption that larger facilities use natural gas as their onsite power source.22
Because the filter feed and injection pumps were assumed to be driven by either diesel or natural
gas fuel, mathematical models were generated for each fuel type to determine the distribution of the energy
requirements corresponding to the range of design flow rates. Table Xni-11 lists the power requirements
for produced water injection systems. Electric power supplies power to feed pumps, except for injection
pumps at the 200 bpd and 500 bpd design flows. Natural gas-driven engines primarily power injection
pumps, except for the 30,000 bpd and 42,000 bpd design flows where two 12-hp and five 12-hp natural
gas driven feed pumps are included, respectively.
Three mathematical models were developed to determine the requirements for flows other than the
design flows. The model equations used to determine energy requirements and fuel type distribution are
listed in Table Xffl-12.26
The equations in Table XIII-12 were used to determine the energy requirements for the facilities
in the Gulf of Mexico to inject produced water. The results are listed in Table Xffl-13. For the current
requirements baseline, the total diesel fuel use (19,328 gal/yr) and the total natural gas fuel use (507.80
MMscf/yr) were converted to BOB per year and summed to determine the total fuel use for Options 2 and
3 (90,847 BOE/yr), as shown in Table Xffl-7.
The zero discharge option NWQI data presented in Table Xffl-13 include Flores & Rucks, Inc.
(FRI) at Case 2. A discussion of the selection of Case 2 as a reasonable scenario is provided in
Chapter XL Energy requirements for FRI were calculated separately for all four cases and are also
presented in Table Xffl-13. As described in Section 3.1, all of the produced water is injected in dedicated
injection wells in Case 1 or is injected into waterflood wells as well as some dedicated injection wells in
Case 2. For Cases 3 and 4, coastally-derived produced water is injected and natural gas is used to supply
all power requirements. Offshore-derived produced water is segregated and treated using improved gas
flotation units installed on satellite platforms offshore. Natural gas power was calculated for the IGF unit
and feed pumps using the regression formula presented in Section 3.1.1.1. Existing equipment and power
xm-23
-------
TABLE Xra-11
DESIGN POWER AND FUEL REQUIREMENTS FOR PRODUCED WATER INJECTION"
Design
Flow
.(bpfl)
200
500
1,000
5,000
10,000
18,000
30,000
42,000
Power Requirements
Diesel-Fueled „
Electric Power (bp)-; . .
/ "Feed Pumps
<'.NoV*
< ,-• .
1
1
,fcP
1
1
Tothp
1
1
• lujectipn Pumps
No.
1
1
hp •
8
18
ITbt. hp
8
18
Natural Gas-Fueled
Electric Power (hp) '
FeedPunips • -
No-;
1
1
2
4
4
4
;.KP
2
6
6
6
6
6
TotThp
2
6
12
24
24
24
Natural Gas-Driven
, EugineK(hpX - ' ,
FeedPwnps
Wr<
„_
--
--
--
2
5
;Hp
__
--
--
--
12
12
yothg
--
--
--
--
24
60
% 'Injection PmuBsfv j.
*No.*
1
"1
2
4
6
9
hp~
42
170
170
170
170
170
Tot. hp
42
170
340
680
1,020
1,530
Total
Horse-
power
<*
9
19
44
176
352
704
1,068
1,614
a Source: Erickson, M., January 5,1995.21
-------
TABLE Xm-12
MATHEMATICAL MODELS FOR POWER REQUIREMENTS
Condition of Power Requirement ''
Diesel electric power for flows less than 603 bpd
Natural gas electric power for flows greater than 603 bpd
Natural gas power for flows greater than 603 bpd
Mathematical Model , ^
HP =
HP =
HP =
2.33 + 0.033 x (flow, bpd)
0.0013 x (flow, bpd) - 0.372
0.037 x (flow, bpd) - 10.855
sources currently used for waterflooding are assumed to be available for produced water disposal in Cases
2 and 4. Therefore, incremental non-water quality environmental impacts are not incurred by water-
flooding activities in these cases. Only dedicated injection wells and offshore improved gas flotation units
incur incremental NWQIs.
3.1.1.3
New Sources
All North Slope coastal facilities and coastal facilities in California, Alabama, Mississippi, and
Florida already inject all produced water for disposal or for use in waterflood operations (see Chapter IV).
The EPA Region 6 general permits for coastal Louisiana and Texas prohibit the discharge of produced
water (produced water derived from the offshore subcategory which is discharging to major deltaic passes
of the Mississippi River are not covered by the general permit). New sources in these areas would be
expected to comply with zero discharge limitations under applicable existing regulatory requirements. EPA
projects no new sources of produced water "discharging [produced water from the Offshore Subcategory]
into the main passes of the Mississippi River below Venice or into the Atchafalaya River below Morgan
City including Wax Lake Outlet."28'29 In the absence of NSPS, new sources in the coastal Gulf of Mexico
region would be required to comply with the zero discharge requirement of the Region 6 General Permits.
Thus, new sources in the Gulf of Mexico are expected to incur no incremental NWQIs due to promulgation
of zero discharge limitations under NSPS.
3.1.2 Air Emissions
EPA estimated air emissions for each facility not covered by the Region 6 General Permits by
calculating the product of specific emission factors, the usage in hours (i.e., hours per year), and the
horsepower requirements. Air emissions for each treatment technology were calculated on the basis of
XIH-25
-------
TABLE XHI-13
ENERGY AND FUEL REQUIREMENTS FOR PRODUCED WATER INJECTION IN GULF OF MEXICO FACILITIES
Permit-
Outfall
Number
3229-001-3
2963-006
2071-004-1
2400-001
2184-002-2
2184-003-1
2184-001
3407-001
Operator
Chevron Pipe Line Co.
Warren Petroleum Co.
Flores & Rucks, Inc. (b)
Gulf South Operators, Inc.
North Central
North Central
North Central
Amoco
TOTAL
Current
Avg. Vol.
(bpd)(a)
18,920
1,808
153,895
291
1,910
7,606
572
6,290
191,292
ElcclrJc Power
From Diesel
P)
714.36
78.08
4,616.23
—
81.87
293.67
—
244.74
--
(hp-hr/jr)
6,257,770
684,000
40,438,153
—
717,223
2,572,541
—
2,143,890
52,813,577
Natural Gas
Fuel Use
(MMscf/yr)
61.45
6.73
386.16
—
7.06
25.31
—
21.09
507.80
See Chapter XI. (b) FRI data presented is at Case 2. All four cases are detailed in the table below.
FLORES & RUCKS, INC ZERO DISCHARGE CASE ANALYSES
, \ Cases " -*
Case 1: PW to New Injection Wells
Case 2
PW to Waterflooding Wells
PW to New Injection Wells
Case3
Coastal Portion (New Injection)
Offshore Portion (IGF)
Case 4
Coastal Portion (Waterflooding)
Offshore Portion (IGF)
*
Current
Ayg. Y$l-
(bpd) w
153,895
30,038
123,857
30,038
123,857
30,038
123,895
EJectrfc ^ower From" ^
•* .Natural (Sas " '
&&
24
24
24
-
- fhp-iiryyf} -
210,240
210,240
210,240
-
Natural Gas Poiyer Fox
' qasUotatidh *
flat
-
331
331
._ (hp-hr/yr)
-
2,901,090
2,901,090
Natural Gas Power
For Injection Pumps
(hp}"
5,733
4,616
1,128
-
^M/yr)
50,222,217
40,438,153
9,879,157
-
<•Na.tur.al (fas
, Fuel IM>
, (fMMScf/yr) <
479.11
386.16
95.85
27.56
27.56
' See Chapter XI.
-------
emission factors for diesel industrial engines and natural gas-fired reciprocating engines. According to
industry sources, engines used at Gulf of Mexico tank batteries and compressor stations are reciprocating
internal combustion engines.27 Table Xffi-14 presents the emission factors used in calculating air emissions
for all treatment technologies considered. The natural gas emissions factors have been updated since
proposal to incorporate current factors published by EPA in "Compilation of Air Pollutant Emission
Factors."
EPA based air emissions calculations on the assumption that the fuel-burning equipment used for
compliance with either the gas flotation or zero discharge options does not contain any emissions control
technology. In fact, engines with some form of emissions control are readily available to the oil and gas
industry.30 EPA, therefore, estimated for comparative purposes the air emissions of natural gas engines
with nitrogen oxides- (NOx) reducing technology. Table Xffl-14 also lists the controlled emission factors
for natural gas-fired reciprocating engines.
Nitrogen oxides readily form in the high-temperature, pressure, and excess air environment found
in natural gas-fired compressor engines. To lower NOX emissions, reciprocating engines have been
developed with both combustion controls and post-combustion catalytic reduction. Sulfur oxides (SOx)
emission are not affected by the control technology. This is because SOX emissions are proportional to the
sulfur content of the fuel and will usually be quite low for natural gas oxide due to its negligible sulfur
content.30
Emission reduction technologies are also available for diesel fueled industrial engines. These
technologies are categorized into fuel modifications, engine modifications, and exhaust treatments.
However, current data are insufficient to quantify the resulting emissions due to the modifications and are
not presented in the AP-42 publication.30
Tables XIII-15 and XIII-16 list the uncontrolled and controlled air emissions, respectively,
calculated for each of the Gulf of Mexico facilities for improved gas flotation. Tables Xffi-17 and XIII-18
list each facility's uncontrolled and controlled air emissions, respectively, for subsurface injection. An
example calculation for uncontrolled natural gas carbon monoxide emissions is:
(515,685 hp-hr/yr) x (1.6 g CO/hp-hr) x (1 ton/908,000 g) = 0.91 tons CO/yr
xm-27
-------
TABLE Xm-14
UNCONTROLLED AND CONTROLLED EMISSION FACTORS
J
Pollutant
Carbon Monoxide (CO)
Nitrogen Oxides (NO*)
Sulfur Dioxide (SOj)
Total Hydrocarbons (THC)
Total Suspended Particulates
1;" ^WA -Av^^s '#, ;*
Uncontrolled Natural
G^s Factors fo»r £
Redprocaiing Enginfes*
-------
TABLE Xm-15
UNCONTROLLED AIR EMISSIONS FOR PRODUCED WATER IMPROVED GAS FLOTATION IN COASTAL GULF OF
MEXICO
(Current Requirements Baseline)
« Outfall,/-
r/jUSjttejr':,
3229-001-3
2963-006
2071-004-1
2400-001
2184-002-2
2184-003-1
2184-001
3407-001
I-A-'-V, ~- 1; sV» /i ^'- -.-••/-.
^i^m:/,^,
%; • i , •, --, * j ~-\ c/ "'• » , • * |", ';
Chevron Pine Line Co.
Warren Petroleum Co.
Flores & Rucks. Inc. (at
Gulf South Operators. Inc.
North Central
North Central (a)
North Central
Amoco
TOTAT,
jW-;s-"" '->";•'';'
j'ffilsd&per'I. ,
, ^(hp-hWytsp;-; »
..
134.719
__
104.731
• 136.735'
__
110.286
_.
486,471
$?•>?' - '-;,-'' ?'-'
" 'NatarM-Gas'- '-
;\4^or\>>
«=> sfhp-hr/yr) .. t -
515.685
__
__
..
__
__
__
228.582
744.267
T.I.TS'?,
,> .,'*. ,$ - *,
'-•; -ex%,,s
0.91
0.45
0.35
0.46
._
0.37
0.40
2.
*..PK"-^.
2.78
0.17
0.13
0.17
__
0.14
1.23
4.A2
sMjrsir
0
0.15
0.12
0.15
„
0.12
0
n..';
10.51
2.98
__
2.32
3.02
_.
2.44
4.66
25.92
TABLE XIII-16
CONTROLLED AIR EMISSIONS FOR PRODUCED WATER IMPROVED GAS FLOTATION IN COASTAL GULF OF
MEXICO
(Current Requirements Baseline)
I Permit-/
- - Outfall » -
3229-001-3
2963-006
2071-004-1
2400-001
2184-002-2
2184-003-1
2184-001
3407-001
TOTAT,
J - - *%•'-• v *-•'*•-
Chevron Pine Line Co.
Warren Petroleum Co.
Flores & Rucks, Inc. fa)
Gulf South Operators. Inc.
North Central
North Central fa)
North Central
Amoco
,:x"J ; /;;_
, **$$&.'.-
._
134.719
__
104.731
136.735
„
110.286
__
486,471
-- Natttral'Gas- '*
/;j(JjSEJb*;t
515,685
„
..
__
__
„
„
228.582
744,267
-• ..' ¥" ' ^
*.'*<»'•*
0.62
0.45
„
0.35
0.46
__
0.37
0.28
2.53
- ,; > '•-
-W&-,i
1.31
2.08
__
1.61
2.11
„
1.70
0.58
9.39
i-Vm&i
».W»**-
0
0.14
__
0.11
0.14
__
0.11
0
n.sn
ons (toiis/yt
''TKC'; -'
1.42
0.17
„
0.13
0.17
__
0.14
0.63
2.65
,. '•- f
A *
0
0.15
„
0.12
0.15
__
0.12
0
0.54
'•, •> • ; , *
-%-TotaI^-.
3.35
2.98
„
2.32
3.02
„
2.44
1.49
IS.fifl
a These facilities have existing improved gas flotation systems and do not require additional power and fuel.
-------
TABLE XHI-17
UNCONTROLLED AIR EMISSIONS FOR PRODUCED WATER INJECTION IN GULF OF MEXICO COASTAL FACILITIES
Permit-Outfall
Number
3229-001-3
2963-006
2071-004-1
2400-001
2184-002-2
2184-003-1
2184-001
3407-001
Operator
Chevron Pipe Line Co.
Warren Petroleum Co.
Flores & Rucks, Inc. (a)
Gulf South Operators, Inc.
North Central
North Central
North Central
Amoco
TOTAL
Diesel
Power
(bp-hr/yr)
..
-
-
105,403
-
-
187,447
-
292,850
Total Natural Gas
Power
.(hp-hr/yr)
6,468,010
708,248
40,648,415
-
742,655
2,664,101
--
2,220,173
53,451,602
Emissions (tons/yr)
CO
11.40
1.25
71.63
0.35
1.31
4.69
0.63
3.91
95.17
NO,
85.48
9.36
537.20
1.63
9.81
35.21
2.89
29.34
710.92
SOi
0.01
0(b)
0.09
0.11
0(b)
0.01
0.19
0(b)
0.42
THC
34.90
3.82
219.36
0.13
4.01
14.38
0.23
11.98
288.81
TSPfe)
NA
NA
NA
0.12
NA
NA
0.21
NA
0.32
Total
131.80
14.43
828.28
2.33
15.13
54.29
4.15
45.24
1,095.64
(a) FRI is analyzed for Case 2. All four cases are analyzed separately below.
(b) These values are rounded to zero due to limitation of significant figures.
(c) Emission factors for total suspended particulars (TSP) are given only for diesel-fueled power sources.
FLORES & RUCKS, INC ZERO DISCHARGE UNCONTROLLED AIR EMISSIONS
"* i- • --" ' ft**** " |'< ' •>'
- ' - < , s<"-v' ; ".-- *•'>*
;', :4To,'' cise*
r -_fj>nv V_K«: -»--'*;*
Casel
PW to New Injection Wells
Case 2
PW to Waterflood Wells
PW to New Injection Wells
Case3
Coastal Portion (New Injection)
Offshore Portion (IGF)
Case 4
Coastal Portion (Waterflooding)
Offshore Portion (IGF)
,. Natural *•£<-'' - '* "•-.""
* ~ -^ ' •' *. >> ^
^ V^r; ,;,
88.87
71.63
17.78
5.11
5.11
-? #* *> <•• '' ' < *•
*;-4S9<' »
666.51
537.20
133.34
38.34
38.34
;J!fe^
0.11
0.09
0.02
0.01
0.01
- THC,^;
272.16
219.36
54.45
15.66
15.66
-TSpl?-
NA
NA
NA
NA
NA
V; 'Total *'~
1,027.64
828.28
205.59
59.11
59.11
-------
TABLE Xffl-18
CONTROLLED AIR EMISSIONS FOR PRODUCED WATER INJECTION IN GULF OF MEXICO COASTAL FACILITIES
»'•«• "-;" < »-"-'i C'~
3229-001-3
2963-006
2071-004-1
2400-001
2184-002-2
2184-003-1
2184-001
3407-001
hi ': '' t '\'- - * I' ilxV-s..
'» -* -V , s •-, ;V"Qperdto- * > »-"--iv, - '•
<••. '•!"<• ,,-,-f -•'';"• i 'i $ 'r'lA ",!: '-
^ "X ," ,**">'$'* **..' * *.,/»••<>'<*
Chevron Pipe Line Co.
Warren Petroleum Co.
Flores & Rucks, Inc. (a)
Gulf South Operators, Inc.
North Central
North Central
North Central
Amoco
TOTAL
:toi|rp- f
> j-PoWfe '!'
~;;
-
-
-
105,403
-
-
187,447
-
292,850
,fotrfr&tiwai'efas
» ;< ,, <• <0 , <•!* *•<-,;-••!, '-',? >,,,
- -. ^i r -!*.»',,, JmisstonS (tbns/jfr)- , - » > -'< - ~'4
J'-GO^"-
7.84
0.86
49.24
0.35
0.09
3.23
0.63
2.69
65.73
:JHv:
16.38
1.79
102.96
1.63
1.88
6.75
2.89
5.62
139.91
^
0.01
0(b)
0.09
0.11
0(b)
0.01
0.19
0(b)
0.42
1l$fe'f'
17.81
1.95
111.92
0.13
2.04
7.34
0.23
6.11
147.53
^4;
NA
NA
NA
0.12
NA
NA
0.21
NA
0.32
;XT%;;:
42.04
4.60
264.21
2.33
4.83
17.32
4.15
14.43
353.91
(a) FRI is analyzed for Case 2. All four cases are analyzed separately below.
(b) These values are rounded to zero due to limitation of significant figures.
(c) Emission factors for total suspended participates (TSP) are given only for diesel-ftieled power sources.
FLORES & RUCKS, D4C ZERO DISCHARGE CONTROLLED AIR EMISSIONS
, ", , - v ^ <• •?• x<- ; f ••••;- 'f c
: ' •?-»' , ,Cases , ; .> „ „% t-
Xv^1-^ =: '•-•.^v-.i
Casel
PW to New Injection Wells
Case 2
PW to Waterflood Wells
PW to New Injection Wells
Case 3
Coastal Portion (New Injection)
Offshore Portion (IGF)
Case 4
Coastal Portion (Waterflooding)
Offshore Portion (IGF)
;- PSwejf-For-Gas"'
: ;"' iiotatioif , '
-.'^brl^'
-
2,901,290
2,901,090
-.- Natural (JsaJPowei-c
*':;:^&^-':
50,432,457
40,648,415
10,089,397
~
-5*.*-: -.
:-.M?>:'.
61.10
49.24
12.22
3.51
3.51
* ': ? < *
:\,.$&;:
127.75
102.96
25.56
7.35
7.35
* *,,?' * ' * •*
: Emissions (i
,:-;s^ ,
0.11
0.09
0.02
0.01
0.01
» '( , ;, <, •.
nns/yf) ;
*;WR:»;
138.86
111.92
27.78
7.99
7.99
"" '"" * ' ^ ^ •"-.
- sT^P t ,
NA
NA
NA
NA
NA
^ •"'-.•• frf ^
i *•' * t %;•-',
>;T«t?»^
327.81
264.21
65.58
18.86
18.86
-------
The subject of landfill capacity was discussed in detail in the 1993 Offshore Guidelines
Development Document.24 EPA determined that existing landfills in the areas accessible to the Gulf of
Mexico offshore and coastal oil and gas subcategories have 5.5 million barrels annual capacity available
for oil and gas wastes. Therefore, EPA believes that the incremental quantity of solid waste (121,200 bbls)
generated by drilling injection wells for compliance with the zero discharge produced water option makes
no significant impact on the available landfill capacity. Similarly, the air emissions associated with hauling
the wastes generated by drilling injection wells will likewise be a small fraction (approximately 4.6 percent
based on the waste volume ratio) of the annual total emissions generated by coastal drilling activities. The
emissions from drilling injection wells would be a one-time occurrence as compared with the annual
emissions from production well drilling activities.
3.2 COOK INLET
For the eight facilities currently discharging produced water in Cook Inlet, energy requirements
and air emissions were estimated for equipment that would be added to existing equipment to meet the
limitations of the regulatory options considered for control of produced water. The three options, as they
apply to Cook Inlet operations, are as follows:
Options 1 and 2: Cook Inlet facilities must meet a monthly average oil and grease content.
of 29 mg/1 and a daily maximum of 42 mg/1.
Option 3: Zero discharge.
The technology bases for these options are improved gas flotation for Options 1 and 2, and subsurface
injection for Option 3. Detailed discussions of the additional equipment required to comply with these
control options are included in Chapter XI. The following sections present the methodology used to
calculate energy requirements and air emissions associated with the produced water control options for
Cook Inlet.
3.2.1 Energy Requirements
The horsepower requirements and fuel consumption for the equipment needed to comply with the
produced water control options are presented in Table Xffl-19. The totals in Table Xin-19 are the sum
of the energy and fuel requirements calculated for the eight discharging facilities in Cook Inlet.
Appendices Xffl-3 and XQI-4 present spreadsheets that detail these calculations for both unproved gas
xm-32
-------
TABLE Xffl-19
COOK INLET POWER AND FUEL REQUIREMENTS
FOR PRODUCED WATER CONTROL OPTIONS
-' !>,' "C, ',""
Eguijpment
Total hp-brs
Natural Gas Consumption
s^ CWscf/yr}
',•••••>-,•<•••, Optiofts land 2: Improved Gas Flotation - ",.. ,
Improved Gas Flotation Unit
TOTAL FUEL ;
831,062
—
7,895
7,895
TOTAL FUEL (BOE/yr") = 1,405
„ Optioii 3: Subsurface Injection -
Improved Gas Flotation Unit
Granular Filtration Unit '
Filter Backwash Centrifuge
Injection Pumps :
Booster and Shipping Pumps
TOTAL FUEL
831,062
262,800
2,958
1,611,840
54,312,000
57,020,660
7,895
2,497
28
15,312
515,964
541,696
TOTAL FUEL (BOE/yr) = 96,422
a BOE (barrels of oil equivalent) is the total diesel volume required converted to equivalent oil
volume (by the factor 1 BOE = 42 gal diesel) and the volume of natural gas required
converted to equivalent oil volume (by the factor 1,000 scf = 0.178 BOE).1
flotation (Options 1 and 2), and subsurface injection (Option 3), respectively. Following is a list of energy-
specific assumptions used in all analyses according to the specified equipment:
Improved Gas Flotation Systems: The horsepower requirements for improved gas flotation systems that
were added to two facilities and four platforms that do not currently have one are based on those presented
in the Offshore Development Document.24 In the Cook Inlet produced water compliance cost and pollutant
removal analyses, systems with capacities of 1,000, 5,000, and 10,000 bpd were added for both the
improved gas flotation analysis (Options 1 and 2) and the zero discharge analysis (Option 3) (see
Chapter XI). The corresponding horsepower demands are 12.25, 15.53, and 20.5 hp. The horsepower
demands of the 1,000 and 5,000 bpd systems were calculated via linear interpolation. See Appendix Xffl-3
for details.
Granular Filtration Systems: One'facility and one platform required additional filtration equipment in
the cost and removals analyses for Option 3. The horsepower demands for the 1,000 bpd and 5,000 bpd
xm-33
-------
systems are 10 and 20 hp, respectively. These horsepower requirements are presented in the Offshore
Development Document.24
Filtration Backwash Centrifuge: Centrifuges were added to reduce the volume of filtration backwash
requiring disposal in Option 3 (see Chapter XI). The horsepower demand for filtration backwash
centrifuges was calculated using a method developed for the Offshore rulemaking effort.24 The required
horsepower was calculated as being proportional to the 26-horsepower demand of a 2,000 bpd centrifuge
quoted by a vendor. Thus, using the produced water discharge flow rate and the assumption that 0.5
percent of the produced water flow becomes filtration backwash,24 the horsepower demand was calculated
as in this example for Anna platform:
Centrifuge hp = (919 bbl PW/day x 0.005) / 2,000 bbl centrifuge input per day = 0.0023.
Injection Pumps: Injection pumps of 1,000 and 3,000 bpd capacities were added as needed in Option 3
(see Chapter XI). Their respective horsepower demands of 42 and 100 hp were calculated via linear
interpolation from data presented in Chapter 18 of the 1993 Offshore Development Document.24
Booster and Shipping Pumps: In the Option 3 cost and removals analyses, booster and shipping pumps
were added to two facilities for sending produced water back to specific platforms for injection (see
Chapter XI). Trading Bay Production Facility required four shipping pumps, one for each of three
pipelines plus a spare. East Foreland required only one shipping pump. One booster pump was added for
each pipeline. The horsepower requirements, obtained from information submitted by Cook Inlet
operators, are 1,000 hp for shipping pumps and 300 hp for booster pumps.5
Fuel Consumption: Based on information from Cook Inlet operators, fuel consumption was calculated
based on all equipment being powered by electric motors and electricity being supplied by natural gas-
driven generators.5 Fuel requirements were calculated for natural gas turbines assuming a heating value
of 1,050 Btu/scf of natural gas and an average fuel consumption of 10,000 Btu/hp-hr, or 9.5
(10,000/1,050) scf/hp-hr.12 The usage rate for these systems is 365 days per year or 8,760 hours per year.
These values are used in all three control options. The following is an example fuel consumption
calculation for Anna platform under Options 1 and 2:
Natural gas consumed = 15.53 hp x 8,760 hrs/yr x 9.5 scf/hp-hr = 1,292,407 scf/yr
3.2.2 Air Emissions
Air emissions for the produced water control options were calculated using the uncontrolled air
emission factors for natural gas-fired turbines listed in Table X1H-4. Table XIII-20 lists the air emissions
for all three options, and Appendix XHI-4 presents detailed calculations of these emissions.
3.2.3 Landfill Capacity of Drilling Waste for Injection Wells
EPA projects that to comply with a zero discharge requirement for produced water in Cook Inlet,
operators would need to drill two new produced water injection wells and recomplete two idle production
xm-34
-------
TABLE XHI-20
AIR EMISSIONS ASSOCIATED WITH CONTROL OPTIONS FOR
EXISTING SOURCES OF PRODUCED WATER IN COOK INLET
(tons/year)
Option
1 & 2: Improved Gas Flotation ,
3: Subsurface Injection
M>x !
1.919
81.64
THC
0.165
11.30
- $02 '
0.000
0.125
CO-/'
•0.758
52.12
Total
2.114
145.19
wells for use as disposal wells (see Chapter XI). The volume of drilling waste (drilling fluid and cuttings)
estimated for the new wells is 10,550 barrels, and the recompletions are estimated to generate 4,344
barrels,for a total of 14,894 barrels. The drilling waste volumes are based on the data presented in
Worksheets 1 and 2 in Appendix X-l.
In addition, EPA projected an estimated 33,712 barrels of dewatered sludge would be generated
annually from the centrifuging of produced water filtration backwash as part of the zero discharge by
subsurface injection option. This volume was calculated as 0.06 percent of the volume of fluid to be
filtered, based on the waterflood demand and produced water volumes reported for Cook Inlet production
operations (see Chapter XI).
Assuming a remaining life span of 15 years for the existing Cook Inlet production operations, the
above solid waste volumes represent 0.1 percent of the available capacity at the Kustatan landfill and the
commercial disposal site in Oregon (see Section 2.3). The incremental quantity of drilling waste generated
by drilling injection wells for compliance with the zero discharge produced water option makes no
significant impact on the available landfill capacity. As discussed in Chapter XIV, however, zero discharge
of produced water in Cook Inlet was not found to be economically achievable.
3.3 GULF OF MEXICO ALTERNATIVE BASELINE
In addition to the major pass dischargers (current requirements baseline) non-water quality
environmental impacts, the alternative baseline NWQI analysis assessed the incremental impacts for Texas
dischargers seeking individual permits (TDSIPs) and Louisiana open bay dischargers (LOBDs), who are
already subject to zero discharge (see Chapter IV). NWQIs for the current requirements baseline were
summed with the NWQIs for the TDSIPs and LOBDs to obtain the total NWQI for the alternative
xra-35
-------
requirements baseline. Table XDtt-21 presents the NWQIs calculated for the current requirements baseline
analysis as well as the alternative baseline analysis. The following sections describe the methodologies
used to determine the energy requirements and air emissions for the total alternative baseline.
3.3.1 Energy Requirements
The methodologies used to calculate energy requirements are based on the produced water volume
generated and the location of each facility. As part of the alternative baseline compliance cost analysis
presented in Chapter XI, the volumes of produced water were used to categorize faculties as either medium
to large (herein called "medium/large") or small. The volume that defines the cut-off between
medium/large and small volumes was determined from the intersection of the annualized capital plus O&M
cost curves calculated from design flow equations developed for medium/large volume facilities and for
small volume facilities. Facility locations were defined as being either water-access or land-access sites.
Information used by EPA in developing the proposed and final rules shows that it is reasonable to model
all Louisiana facilities as water-access sites and all Texas facilities as land-access sites (see Chapters IV and
XI).
The information below was used in estimating the energy requirements associated with the final
rule for the alternative baseline:
• Small-volume land-access facilities transport their produced water by truck to a commercial
disposal facility for subsurface injection. Small-volume water-access facilities transport their
produced water by barge to a commercial disposal facility.
• The produced water flow above which it is more economical to treat on site for the treatment
option based on improved gas flotation (Option 1) is 76.5 bpd for land-access and 70.5 bpd for
water-access facilities.
• Medium/Large-volume facilities treat and/or dispose of their produced water on site.treatment
option based on improved gas flotation (Option 1) is 76.5 bpd for land-access and 70.5 bpd for
water-access facilities.
• The produced water flow above which it is more economical to treat and inject produced water
for the zero discharge options (Options 2 and 3) is 70.5 bpd for land-access and 108.4 bpd for
water-access facilities.
The above flow rates define the "cut-off between medium/large facilities and small facilities, and thus
define the method of disposal used. Because there are different cut-off flow rates for Option 1 (improved
gas flotation) versus Options 2 and 3 (zero discharge), Table Xffl-21 shows a greater number of small
Xffl-36
-------
TABLE Xm-21
SUMMARY POWER REQUIREMENTS AND AIR EMISSIONS FOR
PRODUCED WATER CONTROL OPTIONS FOR GULF OF MEXICO FACILITIES
- ->- ' *— '~~>s
Facility Tfcpe, ,, , ,
"" •> s S.-.V.-. "•
Current Requirements Baseline
Major Pass Dischargers'1
Cook Inlet
LA Open Bay Dischargers
Medium/Large Facilities
Small Facilities0
TX Individual Permit Dischargers
Medium/Large Facilities
Small Facilities
Total Alternative Baseline "
.- , •••• ^ -• * •• ^ v f--
Current Requirements Baseline
Major Pass Dischargers'1
Cook Inlet
LA Open Bay Dischargers
Medium/Large Facilities
Small Facilities0
TX Individual Permit Dischargers
Medium/Large Facilities
Small Facilities
Total Alternative Baseline6
Current Requirements Baseline
Major Pass Dischargers'1
Cook Inlet
LA Open Bay Dischargers
Medium/Large Facilities
Small Facilities
TX Individual Permit Dischargers
Medium/Large Facilities
Small Facilities
Total Alternative Baselined
- JS0. Of
Facilities
«v. :•! '•
6
'- 8
; so
7
48
29
120
' - •• , v«v
8
i 8
30
7
49
28
1 122
v ,.
8
8
30
7
49
28
122
TW^fow
-------
facilities in Texas under Option 1 than under Options 2 and 3. This is because two of the eight oufalls for
major pass dischargers have existing gas flotation systems and are not included in the Option 1 analysis.
In addition, Texas permit number 582, currently discharging 75 bpd, is below the Option 1 cut-off and
above the Options 2 and 3 cut-off.
In addition to the above, the approach used to mathematically model the relationship of produced
water flow versus horsepower demands for the major pass dischargers in the current requirements baseline
analysis (see Section 3.1.1) was also used to model the flow versus horsepower demands for the Texas and
Louisiana medium/large facilities for the alternative baseline analysis. This is true for both the improved
gas flotation option (Option 1) and the zero discharge options (Options 2 and 3). The resulting energy
requirements for medium/large volume facilities under each option are presented in Appendices XIII-5
andXm-6.
For medium/large volume facilities, the technology basis for the zero discharge options (Options
2 and 3) differs slightly between land- and water-access sites. While both facility locations dispose of
produced water via subsurface injection, only water-access sites include cartridge filtration prior to
injection. This is because information in the record shows that for land-access facilities, cartridge filtration
is less necessary and well workover costs are cheaper.7 Thus, horsepower demands for filtration feed
pumps are included for water-access sites but not for land-access sites.
For small-volume facilities, the technology basis for all control options is zero discharge via
transporting the produced water to a commercial disposal facility for subsurface injection. NWQIs for
water-access sites are based on weekly barge trips provided by a commercial service company. The bases
and methodology for determining the frequency and duration of the barge trips are presented in
Appendix Xm-7, along with the resulting energy requirements. Small-volume land-access sites use
vacuum trucks to transport produced water off-site. Appendix Xffl-8 presents the energy requirements
calculated for small-volume land-access sites.
3.3.2 Air Emissions
Air emissions for all options were calculated by multiplying the estimated fuel use by the emission
factor for the specific type of equipment. As in the current requirements baseline NWQI analysis,
uncontrolled as well as controlled air emissions were calculated for Gulf of Mexico medium/large facilities
for the gas flotation and subsurface injection options (see Section 3.1.2). The emission factors used for
xm-38
-------
small Louisiana and Texas facilities were for barging and trucking activities, respectively, as presented in
Table XIII-4. Controlled air emissions were not calculated for small facilities because installation of
controlled emissions technology onto trucks or service vessels is the decision of the commercial disposal
company, not that of the small produced water volume generating facility. The resulting air emissions for
all alternative baseline facilities are summarized in Table Xni-21 and are presented in detail in Appendices
Xffl-5 and XHI-6.
3.4 OTHER FACTORS
3.4.1 Impact of Marine Traffic on Coastal Waterways
In evaluating the impact of the final rule on the potential for increased service vessel traffic,
dredging, and the widening of navigation channels, EPA reviewed MMS data and EPA estimates regarding
transport boat usage. The service vessel usage at coastal facilities may be as high as two supply boats per
day and two crew boats per day during the exploration and development operations. In general, service
vessels make three trips per week to exploration and development operations and one trip per week to
production facilities. A boat may visit only one site or, if it is only going to production facilities, it may
visit as many as five facilities in a single trip.6
The oil and gas industry in the Gulf of Mexico uses the extensive waterway system located within
the Gulf Coastal States to provide access between onshore support operations and coastal production
facilities and drilling rigs. Oil industry support vessels moving along coastal navigation channels include
crew boats, supply boats, barge system, derrick vessels, geophysical-survey boats, and floating production
platforms. Navigation channels serve as routes for service vessels traveling back and forth from service
and supply bases.24 Generally, oil and gas industry use accounts for approximately 12 percent of all
commercial usage of the Gulf Coastal navigation channels according to MMS data.32
In terms of the Gulf of Mexico current requirements baseline, service vessels will only be
necessary to support produced water injection well drilling. The volume of waste generated from drilling
injection wells is only 1.7 percent of the annual offshore drilling waste volume (see Section 3.1.3).33 The
number of service vessels servicing drilling waste disposal from injection wells for the current requirements
baseline is only 1.7 percent of the total offshore vessel traffic or 0.2 percent of all commercial traffic. It
is important to note that the injection well drilling waste volume will occur only once and the vessel traffic
will be effected temporarily.
Xin-39
-------
MMS data show that for offshore operations alone, an average of 30,000 service vessel trips per
year support oil and gas related activities in Federal waters of the Gulf of Mexico.34 These data do not
include vessel traffic destined for coastal or offshore activities in the State territorial seas and therefore
wider-count actual boat traffic. In estimating the vessel traffic resulting from this rule, EPA projected that
transporting produced water from wells subject to zero discharge would require a total of 60 barge trips
per year (see Section 3.3, alternative baseline). In comparison to the offshore MMS data alone, it is
apparent that the differential increase in boat traffic due to this rule would be less than 0.2 percent of all
service vessel traffic.34
Since service vessels must have unimpeded access to supply bases to continue servicing coastal
activities, maintenance dredging of navigation channels would be required regardless of whether this rule
was promulgated. Recalling that oil and gas related traffic accounts for approximately 12 percent of all
commercial use of the navigation channels and that oil/gas related vessel traffic resulting from this rule will
increase less than 0.2 percent, any increase in vessel traffic due to this rule is expected to be minimal. No
significant increase in dredging activities is anticipated as a result of this rule.
3.5 UNDERGROUND INJECTION OF PRODUCED WATER
Produced water is required to be disposed of in Class II injection wells. The authority of the
Underground Injection Control (UIC) program extends to all offshore injection wells located in state
territorial waters, but does not apply to injection wells located in federal waters (40 CFR Parts 144, 145
and 146). EPA does not believe that zero discharge in properly constructed Class II injection wells will
endanger underground sources of drinking water.
In the 1987 Report to Congress (EPA/530-SW-88-003), EPA analyzed.the impact of the disposal
of produced water in injection wells.35 The study found that injection wells used for the disposal of
produced water have the potential to degrade fresh groundwater in the vicinity if they are inadequately
designed, constructed, or operated. Highly mobile chloride ions can migrate into freshwater aquifers
through corrosion holes in injection tubing, casing and cement. To prevent groundwater contamination,
the UIC program (administered by EPA and states pursuant to the Safe Drinking Water Act, sections 1421-
1425) requires mechanical integrity testing of all Class n injection wells every 5 years. All states with
permitted Class II injection wells meet this requirement, although some states have requirements for more
frequent testing.
xm-40
-------
4.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
Treatment, workover, and completion (TWC) fluids are commingled with produced water for
treatment in Cook Inlet, thus non-water quality enviromental impacts (NWQI) for TWC fluids in Cook Inlet
are included in the NWQI analysis for produced water. Coastal facilities in Alaska's North Slope,
Alabama, Mississippi, Florida, and California are already achieving zero discharge of TWC fluids. The
population of facilities included inlthe NWQI analysis for TWC fluid discharges in Texas and Louisiana
is the same as for the TWC compliance cost and pollutant removals analysis. As described in detail in
Chapter Xn, the total TWC population was subdivided into the following distinct facility types:
Medium/Large Facilities: Those facilities generating large enough amounts of produced
water to make it cost effective to develop and operate onsite treatment technology.
Medium/Large facilities are subject to two different produced water discharge limitations:
a) General Permit Facilities: Those Medium/Large facilities required to meet zero
discharge limitations under the 1995 Region 6 General Permits.
b) Major Pass Dischargers: Those Medium/Large Facilities not covered by the zero
discharge requirements of the 1995 Region 6 General Permits because they discharge off-
shore or stripper subcategory produced waters into major passes of the Mississippi River
or to the Atchafalaya River below Morgan City including Wax Lake Outlet.
Small Facilities: Those facilities which, due to their lower produced water flow rates, use
commercial treatment/disposal facilities for pollution control. All of these facilities were
covered by the 1995 Region 6 General Permits.
Since TWC fluids are, or can be, commingled with produced water for treatment and discharge
or injection, the regulatory options for the TWC NWQI analysis are the same as those developed for
produced water. Table XIII-22 presents the summary energy requirements and air emissions calculated
for TWC fluids according to the regulatory options. Note that, as in the produced water NWQI analysis,
Option 1 allows discharge (from major pass dischargers only) of TWC fluids meeting compliance with
limitations based on improved performance of gas flotation (IGF), and Options 2 and 3 are both zero
discharge for all facilities in the Gulf of Mexico based on onsite injection or commercial transport to offsite
injection.
Although Option 1 is based on IGF, only those operators currently discharging produced water
(i.e., major pass dischargers) are expected to utilize gas flotation to meet the Option 1 limitations, whereas
those operators currently required to meet zero discharge of produced water (i.e., general permit facilities)
xra-4i
-------
TABLE Xm-22
UNCONTROLLED AIR EMISSIONS AND ENERGY REQUIREMENTS
FOR GULF OF MEXICO TWC FLUIDS BAT AND NSPS OPTIONS
Option
Option l:b
Zero discharge except: major pass
river dischargers at 29/42 mg/1 oil
and grease limitations.'
Options 2 & 3:b
Zero discharge for all Gulf of
Mexico facilities.11
i Facility Type'
M * < > - * „
• Medium/Large Facilities:
- Major Pass Dischargers
- General Permit Facilities
• Small Facilities:
- Water-access
- Land-access
Total
• Medium/Large Facilities
• Small Facilities:
- Water-access
- Land-access
Total
Fuel Requirements
(BOE/year)*
BAT
3.62
216.85
1,006.21
131.26
1,359.94
276.10
1,006.21
131.26
1,413.57
BfSPS
0.89
30.04
136.76
14.33
182.02
36.25
136.76
14.33
187.34
Air Emissions
(tons/year) '
BAT
0.05
2.62
11.65
0.54
14.86
3.33
11.65
0.54
15.52
US'*
0.01
0.36
1.58
0.06
2.01
0.44
1.58
0.06
2.08
" BOE (barrels of oil equivalent) is the sum of the total diesel volume required and total natural gas volume converted to
equivalent oil volume by the factors: 1 BOE = 42 gal diesel, and 1,000 scf = 0.178 BOE.1
b Cook Inlet produced water NWQIs are presented in a separate document.
c FRI is already at IGF and North Central outfall #003-1, permit #2184 is at gas flotation; therefore there are no incremental
emissions for these two outfalls.
d FRIatCase2.
are expected to utilize subsurface injection to meet the Option 1 limitations. Therefore, the NWQIs
calculated for TWC fluids generated by major pass dischargers under Option 1 are based on the NWQIs
calculated for produced water treated by improved gas flotation systems as presented in Section 3.1.1.1.
The NWQIs for TWC fluids generated by general permit facilities under Option 1 are based on the NWQIs
calculated for produced water disposed by injection as presented in Section 3.1.1.2. For TWC fluids
generated by all medium/large facilities, including both major pass and general permit facilities, the
NWQIs calculated under Options 2 and 3 are based on the NWQIs calculated for produced water disposed
by injection as shown hi Section 3.1.1.2.
Based on the practice of commingling, the quantity of NWQIs generated by treating or disposing
of one barrel of TWC fluid is equal to the NWQIs generated by treating or disposing of one barrel of
produced water. Hence, EPA estimated the total NWQIs for TWC fluids as being proportional to the total
NWQIs calculated for produced water. To calculate TWC fluid NWQIs proportional to produced water
XIH-42
-------
NWQIs, the total annual volume of combined TWC fluids generated per job per facility type was divided
by the annual produced water volume generated by the major pass dischargers (see Section 3.1.1,
Table XHHO). The ratio was then multiplied by the total fuel consumption and power requirements that
were originally calculated for the facilities in the produced water NWQI analysis presented in Section 3.0
of this document. A detailed description of these calculations is provided in the following sections.
EPA determined that incremental energy requirements and air emissions would occur from
medium/large facilities and from small facilities. The following sections present the methodology used to
estimate energy requirements and air emissions from onsite gas flotation, onsite injection, and
transportation and handling activities associated with commercial disposal of TWC fluids.
4.1 ENERGY REQUIREMENTS
4.1.1 Medium/Large Facilities
The energy requirement calculations for medium/large facilities (comprised of major pass
dischargers and general permit facilities) took into account the total number of treatment/workover jobs
and completion jobs per year and the corresponding volumes of TWC fluids to be disposed of or
discharged. The TWC fluid volumes and jobs per year are based on information presented hi Chapter XH.
Appendix Xffl-9 presents two tables (for existing and new sources, respectively) that list the following data
for each facility type (i.e., major pass dischargers and general permit facilities) and regulatory option:
Number of workover/treatment jobs per year
Workover/treatment fluid volume per job (in bbl per year)
Total workover/treatment fluid volume per year (hi bbl per year)
Number of completion jobs per year
Completion fluid volume per job (hi bbl per year)
Total completion fluid volume per year (hi bbl per year)
Total TWC fluid volume per year (hi bbl per year).
After multiplying the number of jobs per year by the corresponding volume of fluid generated per
job, the total volumes from the two types of jobs were summed, resulting hi a weighted average volume
of TWC fluids. To illustrate the derivation of the data presented hi Appendix Xni-9, the following is an
example using the data hi the first row of Table A, namely, the calculation of the total TWC fluid volume
generated per year by major pass dischargers under Option 1 (discharge based on IGF):
(25 W/T jobs/yr x 587 W/T bbl/job);+ (23 Compl. jobs/yr x 209 Compl. bbl/job) = 19,482 bbl TWC fluids/yr
Xffl-43
-------
As discussed in the preceding section, EPA estimated the total NWQIs for TWC fluids as being
proportional to the total NWQIs calculated for produced water. The proportional relationship was
calculated as the ratio of the total annual volume of combined TWC fluids generated per job per facility
type (as listed in Appendix Xffl-9) relative to the annual produced water volume generated by the major
pass dischargers (as listed in Table Xffl-10). Three such ratios were calculated: one for major pass
dischargers under Option 1, one for general permit facilities under Option 1, and one for all medium/large
facilities under Options 2 and 3. Below are the three equations used to calculate these ratios:
Option 1 Equations:3'11
TWC Volume from Major Pass Dischargers (App. XIII-9)
PW Volume from Major Pass Dischargers Not Using Gas Flotation (Table XIII-10)
19'482 bbl'yr = 0.00179
(29,791 bpd x 365 dayslyr) Eqn. 1
TWC Volume from General Permit Facilities (App. XIII-9)
PW Volume from All Major Pass Dischargers (Table XIII-10)
166.662 bbllyr =
(191,292 bpd x 365 dayslyr) Eqn. 2
Option 2 Equation:
TWC Volume from All Medium/Large Facilities (App. XIII-9)
PW Volume from All Major Pass Dischargers (Table XIII-10)
212.203 bbllyr = n „„
(191,292 bpd x 365 dayslyr) Eqn. 3
Note that the volume of produced water in the denominator of Equation 1 is less than the volume
in the denominator of Equation 2. Although both volumes are derived from Table XIII-10 and both apply
Those major pass facilities already employing gas flotation to treat produced water (and commingled TWC fluids) incur
no NWQIs under Option 1.
Equation 1 uses the ratio of TWC fluids that would undergo gas flotation to the volume of produced water used in Section
2 to calculate NWQIs associated with gas flotation. Thus, the NWQIs resulting from gas flotation treatment of one barrel
of TWC fluids is equal to the NWQIs resulting from gas flotation treatment of one barrel of produced water. The
resulting value for Equation 1 is 0.00179, or 0.179%. Thus, IGF treatment of TWC fluids under Option 1 will require
0.179% of the total fuel consumption calculated for IGF treatment of produced water under Option 1. The same
percentage holds true for air emissions estimates. Equations 2 and 3 perform similar calculations to estimate NWQIs for
those TWC fluids that would be injected.
xm-44
-------
to Option 1, the volume in Equation 1 excludes those major pass dischargers that currently use gas
flotation, and the volume in Equation 2 includes all major pass dischargers. As noted in the preceding
section, only major pass dischargers are expected to utilize gas flotation to comply with Option 1
limitations, while general permit facilities are expected to utilize injection to meet the same limitations.
Therefore, the proportion of NWQIs associated with TWC fluids treatment at major pass dischargers under
Option 1 is relative only to the NWQIs resulting from adding IGF treatment for the incremental volume
of produced water at those facilities. The proportion of NWQIs due to TWC fluids injection by general
permit facilities under Option 1 is relative to the NWQIs resulting from injection of the total produced
water volume by major pass facilities. For Option 2 in which all medium/large facilities utilize injection,
the denominator is the total produced water volume for major pass facilities.
To determine TWC energy requirements, the TWC/PW volume ratios were then mulitplied by the
corresponding produced water power requirements and fuel usage derived in Section 3.1.1. For example,
the incremental amounts of diesel and natural gas fuels used to treat TWC fluids onsite via improved gas
flotation for the major pass dischargers under Option 1 was calculated as foEows:
From PW Analysis TWC/PW Proportion For TWC Analysis
32,107 gal/yr diesel :x 0.00179 = 57.53 gal/yr diesel
7.07 MMscf/yr natural gas :x 0.00179 = 0.0127 MMscf/yr natural gas
The produced water data and resulting TWC fuel use and power requirements for all options of the major
pass discharge and general permit facilities are presented in Table Xffl-23.
4.1.2 Small Facilities
The NWQI analysis for TWC fluids generated by small faculties was based on the assumption that
all small facilities use commercial disposal services to transport and dispose via injection TWC fluids.36
Water-accessed small facilities transport their waste by barge for commercial disposal. Land-accessed
small facilities transport their waste by track for commercial disposal.
The fuel usage due to the operation of barges and trucks to transport TWC fluids from either water-
or land-accessed facilities to commercial facilities for disposal was calculated by estimating the fuel
consumption required by trucks and barge tugs, the distance barges and tracks have to travel, fuel eon-
XIII-45
-------
TABLE Xffl-23
TWC FLUID ENERGY REQUIREMENTS FOR MAJOR PASS DISCHARGERS AND
GENERAL PERMIT FACILITIES (EXISTING SOURCES)
, , , jicUKyTft»-,a*
''' , * ,~ ^ *' A;^
Option 1:
» Major Pa«s Dischargers
* General Permit Facilities
Option!:
« AH Medium/Large
Facilities
S tedJljpe
' " V< A & ^
$v t '
5 ^(feB/SsW""*'""
486,471
744,267
292,850
53,451,602
292,850
53,451,602
TWCTO
" Vdludtt, Ratio >
*v* E
0.00179
0.00179
0.002387
0.002387
0.003039
0.003039
TWCBielTJje"
«"*f V ,?™-" <
•- * ^ *- ? * ; -s
57.53 gal/yr
0.0127 MMscf/yr
46.14 gal/yr
1.21 MMscf/yr
58.74 gal/yr
1.54 MMscf/yr
TWCPoyw
-^alremejts ;
„ fltoHte/y) „ »
871.59
1,333.47
689,02
127,587.36
890.03
162,451.07
* Values for Major Pass Dischargers under Option 1 are from Table XDJ-10. Values for General Permit facilities under Option 1 and all Medium/Large Facilities
under Option 2 are from Table Xffl-13.
-------
sumption by auxiliary generators when the barges are loaded and tugs are idling, and by vacuum pumps
and compressors to unload the barges (see Appendix XIH-10). To simplify calculations, the treatment/
workover and completion fluid volumes were combined. Table A in Appendix XEI-9 shows how these
volumes were calculated. The total TWC volumes were used to determine NWQIs of either trucking or
barging.
Table Xm-24 presents the fuel required to transport TWC fluids from existing small water- or land-
accessed facih'ties to commercial facilities for disposal. Fuel requirement calculations for small facilities
are presented in Appendix XIII-10.
TABLE XHI-24
EXISTING FACILITY TWC FLUIDS NON-WATER
QUALITY IMPACTS FOR ALL REGULATORY OPTIONS
' ,, Fad&%'~ "
1 Tm ;.
Water-Access
Land-Access
' s% !/
I $W€: \,
Volume ..
;^
41,183
21,870
,- , -Fuel Requirements (gal/yr) ? ,
% ^"F 1
41,200
0
_ Track •
0
5,513
Auxiliary
Equipment
1,061
0
'Total
42,261
5,513
4.1.3 New Sources
The basis for the number of new sources generating TWC fluids is described in detail in
Chapter XII. Table B in Appendix XD1-9 lists the number of jobs and TWC volumes corresponding to each
of the options. As hi the existing source NWQI analysis, energy requirements for new source medium/
large facilities were based on the ratio of TWC-to-major pass discharger produced water volumes. The
TWC/PW volume ratios for each option and facility type are presented in the following equations:
Option 1 Equations:
TWC Volume from "New" Major Pass Sources (App. XIII-9)
PW Volume from Major Pass Dischargers Not Using Gas Flotation (Table XIII-10)
4,776 bbllyr
(29,791 bpd * 365 dayslyr)
= 0.00044
Eqn. 4
xm-47
-------
TWC Volume from "New" General Permit Sources (App. XHI-9)
PW Volume from All Major Pass Dischargers (Table XIII-IQ)
23'084 _ = 0.00033
(191,292 bpd * 365 dayslyr) Eqn. 5
Option 2 Equation:
TWC Volume from. All "New" Medium/Large Sources (App. XIII-9)
PW Volume from All Major Pass Dischargers (Table -X7//-10)
27'860 _ = 0.00040
.
(191,292 bpd * 365 dayslyr) Eqn. 6
Table Xffi-25 presents the data and the TWC fuel usage and power requirements for medium/large
facilities for all options.
For the NWQI analysis of new sources of TWC fluids generated at small facilities, the number of
TWC jobs per year and volumes are me same as in Chapter XII and are presented in Table B in Appendix
Xm-9. The methodology and estimates used for existing small facilities were also used to calculate the
energy requirements for new source small facilities as presented in Table xni-26.
4.2 AIR EMISSIONS
The air pollutants evaluated for the TWC fluids options are the same as those identified for the
produced water treatment options: nitrogen oxides (NO,,), total hydrocarbons (THC), sulfur dioxide (SO2),
carbon monoxide (CO), and total suspended particulates (TSP). Air emissions were calculated for each
facility type by multiplying the product of specific emission factors by the power requirements in hp-hr per
year. The annual power requirements for each fuel type were calculated for all medium/large facilities
generating TWC fluids by multiplying the TWC/PW volume ratios derived for each facility type and option
(see Equations 1 through 6) by the corresponding produced water power requirements. Table XIQ-14
presents the emission factors for diesel- and natural gas-powered reciprocating engines used in calculating
the air emissions for medium/large facilities. Tables Xin-27 and Xffl-28 present the summary air
emissions for existing and new sources, respectively, for all facility types and regulatory options.
Table Xm-4 presents the emission factors for barges, trucks and auxiliary equipment used in
calculating air emissions for TWC fluid disposal from small facilities. Tables XIII-27 and XIII-28
xm-48
-------
TABLE XIII-25
TWC FLUID ENERGY REQUIREMENTS FOR MAJOR PASS DISCHARGERS AND
GENERAL PERMIT FACILITIES (NEW SOURCES)
gUll!
Option 1:
• Major Pass Dischargers
• General Permit
Facilities
Option 2:
• All Medium/Large
Facilities
S8
Diesel
Natural Gas
Diesel
Natural Gas
Diesel
Natural Gas
t,A» "•'-, ^ i , •"',>- -A
32, 107 gal/yr
7.07 MMscf/yr
19,328 gal/yr
507.79 MMscf/yr
19,328 gal/yr
507.79 MMscf/yr
* Rijtjuireitiehts V
\\ : '(np/hr/yr)' * -'<
486,471
744,267
292,850
53,451,602
292,850
53,451,602
* / ' 1' W//*^ rtrtX/ ? ~~ ^f
-.•.JL >fjt \AtJQJii' w ff -.
0.000439
0.000439
0.000331
0.000331
0.000399
0.000399
iiiW
14. 10 gal/yr
0.0031 MMscf/yr
6.39 gal/yr
0.168 MMscf/yr
7.71 gal/yr
0.203 MMscf/yr
213.67
326.90
96.82
17,671.85
116.85
21,328.10
(a) Values for Major Pass Dischargers under Option 1 are from Table XIII-10. Values for General Permit Facilities under Option 1 and all Medium/Large
Facilities under Option 2 are from Table XIII-13.
-------
TABLE Xm-26
SMALL FACILITY ENERGY REQUIREMENTS FOR NEW SOURCES OF TWC FLUIDS
Facility Type
Water-Access
Land-Access
TWC, v
VbIumeS-4
CbWyrf *
4,109
2,348
Barge ; ,
5,600
0
^FtielSe^uirc
* '/ ' *,*/ « ^
0
602
melts feai/yr)
'4w
144
0
> s "• ' s \
,- Total J
5,744
602
summarize the air emissions resulting from the transportation of TWC fluids to commercial facilities for
disposal for existing and new small sources, respectively.
xm-5o
-------
TABLE XIII-27
FUEL CONSUMPTION AND UNCONTROLLED AIR EMISSIONS FOR
EXISTING SOURCES
' ,, ~:.r~"'*\^*"t 'i ' ., '»i><.\
-,-~ [ ^'f? -{"- t.. '•';;•,',* - ,'
^ Jii^d^yiSeJAeift ,';
>"'-5^; "»-;> ^x-'';
0 '?>*.* ,"t ";f-?
Major Pass Dischargers"
General Permit Faciliites
Small Water-Access
Small Land-Access
Total
V '* * '<" "• ^ •>- J*, ^ ' >
Medium/Large Facilities'"
Small Water-Access
Small Land-Access
Total
Tbial Diesel
- 1?ueLilser
:f(gy/y0;::;-
.' "*"• •'* '-"i ;,-
,r (!• "! ,,S ' ' ,
57.53
46.14
42,261
5,513
47,878
V '*;V*'
58.74
42,261
5,513
47,833
'Mat Natural-
^f;iealjfi^,J
f^^);;1
,>,<< W i~, ;^
5. v\> ' '*'K; z.*'*, -•
0.0127
1.2121
0
0
1.2248
"C t-ifl ",. / "^
1.543
0
0
1.543
-KOgT'^i:
^051^)7
« 4 * , ? -. ^
'"* -'rt'if *
0.0031
1.6970
8.3178
0.2728
10.3187
/ Opiwns J
2.1607
8.3178
0.2728
10.7513
-.' ' ""l *
'•^^m-
jvtlttiis/#c) 4
' •••• * -.v ^ *v •• ^
Kif.--4'^'^,"* 4"
W*-'x , 'i. -
0.0083
0.6894
0.3660
0.0605
1.1242
u*r* n.,-
0.8778
0.3660
0.0605
1.3043
"Sd^Qlaf
;;%^#r)M
:,ft f-'«-A<.^
-,:' ''c; , ":' tf J
t ' * ,\ ; ". t ' * *
0.0009
0.0010
0.6032
—
0.6051
'I > 1 4 >'",,'••
0.0013
0.6032
—
0.6045
:fcoiWHi;,
V(ifliy/^);f;
•'"'. .: ' «-
i« OP-;
0.0053
0.2272
1.6671
0.2072
2.1068
i-^r,,*;.
0.2892
1.6671
0.2072
2.1635
••fafowaa,
t (toifs/yt-)-5
-\- ,,,'.» '»
:*.'?;,^* ;
0.0010
0.0008
0.6976
—
0.6994
- 4 '-,'""
0.0010
0.6976
—
0.6986
IMalAlrr
i EmisMols! ,
iJtaatfrl',;
" J '^^ " * ' •-•
;* •- \. Vo / "?"• v *••
0.0466
2.6154
11.6517
0.5405
14.854
, ;,/ ;,- -*
3.330
11.6517
0.5404
15.522
' Due to existing gas flotation systems, FRI and North Central permit no. 2184-003-1 are not included in the Option 1 analysis.
b For Options 2 and 3, all major pass facilities are included in the analyses.
-------
TABLE XHI-28
FUEL CONSUMPTION AND UNCONTROLLED ADR EMISSIONS FOR
NEW SOURCES
Industry Segment ,
-,<• :< " 1
Total Diesel
Fuel Use
> (gal/yr)
Total Natural
„ Gas Use
jMMscf/j •- , '• * /,r i *"•- 1 . % ,v» "*,;A option rsi A*/"- >>>-" ?v- &r ~J &{'•<-£ cL
Major Pass Dischargers
General Permit Facilities
Small Water-Access
Small Land-Access
Total
14.10
6.39
5,744
602
6,367
0.0031
0.1679
0
0
0.171
0.0076
0.2350
1.1305
0.0298
1.4029
0.0020
0.0955
0.0497
0.0066
0.1538
0.0002
0.0001
0.0820
—
0.0823
0.0013
0.0315
0.2266
0.0226
0.282
0.0002
0.0001
0.0948
—
0.0951
0.0113
0.3622
1.5836
0.0590
2.0161
- ' '"' 'I, ; **: .Options 2t& 3V' .'„.', '" .
Medium/Large Facilities
Small Water-Access
Small Land-Access
Total
7.71
5,744
602
6,354
0.2026
0
0
0.2026
0.2837
1.1305
0.0298
1.444
0.1152
0.0497
0.0066
0.1715
0.0002
0.0820
—
0.0822
0.0380
0.2266
0.0226
0.2872
0.0001
0.0948
—
0.0949
0.4372
1.5836
0.0590
2.0798
-------
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\
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xra-53
-------
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Estimates," January 5, 1995.
22. SAIC, "Coastal Oil and Gas Production Sampling Summary Report," April 30, 1993.
23. Dawley, J., SAIC, telecommunication with John Hainsworth, John H. Carter Company, Baton
Rouge, LA, regarding "Horsepower Requirements of Gas Rotation Units," February 25, 1992.
24. 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, EPA 821-R-193-003, January 15, 1993.
25. W-H-B Pumps, Inc., Pump Specifications and Costs, January 10, 1994.
26. Avanti, "Non-Water Quality Environmental Impacts for Gulf of Mexico Produced Water (Current
Requirements Baseline) and Treatment, Workover, and Completion Fluids," September 16, 1996.
27. Sunda, J., SAIC, communication with D. Chisholm, Texaco, regarding NWQI-Type of natural gas
powered engines used at tank batteries compressor stations in coastal Gulf of Mexico areas,
November 3, 1994.
28. U.S. EPA "Final NPDES General Permits for Produced Water and Produced Sand Discharges from
the Oil and Gas Extraction Point Source Category to Coastal Waters in Louisiana and Texas," 60
Fed. Reg. 2387 (January 9, 1995).
29. Jordan, R., EPA, memorandum to the record regarding "Discharges of Offshore Subcategory Water
into Coastal Waters of Texas and Louisiana," February 8, 1996.
30. U.S. EPA, "Compilation of Air Pollutant Emission Factors," AP-42, Volume I, January 1995.
31. SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire (Final)," January 31, 1995.
32. U.S. Department of the Interior, Minerals Management Service, "Outer Continental Shelf Natural
Gas and Oil Resource Management Program: Cumulative Effects 1987-1991," Herndon, VA,
February 1995.
33. U.S. EPA, "Non-Water Quality Environmental Impacts Resulting from the Offshore Disposal of
Drilling Fluids and Drill Cuttings from Offshore Oil and Gas Drilling Activities," January 13, 1993.
(Offshore Rulemakiing Record Volume 156)
xra-54
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34. U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, "Gulf
of Mexico Sales 157 and 161: Central and Western Planning Areas," Final Environmental Impact
Statement, Volume I: Sections I through IV.C, New Orleans, November 1995.
35. U.S. EPA, Report to Congress: Management of Wastes from the Exploration, Development, and
Production of Grade Oil, Natural Gas, and Geothermal Energy, EPA/530-SW-88-003, December
1987. ',
36. U.S. EPA, Development Document for Proposed Effluent Limitations Guidelines and Standards for
the Coastal Subcategory of the Oil and Gas Extraction Point Source Category, EPA 821-R-95-009,
February 1995. ;
xm-ss
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CHAPTER XIV
OPTIONS SELECTION: RATIONALE AND TOTAL COSTS
1.0 INTRODUCTION
This section presents the options EPA selected for control of the coastal oil and gas wastestreams
and a discussion of EPA's rationale for selecting the options which were chosen.
2.0 SUMMARY OF OPTIONS SELECTED AND COSTS
Drilling fluids, drill cuttings, and dewatering effluent are limited under BCT, BAT, NSPS, PSES,
and PSNS. BCT limitations are zero discharge, except for Cook Inlet, Alaska. In Cook Inlet, BCT
limitations prohibit discharge of free oil. For both BAT and NSPS, EPA is establishing zero discharge
limitations for drilling fluids and drill cuttings, except for Cook Inlet. In Cook Inlet, discharge limitations
include no discharge of free oil, no discharge of diesel oil, 1 rag/kg mercury and 3 mg/kg cadmium
limitations on the stock barite, and a toxiciry limitation of 30,000 ppm SPP. For both PSES and PSNS,
EPA is establishing zero discharge limitations nationwide.
Produced water and treatment, workover, and completion fluids are limited under BCT, BAT,
NSPS, PSES, and PSNS. For BCT, EPA is establishing limitations on the concentration of oil and grease
in produced water and treatment, workover, and completion fluids equal to current BPT limits. The daily
maximum limitation for oil and grease is 72 mg/1 and the monthly average limitation is 48 mg/1. For BAT
and NSPS, EPA is establishing zero discharge limitations, except for Cook Inlet, Alaska. In Cook Inlet,
the daily maximum limitation for oil and grease is 42 mg/1 and the monthly average limitation is 29 mg/1.
For both PSES and PSNS, EPA is establishing zero discharge limitations.
For produced sand, EPA is establishing zero discharge limitations under BPT, BCT, BAT, NSPS,
PSNS, and PSES.
Deck drainage is limited under BCT, BAT, NSPS, PSES, and PSNS. For BCT, BAT, and NSPS,
EPA is establishing discharge limitations of no free oil. For PSES and PSNS, EPA is establishing zero
discharge limitations.
XTV-1
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Domestic waste is limited under BCT, BAT, and NSPS, For BCT, EPA is establishing no
discharge of floating solids or garbage as limitations. For BAT, EPA is establishing no discharge of foam
as the limitation. For NSPS, EPA is establishing no discharge of floating solids, foam, or garbage as
limitations. There are no PSES and PSNS for domestic waste under the coastal guidelines.
Sanitary waste is limited under BCT and NSPS. For BCT and NSPS, sanitary waste effluents from
facilities continuously manned by ten or more persons would contain a minimum residual chlorine content
of 1 mg/1, with the chlorine level maintained as close to mis concentration as possible. Facilities
continuously manned by nine or fewer persons or only intermittently manned by any number of persons
must not discharge floating solids. EPA is establishing no BAT, PSES, or PSNS regulations for sanitary
waste under the coastal guidelines.
While coastal areas other than Alaska, California and the Gulf of Mexico are not specifically
addressed throught this chapter or other sections of the Development Document, the zero discharge
requirements of the effluent limitations guidelines and standards in the final rale were found to be
technologically available and economically achievable in all coastal areas of the United States, and would
result in acceptable non-water quality environmental impacts. The limitations for all wastestreams are
presented in Tables XTV-1 through XTV-5.
TABLE XIV-1
BPT EKB'LUENT LIMITATIONS PROMULGATED BY THIS RULE"
Produced Sand
No discharge
* Existing BPT limitations for other wastestreams are not changed by this final rule (see 40 CPR Part 435.42).
XTV-2
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TABLE XIV-2
BAT EFFLUENT LIMITATIONS
: " Wasfestream I
• * f '<•.* ' V«,«, $ t^ffJfff ff M ',,
Drilling fluids, DriU
Cuttings and Dewatering
Effluent
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Produced Water
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Well Treatment, Workover
and Completion Fluids
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Produced Sand
Deck Drainage
Domestic Waste
Pollutant Parameter
s^
Free Oil(1>
Diesel Oil
Mercury
Cadmium
Toxicity
Qil and Grease
Oil and Grease
Free Oil®
' Foam
„,,.,, -cor;,. , ; Limitations ;; "' ;
No discharge
No discharge
No discharge
1 mg/kg dry weight maximum in the stock barite
3 mg/kg dry weight maximum in the stock barite
Minimum 96-hour LC50 of the SPP shall be 3 percent
by volume® (maximum test result of 30,000 ppm)
No discharge
The maximum for any one day shall not exceed 42
mg/1, and the 30-day average shall not exceed 29 mg/1
No discharge
The maximum for any one day shall not exceed 42
mg/1, and the 30-day average shall not exceed 29 mg/1
No discharge
No discharge
No discharge
(1) As determined by the static sheen test (see Appendix 1 to 40 CFR Subpart A).
(2) As determined by the toxicity test (see Appendix 2 of 40 CFR Subpart A).
(3) As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water
(visual sheen).
XIV-3
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TABLE XIV-3
BCT EFFLUENT LIMITATIONS
Wastestream. : \
Drilling Fluids, Drill Cuttings and
Devvatering Effluent
A) All facilities except Cook Inlet
B) Cook Inlet
Produced Water
(all facilities)
Well Treatment, Workover and
Completion Fluids
A) All facilities except fresh water
locations in TX and LA
B) Fresh water locations in TX
and LA
Produced Sand
Deck Drainage
Sanitary Waste
Sanitary M10
Sanitary M9IM
Domestic Waste
Pollutant Parameter
" i, V " "*"-
,. i -f ** ^ "'•"• '•?
Free Oil
Oil and Grease
Free Oil
Free Oil
Residual Chlorine
Floating Solids
Floating Solids and
Garbage
„
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TABLE XTV-4
NSPS EFFLUENT LIMITATIONS
Wasfesir*am
Drilling Fluids, Drill
Cuttings and Dewatering
Effluent
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Produced Water
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Well Treatment, Workover
and Completion Fluids
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Produced Sand
Deck Drainage
Sanitary Waste
Sanitary M10
Sanitary M9IM
Domestic Waste
Pollutant Parameter
'FreeOil(1>
Diesel Oil
Mercury
* Cadmium
: Toxicity
i
Oil and Grease
Oil and Grease
'Free Oil®
Residual Chlorine
Floating Solids
Floating Solids,
Garbage(4> and Foam
NSPS Limitations
No discharge
No discharge
No discharge
1 mg/kg dry weight maximum in the stock barite
3 mg/kg dry weight maximum in the stock barite
Minimum 96-hour LC50 of the SPP shall be 3 percent
by volume® (maximum test result of 30,000 ppm)
No discharge
The maximum for any one day shall not exceed 42
mg/1, and the 30-day average shall not exceed 29 mg/1
No discharge
The maximum for any one day shall not exceed 42
mg/1, and the 30-day average shall not exceed 29 mg/1
No discharge
No discharge
Minimum of 1 mg/1 and maintained as close to this
concentration as possible.
No discharge
No discharge of floating solids or garbage or foam
(1) As determined by the static sheen test (see Appendix 1 to 40 CFR Subpart A).
(2) As determined by the toxicity test (see Appendix 2 of 40 CFR Subpart A).
(3) As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water
(visual sheen). '
(4) As defined in 40 CFR §435.41. '
XIV-5
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TABLE XIV-5
PSNS AND PSES EFFLUENT LIMITATIONS
Wastestream ,, 7* %. '
- *, 5'", f''- " < ',
% < v' / >4 f SS A • 'S
Drilling Fluids, Drill Cuttings
and Dewatering Effluent
Produced Water
Well Treatment, Workover
and Completion Fluids
Produced Sand
Deck Drainage
- ••PSNS and PSES Limitations
No discharge
No discharge
No discharge
No discharge
No discharge
3.0 OPTION SELECTION RATIONALE
3.1 DRILLING FLUIDS, DRILL CUTTINGS AND DEWATERING EFFLUENT
3.1.1 BAT and NSPS
EPA is establishing BAT and NSPS limitations that require zero discharge of drilling fluids, drill
cuttings, and dewatering effluent (drilling wastes), except in Cook Inlet, Alaska. For BAT and NSPS in
Cook Inlet, discharge limitations include no discharge of free oil, no discharge of diesel oil, ! mg/kg
mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000 ppm in
the suspended particulate phase (SPP). BAT and BCT limitations for dewatering effluent are applied
prospectively. BAT and BCT limitations in this rule are not applicable to discharges of dewatering effluent
from reserve pits which as of the effective date of the coastal guidelines no longer receive drilling fluids
and drill cuttings. Limitations on such discharges shall be determined by the NPDES permit issuing
authority. BAT and BCT limitations are applicable to dewatering effluent from reserve pits which receive
drilling wastes after the effective date of the coastal guidelines.
In the 1995 proposal, EPA presented three options for both BAT and NSPS limitations. The three
options were: (1) Zero discharge of drilling fluids, drill cuttings, and dewatering effluent except for Cook
Inlet, where discharge limitations include no discharge of free oil, no discharge of diesel oil, 1 mg/kg
mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000 ppm; (2)
Zero discharge of drilling fluids, drill cuttings, and dewatering effluent except for Cook Inlet, where
XIV-6
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discharge limitations include no discharge of free oil, no discharge of diesel oil, both 1 mg/kg mercury and
3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation in range of 100,000 ppm to 1
million ppm; and (3) Zero discharge everywhere. The control option including the more stringent toxicity
limitation was based, in part, on the volume of drilling wastes that could be injected or disposed of onshore
without interfering with ongoing drilling operations. The more stringent toxicity limit would have been
based on (1) the volume of drilling wastes that could be subjected to zero discharge without interfering with
ongoing drilling operations and (2) a specified level of toxicity selected such that no more than this volume
of waste, determined in the previous step, would exceed the specified level of toxicity. However, as
pointed out in comments on the proposal and confirmed with further investigation, there are a number of
problems with the database that would be used to establish a more stringent toxicity limitation. Many of
the records in the database do not have either a waste volume identified or indicate whether the drilling
fluids were discharged. Where waste volumes are reported, the methods used to determine these volumes
are not consistent and they are not documented. It is also unclear whether the volumes and fluid systems
reported for any given well represent a complete record of the drilling activity associated with the well.
For these reasons, EPA rejected the option of developing a more stringent toxicity limitation for the final
rule.
Following elimination of the more stringent toxicity limitation, EPA's analyses for the final rule
considered two options for the BAT and NSPS level of control for drilling fluids, drill cuttings and
dewatering effluent. (In the discussion of limitations for drilling wastes in this chapter and elsewhere in the
Development Document, the limitations discussed for drilling fluids and drill cuttings also apply to
dewatering effluent.)
Under Option 1 for the final rule, BAT and NSPS would require zero discharge of drilling fluids
and drill cuttings for all coastal drilling operations except those located in Cook Inlet. Allowable discharge
limitations for drilling fluids and cuttings in Cook Inlet would require compliance with a toxicity value of
no less than 30,000 ppm; no discharge of free oil (as determined by the static sheen test); no discharge of
diesel oil; and a maximum of 1 mg/kg of mercury and 3 mg/kg of cadmium in the stock barite. Limitations
for Cook Inlet are identical to the limitations applicable to offshore discharges in Alaska. Option 1 was
developed taking into consideration that Cook Inlet operations are unique to the industry due to a
combination of geology available for grinding and injection, climate, transportation logistics, and structural
and space limitations that interfere with drilling operations. Operators would not incur any incremental
XTV-7
-------
costs, nor are there any incremental pollutant reductions or non-water quality environmental impacts due
to the coastal guidelines under Option 1 because the requirements reflect current practice.
Under Option 2 for the final rule, BAT and NSPS would prohibit the discharge of drilling fluids
and drill cuttings from all coastal oil and gas drilling operations. In Cook Inlet, for reasons discussed
below, this option uses onshore disposal as the basis for complying with zero discharge of drilling fluids
and drill cuttings. Outside of Cook Inlet, this option uses a combination of grinding and injection and
onshore disposal as a basis for complying with zero discharge of drilling fluids and drill cuttings. Costs
to comply with Option 2 (zero discharge all) are attributed only to Cook Inlet operators. Costs to comply
with BAT zero discharge limits are estimated to be approximately $8,200,000 annually for the Cook Inlet
operators. The BAT limitations would remove approximately 24,089,000 pounds/year of conventional
pollutants, 1,194,000 pounds/year of nonconventional pollutants, and 4,300 pounds/year of priority
pollutants. Non-water quality environmental impacts due to zero discharge under BAT include 5,200
barrels of oil equivalent (BOE) of fuel being used annually, resulting in approximately 72,000 pounds/year
of air emissions (see Chapter X for a discussion of pollutant reductions and costs associated with the control
options; non-water quality environmental impacts are discussed in Chapter XTS).
EPA has identified no incremental costs, pollutant reductions, or non-water quality environmental
impacts attributable to the zero discharge NSPS requirements under Option 2 of the coastal guidelines. In
the absence of the NSPS being promulgated in the coastal guidelines, all new coastal facilities outside Cook
Inlet would be expected to comply with existing NPDES or State zero discharge requirements. Based on
information available in the record, EPA projects that no new sources will be developed in Cook Inlet and
thus no costs would be attributable to NSPS requirements for drilling wastes. This is because all future
development wells are expected to be drilled from existing platforms in Cook Inlet. According to the
definition of new sources, these wells would be existing sources. Additionally, any drillings that may occur
in the recently discovered Sunfish formation or other areas identified by industry in Cook Inlet are
projected to be exploratory wells, which are also existing sources according to the new source definition.
Thus, no costs are attributed to NSPS in Cook Inlet. (Nonetheless, EPA did conservatively assess the costs
and economic impacts that would be attributed to NSPS should a new source be developed in Cook Inlet.
EPA determined that the costs to meet zero discharge would not pose a barrier to entry for the drilling
project; however, as described below there are technical problems associated with any individual new
source meeting zero discharge. The analysis of NSPS costs for a model new source platform in Cook Inlet
is discussed in the Economic Impact Analysis1 and Chapter X of the Development Document.)
XIV-8
-------
In the final rule, EPA is establishing BAT and NSPS limitations described above for Option 1,
which requires zero discharge for drilling fluids, drill cuttings and dewatering effluent, except in Cook
Met. In Cook Inlet, discharge limitations include no discharge of free oil, no discharge of diesel oil, both
1 nag/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000
ppm. With regard to coastal facilities outside of Cook Inlet, zero discharge is technically and economically
achievable because it reflects current industry practices under existing permit requirements.
With regard to coastal facilities in Cook Met, EPA rejected zero discharge in large part because
the technology of grinding and injection has not been demonstrated to be available throughout Cook Met,
and because of operational interferences that would result if operators were required to haul all drilling
wastes to shore for disposal.
Drilling fluids and drill cuttings can not be injected into producing formations, as is sometimes the
case for produced water, because they would interfere with hydrocarbon recovery. The high solids
content of these wastes would plug the formation and impede subsurface fluid flow. Thus, operators must
have available different formation zones with appropriate characteristics (e.g., porosity and permeability)
for injection of drilling fluids and drill cuttings (see Chapter VII for a discussion of geologic characteristics
for the injection of these drilling wastes). Unlike the coastal region along the Gulf of Mexico or the North
Slope of Alaska, where the subsurface geology is relatively porous and formations for injection are readily
available, the geology in Cook Met is highly fragmented and information in the record indicates that
formations amenable to injection may not be available throughout Cook Met.2-3 HPA reviewed information
where attempts to grind and inject drilling fluids and drill cuttings failed in the Cook Inlet area. For
example, one operator attempted to operate a grinding and injection well in the Kenai gas field that failed
due to downhole mechanical failure of the injection well (1992/1993).2-3 There, the well experienced
abnormal pressure on the well annulus, necessitating shutdown of the disposal operation. The operator also
attempted annular pumping of drilling fluids and drill cuttings in two production wells in the Ivan River
Field (onshore on the west side of Cook Inlet) where the annuli of both wells plugged during injection.4
Another operator, attempting to pump drilling waste into the annuli of exploration wells, lost the integrity
of the well.3 In view of these difficulties encountered in injecting drilling wastes and the limited data
available to date, EPA is unable to estimate the degree to which injection would be available in Cook Met
and believes that the information in the record indicates that certain sites in Cook Inlet may not be able to
inject sufficient volumes of drilling wastes to enable compliance with zero discharge.
XTV-9
-------
Because not all of the drilling fluids and drill cuttings can be injected, much of the waste would
have to be land disposed. The sole land disposal site for drilling wastes in Cook Inlet (referred herein as
the Kustatan landfill) is a private facility owned by two of the operators. While no regulatory obstacles
would prohibit disposing of the wastes from other operators at the Kustatan landfill, since it is a private
facility its availability for use by third parties cannot be assured. As a result, EPA's analysis considers the
Kustatan landfill to be available for use by only two of the operators in the region. Since no other land
disposal facilities in Alaska are believed available to the remaining Cook Inlet operators, land disposal costs
for these operators are based on transporting the drilling wastes to a disposal facility in Oregon. (EPA is
unaware of any other land disposal facilities coming into existence hi Cook Inlet, as Cook Inlet is a fairly
mature field nearing the end of its useful life. All but one of the existing platforms were installed hi the
1960s. The newest platform began production in 1987, but production from the facility has remained well
below expectations.) Land disposal is a problem for Cook Inlet operators, analogous to those faced by
offshore operators in Alaska, because the climate and safety conditions that exist during parts of the year
in Cook Inlet make transportation of drilling fluids and drill cuttings particularly difficult and hazardous.
The harsh climate, snow, ice, and poor visibility from fog and snow often restrict land and sea
transportation. Also, the extensive tidal fluctuations (typically near, and frequently hi excess of, 30 feet),
strong currents affecting waste transfer operations between the platforms and boats (on the order of 6-9
knots in the vicinity of platforms), and ice formation during whiter months hi the Inlet impose severe
logistical difficulties for storing and transporting the drilling wastes (see Chapters VII and X for a
discussion of tides, currents and climatological factors affecting waste transfer operations and navigation
in Cook Inlet).
Moreover, the limited storage space on platforms and transportation-related difficulties and delays
associated with a zero discharge limitation for all drilling wastes would impose severe operational
constraints on drilling activities. Under current NPDES permit requirements (which are the same as the
requirements for Option 1), the volumes of drilling wastes which cannot be discharged are sufficiently
small to allow operators flexibility to schedule removal of the wastes from the platform in a manner which
minimizes operational impacts. That is, the waste volumes requiring transport to shore generally are small
enough in comparison to the available storage space on the platform to allow operators to hold the drilling
wastes long enough to schedule waste removal hi a manner that minimizes drilling interruptions (e.g., can
conduct waste transfer evolutions during periods of slack tide and avoid severe fog and other weather
conditions). However, under a zero discharge scenario where all drilling wastes are taken to shore for
disposal, the rate of waste generation is large enough (relative to the platform storage capacity of 12
xrv-io
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cuttings boxes) that frequent boat trips are required at certain phases of the drilling operation. Over the
first fifty days of drilling, wastes must be transferred to boats an average of every 1-2 days, and more often
at certain stages when drill cuttings are generated at high rates.5
The required frequency of boat trips makes it difficult to avoid the effects of large tidal ranges,
current action (especially during peak flood and ebb tides when the boats must remain on station next to
fixed platforms while countering 6-9 knot currents and wave action), ice, fog and other climatological
conditions such as snow and high winds. Currents in Cook Inlet narrows have average speeds of more than
8.5 knots and 6 knot currents at East Foreland are common. Currents are highest during peak ebb and
flow tides, and the slack tide (the time in between ebb and flow tides, when the currents are relatively slow)
is brief. High waves are common in this area and localized rip currents where the current is extremely fast
are not unusual in Cook Inlet.6
Due to ocean currents and wave action, boats must maintain engines idling while at platforms
unloading empty cuttings boxes and loading drilling fluids and boxes. The total average time idling on
station at the drill site for loading is 4.15 hours per visit.7 As a result, it is likely that a zero discharge
requirement for all drilling wastes hi Cook Inlet could interfere with operations to the extent that drilling
would be periodically halted due to the inability to remove drilling wastes from the platform expeditiously.
Thus, for purposes for BAT and NSPS, EPA does not believe that land disposal of all drilling wastes is
generally available for Cook Inlet operators. These same operational constraints hindering land disposal
of large drilling waste volumes would also apply in the case of operators being required to haul all drillings
to shore locations'where subsurface injection of drilling wastes may be available.
There are non-water quality environmental impacts associated with a zero discharge limitation for
Cook Inlet, as discussed above. While EPA believes the non-water quality environmental impacts — in and
of themselves — are not unacceptable, by comparison with the operational constraints discussed above and
pollutants removed by zero discharge (4,300 pounds of toxic pollutants annually), these non-water quality
environmental impacts weigh against requiring zero discharge in Cook Inlet.
The NSPS requirements selected for the final rule, both inside and outside of Cook Inlet, are
technically and economically achievable because they reflect current practice. With regard to the potential
for a barrier to entry, NSPS are equal to BAT limitations. BAT limitations have been demonstrated to be
economically achievable for existing structures. Design and construction of pollution control equipment
XIV-11
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on new production facilities is generally less expensive flan retrofitting existing facilities. Therefore, while
the NSPS are equal to BAT limitations, it is less costly for new structures to meet these requirements and
these costs would not inhibit development of new sources. Costs for new sources are generally less than
BAT because process modifications can be incorporated into the drilling rig design prior to its installation
rather than retrofitting an existing operation. Since EPA has determined that BAT is economically
achievable, equivalent NSPS requirements would also be economically achievable, and cause no barrier
to entry,
3.1.2 BCT
With the exception of Cook Inlet, BCT limitations require zero discharge of drilling fluids, drill
cuttings, and dewatering effluent. In Cook Inlet, BCT limitations prohibit the discharge of free oil.
Because all operators throughout the coastal subcategory, except in Cook Inlet, are currently
practicing zero discharge of drilling fluids and drill cuttings and dewatering effluent, zero discharge was
the only option considered for coastal areas outside Cook Inlet. Since zero discharge reflects current
practice, there are no incremental costs, pottutant reductions, or non-water quality environmental impacts
associated with this limitation. Thus, EPA has determined that zero discharge passes the BCT cost tests
and other statutory factors and is establishing the BCT limitation equal to zero discharge for all areas except
Cook Met.
la Cook Met, EPA considered two options for BCT control: (1) setting BCT equal to the BPT
limits prohibiting discharges of free oil; and (2) zero discharge. As discussed above for BAT, EPA
determined that zero discharge of all drilling wastes in Cook Inlet is not technologically available. The
costs, pollutant reductions, and the results of the BCT cost test calculations are presented in Chapter X for
informational purposes. There are no incremental costs, pollutant reductions, or non-water quality
environmental impacts associated with the BCT "no free oil" limitation for Cook Met because it is equal"
to current BPT requirements.
3.1.3 Pretreatment Standards for Drilling Wastes
EPA develops pretreatment standards for existing sources (PSES) under Section 307(b) of the Clean
Water Act (CWA). Pretreatment standards are designed to prevent the discharge of the poEutants that pass
through, interfere with, or are otherwise incompatible with the operation of publicly owned treatment
works (POTWs). PSES are technology-based and analogous to the best available technology economically
XTV-12
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achievable (BAT) for direct dischargers. Section 307(c) of the CWA requires EPA to promulgate
pretreatment standards for new sources (PSNS) at the same time that it promulgates new source
performance standards (NSPS). PSNS are technology-based and analogous to the best demonstrated control
technology (BADCT) for direct dischargers. New indirect discharging facilities, like new direct
discharging facilities, have the opportunity to install the best available demonstrated technology, including
process changes, in-plant controls, and end-of-pipe treatment technologies.
EPA determines whether or not to regulate a pollutant under pretreatment standards on the basis
of whether or not the pollutant passes through, interferes with, or is incompatible with the operation of the
POTW. EPA evaluates pollutant pass through by comparing the average percentage removed nationwide
by well-operated POTWs (those meeting secondary treatment requirements) with the percentage removed
by directly discharging facilities applying BAT for that pollutant. When the average percentage removed
by well-operated POTWs is less than the percentage removed applying BAT, the pollutant is said to pass
through and a pretreatment standard would be required. When the pollutant does not pass through (average
percentage removed by well-operated POTWs is greater than the percentage removed by applying BAT)
a pretreatment standard would not be'required. To the extent that BAT and NSPS require zero discharge
under the coastal guidelines, any pretreatment standard which allows discharge of the wastestream would
be allowing toxic pollutants to pass through because biological treatment will not achieve complete pollutant
removal.
The general pretreatment regulations, applicable to existing and new source indirect dischargers
(PSES and PSNS) are codified at 40 CFR Part 403. These regulations describe the Agency's overall policy
for establishing and enforcing pretreatment standards for new and existing users of a POTW as well as the
prohibited discharges that apply.
Based on comments, the 1993 Coastal Oil and Gas Questionnaire, and other information reviewed
as part of this rulemaking, EPA has not identified any existing coastal oil and gas facilities which discharge
drilling fluids and drill cuttings to POTWs, nor are any new facilities projected to direct these wastes in
such manner. However, due to the high solids content of drilling fluids and drill cuttings, EPA is
establishing pretreatment standards for existing and new sources in all coastal areas equal to zero discharge
because these wastes are incompatible and would interfere with POTW operations. Certain constituents
present in drilling wastes can exhibit effluent toxicity and would be expected to further interfere with
POTW operations. In addition, the high solids content of the wastes would likely cause obstruction to the
XIV-13
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flow in the POTW resulting in interference with POTW operations due to the high total suspended solids
(TSS) content which could not only cause clogging in the piping leading into the POTW, but interfere with
the biological treatment systems as well. And as stated in 40 CFR Part 403.5 "National Pretreatment
Standards: Prohibited discharges": Solid or viscous pollutants hi amounts which will cause obstruction to
the flow in the POTW resulting in interference shall not be introduced into POTWs. This can occur with
drilling fluids and drill cuttings due to the high solids content (pollutants found in drilling fluids and drill
cuttings are listed in Chapter VU).
Further, where BAT and NSPS limitations require zero discharge, these limits result in complete
removal of toxic pollutants. Any pretrearment standard allowing discharge after biological treatment at a
POTW (which would not accomplish 100 percent removal of toxic pollutants) would effectively allow pass
through of toxic pollutants to surface waters. For PSNS, zero discharge would not cause a barrier to entry.1
3.2 PRODUCED WATER AND TREATMENT, WORKOVER AND COMPLETION FLUIDS
3.2.1 Summary of Produced Water and TWC Requirements
EPA is establishing BAT and NSPS limitations prohibiting discharges of produced water and
treatment, workover and completion (TWC) fluids from all coastal facilities, except for those facilities
located in Cook Inlet. Coastal facilities in Cook Inlet are required to comply with oil and grease limitations
(29 mg/1 monthly average; 42 mg/1 daily maximum) based on improved operating performance of gas
flotation. EPA has determined the limitations are economically achievable and technologically available,
and they reflect the BAT and BADCT (NSPS) levels of control.
EPA has reviewed the extensive information compiled during the coastal and offshore guidelines
rulemaking efforts regarding treatment practices for TWC fluids. Based on industry responses to the 1993
Coastal Oil and Gas Questionnaire and other information in the record, including site visit reports and other
industry contacts, EPA has determined that, in the coastal subcategory, TWC fluids are generally
commingled with produced water, especially where the proportion of produced water to TWC fluids is high
enough to overcome any interference the TWC fluids may have on the produced water treatment system.
The rulemaking record also demonstrates that where TWC fluids are not currently commingled, they can
be effectively commingled with produced water and be discharged in compliance with the NSPS and BAT
limits of the coastal guidelines if the treatment equipment is operated properly and TWC fluids introduced
to the system in a prudent manner. In view of this information, EPA is establishing limitations for TWC
fluids equivalent to produced water limitations.
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3.2.2 Options Considered
Three options were considered in the final rule for BAT and NSPS control of produced water and
TWC fluids. The costs, pollutant reductions, and non-water quality environmental impacts associated with
these options are presented in Chapters XI, XII, and Xffl.
Option 1 - (Zero Discharge: Except Major Deltaic Pass and Cook Inlet Based On Improved Gas
Flotation): With the exception of facilities in Cook Inlet and facilities discharging offshore
produced water into the coastal subcategory waters of a major deltaic pass of the Mississippi River
or the Atchafalaya River below Morgan City, all coastal oil and gas facilities and all facilities
discharging offshore produced water into coastal locations would be prohibited from discharging
produced water and treatment, workover, and completion fluids. Coastal facilities in Cook Inlet
and facilities discharging offshore produced water into a major deltaic pass would be required to
comply with oil and grease limitations of 29 mg/1 monthly average and 42 mg/1 daily maximum
based on improved performance of gas flotation.
Option 2 - (Zero Discharge: Except Cook Inlet Based On Improved Gas Flotation): With the
exception of coastal facilities in Cook Inlet, all coastal oil and gas facilities would be prohibited
from discharging produced water and treatment, workover, and completion fluids. Discharges of
offshore produced water and treatment, workover, and completion fluids would be prohibited when
the wastes are discharged in coastal locations. Coastal facilities in Cook Inlet would be required
to comply with oil and grease limitations of 29 mg/1 monthly average and 42 mg/1 daily maximum
based on improved performance of gas flotation.
Option 3 - (Zero Discharge All): For all coastal facilities, this option would prohibit discharges
of produced water and treatment, workover, and completion fluids based on injection. Further,
discharges of offshore produced water and treatment, workover, and completion fluids would be
prohibited in coastal locations.
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3.2.3 Rationale for Selection of BAT for Produced Water and TWO Fluids
3.2.3. / BAT Rationale for Coastal Subcategory (Except Cook Inlet)
EPA is establishing zero discharge of produced water and TWC fluids as BAT for the coastal
subcategory (except for Cook Inlet) because it is technically available, economically achievable and reflects
the appropriate level of BAT control.
Zero discharge of produced water and TWC fluids is technically available. Zero discharge of
produced water has been required of onshore facilities since EPA promulgated BPT regulations for the
onshore subcategory of the oil and gas industry, in 1979. 40 CFR Part 435 Subpart C (44 FR 22069; April
13, 1979). With the exception of Cook Inlet, injection of produced water is widely practiced by facilities
in the coastal subcategory. Independent of this rule, all coastal facilities in Alabama, California,
Mississippi, Florida, and the North Slope of Alaska are currently practicing zero discharge. EPA estimates
that at least 80% to 99.9% of all coastal facilities in Louisiana and Texas will be practicing zero discharge
by January 1, 1997. The 80% estimate is based on subtracting the sum of the six facilities discharging into
a major deltaic pass of the Mississippi, the 37 facilities (82 outfalls) discharging to Louisiana open bays,
and the 82 facilities associated with individual permit applications in Texas from the 853 total coastal
facilities in Louisiana and Texas. The 99.9% estimate is based on subtracting the number of facilities
discharging into a major deltaic pass of the Mississippi from the total number coastal facilities along
Louisiana and Texas. Additionally, using data from the Coastal Oil and Gas Questionnaire and other
information regarding facilities known to be discharging in 1992, EPA estimated that 62% of coastal
facilities along the Gulf of Mexico were practicing zero discharge hi 1992. For the onshore subcategory,
injection is the predominant technology used to comply with the zero discharge BPT limitation promulgated
in 1979.
Some coastal operators have voluntarily upgraded to zero discharge technologies while other
coastal operators have been subject to consent decrees requiring zero discharge in citizen suits filed by
environmental groups. In the western Gulf of Mexico, coastal dischargers are covered by the current
general permits which require zero discharge, but these facilities also have an administrative order allowing
until January 1997 to come into compliance with zero discharge. Formations appropriate for injection of
produced water have been demonstrated to be available for coastal facilities in the Gulf of Mexico.
In response to comments that operators discharging offshore produced water into a major deltaic
pass of the Mississippi should not be subject to zero discharge, EPA closely examined these facilities.
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However, EPA has identified no basis for providing these facilities with limitations other than those
established for the coastal subcategory outside of Cook Inlet. Injection has been widely demonstrated in
practice as available to coastal facilities in states along the Gulf Coast, including facilities discharging
coastal-derived produced water that are near these facilities discharging offshore-derived produced water.
Zero discharge of produced water and TWC fluids for the coastal subcategory, except Cook Inlet,
is economically achievable. As discussed below, EPA conducted the economic analysis under two
baselines, the current regulatory requirements baseline and an alternative baseline. (See Chapter IV for a
discussion of the alternative baseline.) Under the current requirements baseline, the only facilities outside
of Cook Inlet that are incurring costs las a result of this rule are those discharging wastes from the offshore
subcategory into a "major deltaic pass." Under the alternative baseline, facilities outside of Cook Inlet that
are incurring costs as a result of this rule includes those discharging wastes from the offshore subcategory
into a "major deltaic pass," individual permit applicants in Texas, and Louisiana open bay dischargers.
No closures are projected for the six facilities discharging to a major deltaic pass. Major pass
facilities incur costs and impacts under both the current requirements and the alternative baselines. For
major pass operations, the lifetime production loss is expected to be up to 3.4 million total BOE, which
is 0.6 percent of estimated lifetime production from these facilities. While these losses may be significant
for these dischargers, in context of the coastal subcategory as a whole, this production loss represents 0.3
percent of the coastal production along the Gulf of Mexico. Employment losses in both Cook Inlet and
along the Gulf Coast are acceptable: Considering this small percentage loss of BOE and profitability,
coupled with the determination of no closures, EPA believes that zero discharge is economically achievable
under the CWA.
For individual permit applicants in Texas and Louisiana open bay dischargers, a total of up to 94
wells may be first year shut-ins under zero discharge. Individual permit applicants in Texas and Louisiana
open bay dischargers are considered to have financial impacts only under the alternative baseline. These
wells are approximately 2 percent of all Gulf of Mexico coastal wells. EPA estimates related production
losses would be approximately 12.8 million BOE. This represents less than one percent of all Gulf coastal
production, most of which is in compliance with zero discharge requirements. A maximum of 1 firm
among the Louisiana open bay dischargers and 3 firms among the individual permit applicants from Texas
could foil as a result of the proposed regulatory options. However, EPA's modeling tends to overestimate
economic impacts and firm failures, since these models project that some currently operating firms have
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already failed. These potential failures represent less than one percent of all Gulf of Mexico coastal firms.
EPA also did a facility-level analysis, conducted in response to facility-level information received from
Texas very late in the rulemaMng, that shows fewer wells are baseline failures and fewer wells fail due to
the costs of this rule because wells combine efforts for treatment and production. EPA views the small
percentage loss of BOB and profitability, coupled with the determination of a small number of firm
closures, to meet the definition of economic achievability under the CWA.
The non-water quality environmental impacts of zero discharge, discussed in Chapter XIII, are
acceptable.
3.2.3.2 BAT Rationale for Cook Inlet
EPA is establishing BAT limitations based on improved gas flotation, rather than zero discharge.
EPA rejects zero discharge of produced water because zero discharge is not economically achievable in
Cook Inlet.
EPA considered Cook Inlet separately from other areas in the coastal subcategory because Cook
Inlet is geographically isolated from other areas in the coastal subcategory, zero discharge of produced
water would have disproportionately adverse economic impact hi Cook Inlet.
Unlike states along the Gulf Coast, only the production formation is generally available for
injection of produced water. Because of this, zero discharge would require the additional costs associated
with piping produced water from existing production facilities to existing waterflood injection sites.
EPA's economic analysis shows a disproportionate impact of zero discharge on Cook Inlet as
compared with the rest of the coastal subcategory. EPA projects that zero discharge requirements for Cook
Inlet would close 1 of the 13 existing production platforms and result in the loss of 108 jobs in the oil and
gas industry in Cook Inlet. In addition, there are severe economic impacts on two additional platforms that
were projected to fail at proposal. These disproportionate impacts are demonstrated by a loss in net present
value in Cook Inlet of 18.5 percent as compared to only 1.4 percent in the Gulf coast under the current
requirements baseline. In addition, there are disproportionate impacts in Cook Inlet with regard to
employment, where Cook Inlet already suffers from unemployment higher than the national average and
higher than the rest of the coastal subcategory. The most recently reported (1991) unemployment rate in
Cook Met is 12.7 percent, as compared with the unemployment rate in the Gulf coast of 6.2 to 6.4 percent
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and the national unemployment rate of about 5.2 percent. The loss of 108 jobs that would occur in Cook
Inlet from zero discharge would raise the unemployment level in Cook Inlet 0.5 percent, to 13.2 percent.
Thus, zero discharge would worsen the serious unemployment situation that exists in Cook Met. Because
Cook Inlet is economically and geographically isolated and the economic effects of zero discharge in Cook
Inlet are significant and disproportionately worse than they are in the rest of the subcategory, EPA rejects
zero discharge in Cook Inlet as not economically achievable.
Limitations based on improved gas flotation are technically and economically achievable for Cook
Inlet facilities. These limitations are a daily maximum of 42 mg/1 and a monthly average of 29 mg/1 for
oil and grease. Improved gas flotation technology has been demonstrated in the offshore subcategory
where the wastestreams and physical constraints are similar. No platform closures are expected as a result
of establishing these limitations. EPA expects the production loss over the productive lifetime of these
platforms to be approximately 2.4 million BOE, which is 0.5 percent of the estimated lifetime production
for the Inlet.
The non-water quality environmental impacts of improved gas flotation, discussed in Chapter Xm,
are acceptable. ;
3.2.4 NSPS Rationale for Produced Water and TWC Fluids
For NSPS control of produced water and treatment, workover, and completion fluid discharges
from new sources, EPA is establishing the limitations associated with "Option 2 - Zero Discharge; Except
Cook Inlet Based On Improved Gas Flotation." Zero discharge for Cook Inlet was rejected because of
uncertainties regarding the availability of geologic formations suitable for receiving injected produced
water. Information in the record indicates that a potential new source in Cook Inlet could be unable to
inject adequate produced water volumes near the new source. (See the discussion in Chapter XI which
notes that the geology below the Trading Bay Production Facility is inadequate for subsurface disposal of
produced water. For existing sources in Cook Inlet, because of uncertainties related to Cook Inlet geology,
EPA assumed that compliance with zero discharge would be met through injection into the highly depleted
production formations that are currently being waterflooded with seawater.) As a result, the new source
could be faced with the substantial expenses associated with piping the produced water to a location (the
distance of which is unknown at this! time) where suitable geology would be available.
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Option 2 is economically achievable for the reasons discussed below and in the Economic Impact
Analysis.1 The selected option for NSPS is equal to the selected BAT option for produced water and TWC
fluids. The BAT option has been demonstrated to be technologically available and economically achievable
for existing structures. Design and construction of pollution control equipment on new production facilities
is generally less expensive than retrofitting existing facilities. Therefore, while the NSPS requirements are
equal to the BAT requirement, it is less costly for new structures to meet these requirements and these costs
would not inhibit development of new sources. EPA has determined the non-water quality environmental
impacts (presented in Chapter Xffl) to be acceptable for the selected NSPS option for control of produced
water and TWC fluids.
EPA has identified no new sources of produced water discharges incurring costs due to the NSPS
requirements of the coastal guidelines. In the absence of NSPS promulgation under the coastal guidelines,
due to currently existing state and NPDES permit requirements, all new facilities hi coastal areas, except
Cook Inlet, would be considered new dischargers subject to existing zero discharge requirements for
produced water. No new sources discharging offshore subcategory produced water into the major passes
of the Mississippi River or to the Atchafalaya River are projected. Based on information hi the record,
EPA also projects that no new sources will be developed hi Cook Inlet. Accordingly, EPA has identified
no costs attributable to the NSPS requirements for produced water hi the coastal guidelines. (EPA did
identify costs associated with new source discharges of TWC fluids. The costs and pollutant reductions
for these discharges are presented in Chapter XII. Non-water quality environmental impacts are discussed
in Chapter Xin. Economic impacts are presented hi the "Economic Impact Analysis of Final Effluent
Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point
Source Category."1) Nevertheless, EPA assessed the costs and economic impacts incurred by a model new
source facility under the zero discharge scenario should conditions and future information lead to
development of new sources hi Cook Inlet. For the modeled scenario, EPA based costs on injecting
produced water near the new source facility. However, because of the uncertainties regarding availability
of formations suitable for injection, it is possible that a new source structure would incur some unknown
cost for piping the produced water to a suitable injection location. Since the location and availability of
formations for any new source hi Cook Inlet are unknown, the maximum cost associated with piping
produced water from the wellhead to the nearest injection well cannot be estimated.
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3.2.5 BCT for Produced Water and TWC Fluids
All options considered failed the BCT cost tests (See discussion in Chapter XL) Therefore, EPA
is establishing BCT limitations for produced water equal to the existing BPT limitations for oil and grease
(48 mg/1 monthly average; 72 mg/1 daily maximum). Limitations for treatment, workover, and completion
fluids are established equal to existing BPT and NPDES permit limitations which require zero discharge
of TWC fluids in fresh water in Texas and Louisiana, and no discharge of free oil in all other coastal
locations. The BCT limitations reflects existing discharge practices current permit requirements. There
are no incremental costs, pollutant reductions, or non-water quality environmental impacts associated the
BCT limitations because they reflect current discharge practices.
3.2.6 Pretreatment Standards for Produced Water and TWC Fluids
EPA is establishing pretreatment standards for existing and new sources (PSES and PSNS,
respectively) that prohibit the discharge of produced water and treatment, workover, and completion fluids.
There are no incremental costs, pollutant reductions, or non-water quality environmental impacts associated
with the PSES and PSNS requirements. Thus, EPA has determined that PSES and PSNS are economically
achievable and technologically available.
Based on the 1993 Coastal Oil and Gas Questionnaire and other information reviewed as part of
this rulemaking, EPA has not identified any existing coastal oil and gas facilities which discharge produced
water or treatment, workover, and completion fluids to POTWs, nor are any new facilities projected to
direct their discharges of produced water and TWC fluids in such manner. (It should also be noted that
most coastal facilities are not hi locations amenable to sewer hookup.) However, because EPA is
establishing a limitation requiring zero discharge for existing facilities, there is the potential that some
facilities may consider discharging to, POTWs hi order to circumvent the BAT and /or NSPS limitations.
Pretreatment standards for produced water and treatment, workover, and completion fluids are appropriate
because EPA has identified the presence of a number of toxic and nonconventional pollutants, many of
which are incompatible with the biological removal processes at POTWs. Large concentrations of dissolved
solids in the form of various salts in the produced water and TWC fluids discharge are generally
incompatible with the biological treatment processes at POTWs because these "brines" (and certain
constituents in these wastes) can be lethal to the unacclimated organisms present in the POTW biological
treatment systems. (See Chapter VIII for detailed information on produced water characterization. See
Chapter IX for characteristics of TWC fluids. Certain constituents present hi these wastes can exhibit
effluent toxicity and would be expected to further interfere with POTW operations.) While it is possible
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that an acclimated biological treatment system under relatively constant pollutant load and wastewater flow
may be capable of treating produced water discharges containing relatively low concentrations of total
dissolved solids, such a situation would not be typical of that generally faced at coastal production facilities.
It is uncommon for this industry to discharge produced water effluent at the nearly constant concentrations
and flow rate that would be necessary for a biological treatment system to work properly. Variations in
flow and pollutant concentrations exist, and production processes may cease periodically for a short time
to rework and maintain the well. Major interruptions could occur as a result, causing interferences with
the operation of POTWs.
Although there are no coastal subcategory facilities discharging produced water to POTWs, EPA
is aware of some onshore subcategory discharges of produced water to POTWs. In these instances, the
produced water comprises a very small proportion of the total wastewater flow received by the POTW, on
the order of less than 0.5 percent. This level of dilution minimizes the adverse impacts on the POTWs.
Except for one POTW, the POTWs discharge into the ocean where effluent limits for the POTW are less
stringent than in inland surface waters. The POTW discharging to inland receiving waters has experienced
difficulties in the past (exceeding NPDES discharge limitations) due to the high total dissolved solids (TDS)
level in the POTW effluent. The high TDS level in the POTW effluent was attributed to the produced
water.8
Further, in those locations where BAT require zero discharge, the BAT limitation results hi
complete removal of toxic pollutants. Any pretreatment standard allowing discharge after biological
treatment at a POTW (which would not accomplish 100 percent removal of toxic pollutants) would
effectively allow pass through of toxic pollutants to surface waters. For PSNS, zero discharge would not
cause a barrier to entry.1 Design and construction of pollution control equipment on new production
facilities is generally less expensive than retrofitting existing facilities. Therefore, while the PSNS
requirements are equal to the PSES requirement, it is less costly for new structures to meet these
requirements and these costs would not inhibit development of new sources.
3.3 DECK DRAINAGE
EPA is establishing BCT, BAT and NSPS limitations which prohibit discharges of free oil. Since
free oil discharges are already prohibited under existing BPT requirements, there are no incremental
compliance costs, pollutant removals, or non-water quality environmental impacts associated with the
limitations promulgated in the final rule. Since there are no incremental compliance costs, the BCT
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limitation passes the BCT cost tests. Also, since the limitations prohibiting discharges of free oil are equal
to existing BPT standards, it is technologically available and economically achievable. EPA has determined
that these limitations and standards properly reflect BAT and NSPS levels of control. EPA did not identify
any other available technology for this waste stream.
EPA is requiring zero discharge of deck drainage for the entire coastal subcategory under PSES
and PSNS. EPA believes that zero discharge for PSES and PSNS is appropriate because influent slugs of
deck drainage would be expected to interfere with biological treatment processes at POTWs. Deck
drainage, by its very nature, is contaminated with other process wastewaters from oil and gas operations
and has the potential for interference and pass through of toxic pollutants, as described hi Sections 3.1.3
and 3.2.6 above in this chapter for drilling wastes, produced water, and TWC fluids. EPA has identified
no existing coastal subcategory facilities discharging deck drainage to POTWs, nor are any new source
coastal facilities projected to do so. Moreover, technical difficulties associated with capture of deck
drainage that make it difficult to require limitations other than the BPT prohibition on the discharge of free
i
oil, as well as the fact that coastal facilities generally are not located in areas amenable to sewer hookup,
i
makes it unlikely that this wastestream would be sent to POTWs. Thus, there are no incremental costs
associated with the PSES and PSNS limitations.
At proposal, EPA considered establishing limitations based on commingling and treating deck
drainage with produced water or drilling fluids. In such cases, the deck drainage would have become
subject to the limitations imposed OJQ these wastestreams. EPA also considered requiring facilities to
implement best management practices (BMPs) as part of the deck drainage limitations. For the final rule,
both of these options considered at proposal have been rejected. The commingling of deck drainage with
produced water or drilling fluids is not a demonstrated technology, as discussed below. Promulgating
BMPs in this rule would be redundant to the requirements of the "Final National Pollutant Discharge
Elimination System Storm Water Multi-Sector General Permit for Industrial Activities" (60 FR 50804,
September 29, 1995).
i
With regard to commingling with produced water, the 1993 Coastal Oil and Gas Questionnaire and
facility visits reveal that deck drainage is sometimes commingled with produced waters prior to discharge
or injection. Because of this practice '•, EPA investigated an option at proposal that would require capture
of the "first flush", or most contaminated portion of, deck drainage. Depending on whether the deck
drainage is generated from drilling or production (actual hydrocarbon extraction) operations, this first flush
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would have been subject to the same limitations as would be imposed on either produced water or drilling
fluids and drill cuttings, based on the assumption that these two wastestreams could be commingled.
EPA rejected the first flush option for control of deck drainage for several reasons primarily
relating to whether this option is technically available to operators throughout the coastal subcategory.
Deck drainage is currently captured by drains and flows via gravity to separation tanks below the deck
floor. However, the problems associated with capture and treatment beyond gravity feed, power-
independent, systems are compounded by the potential for back-to-back storms which may cause first flush
overflows from an already full 500 bbl tank. In addition, tanks the size of 500 barrels are too large to be
placed under deck floors. Installation of a 500 bbl tank would require construction of additional platform
space, and the installation of large pumps capable of pumping sudden and sometimes large flows from a
drainage collection system up into the tank. The additional deck space would add significantly, especially
for water-based facilities, to the cost of the first flush option. Further, many coastal facilities are unmanned
and have no power source available to them. Deck drainage can be channeled and treated without power
under the BPT limitations.
Capturing deck drainage at drilling operations poses additional technical difficulties. Drilling
operations on land may involve an area of approximately 350 square feet. A ring levee is typically
excavated around the entire perimeter of a drilling operation to contain contaminated runoff. This ring
levee may have a volume of 6,000 barrels (bbls), sufficient to contain 500 bbls of the first flush. However,
collection of these 500 bbls when 6,000 bbls may be present in the ring levee would not effectively capture
the first flush. Costs to install a separate collection system including pumps and tanks, would add
significantly to the cost of this option.
While costs are significant, the technological difficulties involved with adequately capturing deck
drainage at coastal facilities are the principal reason why the first flush option was not selected for the final
rule.
A requirement to implement BMPs for deck drainage is not included in the coastal guidelines. EPA
believes that current industry practices, in conjunction with the requirements included hi the previously
mentioned general permit for storm water, are sufficient to minimise the introduction of contaminants from
this wastestream to the extent possible. These storm water requirements require an oil and gas operator
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to develop and implement a site-specific storm water pollution prevention plan consisting of a set of BMPs
depending on specific sources of pollutants at each site.
3.4 PRODUCED SAND
EPA is establishing BPT, BGT, BAT and NSPS equal to zero discharge for produced sand. Zero
discharge is established as BPT because it reflects the average of the best existing performance by facilities
in the coastal subcategory. Since BCT is established as equal to BPT, there is no cost of BCT incremental
to BPT. Therefore, this option passes the BCT cost reasonableness tests. EPA has determined that zero
discharge reflects the BAT level of control because, as it is widely practiced throughout the industry, it is
both economically achievable and technologically available.
Based on responses to the 1993 Coastal Oil and Gas Questionnaire and existing NPDES permit
requirements, EPA has determined that there are no discharges of produced sand currently in the coastal
subcategory. Data from the 1993 Coastal Oil and Gas Questionnaire indicate that the predominant disposal
method for produced sand is landfarming, with underground injection, landfilling, and onsite storage also
taking place to some degree. Because of the cost of sand cleaning, in conjunction with the difficulties
associated with cleaning some sand sufficiently to meet existing permit discharge limitations, operators use
onshore (onsite or offsite) or downhole disposal. In fact, only one operator was identified hi the 1993
Coastal Oil and Gas Questionnaire as; discharging produced sand hi the Gulf of Mexico, but this operator
also stated that it planned to cease its discharge hi the near future. In addition, subsequent to this operator's
response, EPA Region 6 issued general permits prohibiting discharges of produced sand in coastal waters
of Louisiana and Texas (60 FR 2387; January 9, 1995). Cook Inlet operators submitted information
stating that no produced sand discharges are occurring in this area (see Chapter IX). No comments on the
proposed guidelines contained contrary information.
Because current practice for the coastal subcategory is zero discharge, allowing the discharge of
produced sand would not represent BAT level control. As stated above, EPA's identified only one
discharger of produced sand in the coastal subcategory and that discharger reported an intent to cease
discharging. Because the industry practice of zero discharge is already so widespread and based on data
from the 1993 Coastal Oil and Gas Questionnaire (showing that only one operator was discharging
produced sand, and those discharges have since been prohibited by the Region 6 permits), EPA determined
that the zero discharge limitation for produced sand will result hi minimal, if any, increased cost to the
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industry because zero discharge generally represents current practice. Non-water quality environmental
impacts from the zero discharge limitation, if any, will be negligible.
EPA is also establishing PSES and PSNS which require zero discharge of produced sand. EPA
has determined that, similar to drilling wastes, the high solids content of produced sand would likely cause
obstruction to the flow in the POTW resulting in interference with POTW operations. Because EPA is not
aware of any coastal operators discharging produced sand to POTWs, this requirement is not expected to
result in operators incurring costs. Zero discharge for PSNS would not cause a barrier to entry. There
are no additional non-water quality environmental impacts associated with this requirement because it
reflects current practice.
3.5 DOMESTIC WASTES
The conventional pollutant of concern in domestic waste is floating solids. The existing BPT
limitations for domestic wastes prohibit discharges of floating soEds. To comply with this limit, operators
grind the waste prior to discharge. As proposed, EPA is establishing BCT and NSPS limitations which
prohibit the discharge of floating solids. BCT and NSPS also include discharge limitations for garbage as
included in U.S. Coast Guard regulations at 33 CFR Part 151. These regulations implement Annex V of
the Convention to Prevent Pollution from Ships (MARPOL) and the Act to Prevent Pollution from Ships,
33, U.S.C. 1901 et seq. (The definition of "garbage" is included in 33 CFR 151.05). In addition, EPA
is establishing BAT and NSPS limitations which prohibit discharges of foam. Foam is a nonconventional
pollutant and its limitation is intended to control discharges that include detergents.
The pollutant limitations described above for domestic wastes are all technologically available and
economically achievable and reflect the BCT, BAT and NSPS levels of control. These limitations are
technologically available. Existing BPT requirements already prohibit discharges of floating solids.
Existing permit requirements for Cook Inlet facilities prohibit discharges of visible foam. In addition, the
availability of controls to prevent discharges of foam are demonstrated by the existing BAT limitations
(which prohibit the discharge of foam) for the offshore subcategory. Under regulations issued by the U.S.
Coast Guard, discharges of garbage, including plastics, from vessels and fixed and floating platforms
engaged in the exploration, exploitation and associated offshore processing of seabed mineral resources
are prohibited with one exception. Victual waste (not including plastics) may be discharged from fixed or
floating platforms located beyond 12 nautical miles from nearest land, if such waste is passed through a
screen with openings no greater than 25 millimeters in diameter. Because vessels and fixed and floating
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platforms must comply with these limits, EPA believes that all coastal facilities are able to comply with this
limit. While not all coastal facilities are located on platforms, compliance with a no garbage standard
should be as achievable, if not more so, for shallow water or land based facilities that have access to
garbage collection services. Further, the final drilling permits issued by Region 6 for coastal Texas and
Louisiana incorporates these Coast Guard regulations (58 FR 49126; September 21, 1993).
Because they represent current practice, the BCT, BAT and NSPS limitations result in no
incremental costs or non-water quality environmental impacts. There are no incremental costs associated
with the BCT limitations; therefore, they pass the BCT cost reasonableness tests. Pretreatment standards
are not being developed for domestic wastes because domestic wastes are compatible with POTWs.
POTWs typically receive these types of wastes from industrial and domestic users.
3.6 SANITARY WASTES
EPA is establishing BCT and NSPS as equal to BPT limits for sanitary waste discharges. Sanitary
waste effluents from facilities continuously manned by ten (10) or more persons must contain a minimum
residual chlorine content of 1 mg/1, with, the chlorine level maintained as close to this concentration as
possible. Coastal facilities continuously manned by nine or fewer persons or only intermittently manned
by any number of persons must comply with a prohibition on the discharge of floating solids. Since there
are no increased control requirements beyond those already required by BPT effluent guidelines, there are
no incremental compliance costs or non-water quality environmental impacts associated with BCT and
NSPS limitations for sanitary wastes. Since there are no incremental costs associated with the BCT limit,
it passes the BCT cost tests.
EPA considered zero discharge of sanitary wastes based on off-site disposal to municipal treatment
facilities or injection with other oil and gas wastes. Off-site disposal would require pump out operations
that, while available to certain land facilities, are not easily available to remote or water-based operations.
Because sanitary wastes are not accepted for injection into Class II wells, zero discharge based on Class
n injection was rejected for sanitary wastes.
EPA is not establishing BAT effluent limitations for the sanitary waste stream because no toxic or
nonconventional pollutants of concern have been identified in these wastes. Pretreatment standards are not
being developed for sanitary wastes because they are compatible with POTWs. POTWs typically receive
these types of wastes from industrial and domestic users.
XTV-27
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4.0 REFERENCES
1. U.S. EPA, "Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards for
the Coastal Subcategory of me Oil and Gas Extraction Point Source Category," October 31,1996.
2. SAIC, "Oil and Gas Exploration Wastes Handling Methods in Coastal Alaska," January 6, 1995.
3. Alaska Oil and Gas Association, "Alaska Oil and Gas Association Comments on U.S.
Environmental Protection Agency 40 CER Part 435 Effluent Limitation Guidelines, Pretreatment
Standards, and New Source Performance Standards; Oil and Gas Extraction Point Source
Category, Coastal Subcategory; Proposed Rule," June 1995.
4. Unocal and Marathon Oil Co., "Drilling Waste Disposal Alternatives - A Cook Inlet Perspective,"
March 1994.
5. Avanti, "Compliance Costs and Pollutant Removals for Drilling Fluids and Drill Cuttings,"
September 16,1996.
6. Mason, T., Avanti, Memorandum to Ron Jordan, U.S. EPA, regarding "Navigation and Weather
Conditions in Cook Met," September 16,1996.
7. Avanti, "Non-Water Quality Environmental Impacts for Drilling Wastes and Produced Water to
Cook Met, Alaska," September 20,1996.
8. Jordan, R. P., U.S. EPA, "Record of Telephone Conversation with County Sanitation Districts
of Los Angeles," June 14,1996.
XIV-28
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CHAPTER XV
BEST MANAGEMENT PRACTICES
Section 304(e) of the Clean Water Act authorizes the Administrator to prescribe best management
practices (BMPs) to control "plant site runoff, spillage or leaks, sludge or waste disposal, and drainage
from raw material storage." Section 402(a)(l) and NPDES regulation (40 CFR 122) also provide for best
management practices to control or abate the discharge of pollutants when numeric effluent limitations
are infeasible.
The coastal guidelines do not establish "best management practices" (BMPs). EPA believes that
current industry practices, in conjunction with the requirements included in the stonnwater regulations
(60 PR 50803, September 29, 1995); are sufficient to minimize the introduction of contaminants to this
wastestream to the extent possible and that additional regulations would be duplicative and unnecessary.
Although BMPs are not required by: this rule, EPA identified several BMPs applicable to this industry.
Good operation and maintenance practices reduce waste flows and improve treatment efficiencies,
as well as reduce the frequency and magnitude of system upsets. Some examples of good coastal facility
operation are:
1. Separation of used motor oil from deck drainage collection systems.
2. Minimization of wastewater treatment system upsets by the controlled usage of deck washdown
detergents. ;
3. Reduction of oil spillage through the use of good prevention techniques such as drip pans and other
handling and collection methods.
4. Segregation of deck drainage from oil leaks from pump bearings and seals by directing the leakage
to the crude oil processing system.
5. If oil is used as a spotting fluid, careful attention to the operation of the drilling fluid system could
result in the segregation from the main drilling fluid system of the spotting fluid and contaminated
drilling fluid. Once segregated, the contaminated drilling fluid can be disposed of in an
environmentally acceptable manner.
XV-1
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6. Substitution of standard drill pipe threading compound (pipe dope) with "toxic metals free" pipe
dope. Standard pipe dope can contribute high amounts of lead and other metals to discharged
drilling fluids and cuttings.
7. Careful application of standard drill pipe dope to minimize contamination of receiving water and
drilling fluids.
8. Substitution of diesel oil with less toxic mineral oil or synthetic-based material in drilling fluid
applications.
9. Substitution of standard drilling fluid additives with less toxic additives.
10. Segregation of contaminated process area deck drainage and runoff from relatively uncontamhiated
runoff from areas such as parking areas, office space, walkways, and living quarters.
11. Segregated handling, storage and disposal of contaminated drilling waste from less contaminated
waste.
12. Installation of roofs and sheds to divert uncontaminated rainfall from areas with a high potential
for generating contaminated runoff.
13. Segregation of existing roof drains from contaminated deck drainage sources.
14. Careful handling of drilling fluid materials and treatment chemicals to prevent spills.
15. Use of local containment devices such as liners, dikes and drip pans where chemicals are being
unpackaged and where wastes are being stored and transferred.
16. Install treatment devices for deck drainage to reduce or remove pollutants in the discharges (e.g.,
skim tanks, oil/water separators, sediment tanks/basins, or detention ponds).
Careful planning, good engineering, and a commitment on the part of the operating, maintenance,
and management personnel are needed to ensure that the full benefits of all pollution reduction facilities
are realized.
XV-2
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GLOSSARY AND ABBREVIATIONS
Acidizing/Fracturing Fluids: Fluids used to
induce formation fracturing, which is a
method of stimulating production by opening
new flow channels hi the rock surrounding a
production well. Often called a frac job.
Under extremely high hydraulic pressure, a
fluid (such as distillate, diesel fuel, crude oil,
dilute hydrochloric acid, water, or kerosene)
is pumped downward through production
tubing or drill pipe and forced out below a
packer or between two packers. :The pressure
causes cracks to open in the formation, and
the fluid penetrates the formation through the
cracks. Sand grains, aluminum pellets, walnut
shells, or similar materials (propping agents)
are carried in suspension by the fluid into the
cracks. When the pressure is released at the
surface, the fracturing fluid returns to the
well. The cracks partially close on the pellets,
leaving channels for oil to flow.around them
to the well.
Act: The Clean Water Act.
ADEC: Alaska Department of Environmental
Conservation.
Agency: The U.S. Environmental Protection
Agency.
Annular Injection: Injection of fluids into the
space between the drill string or production
tubing and the open hole or well casing.
Annulus or Annular Space: The space be-
tween the drill string or casing and the wall of
the hole or casing.
AOGA: Alaskan Oil and Gas Association.
API: American Petroleum Institute.
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 economic-
ally achievable, under Section 304(b)(2)(B)
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 com-
parable volume basis. 1 BOE = 42 gallons of
diesel and 1,000 scf of natural gas = 0.178
BOE.
bpd: Barrels per day.
BPJ: Best Professional Judgment.
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.
G-1
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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 con-
tinues 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.
OBI: Confidential Business Information.
Centrifuge: Filtration equipment that uses cen-
trifugal force to separate substances of varying
densities. A centrifuge is capable of spinning
substances at high speeds to obtain high cen-
trifugal forces. Also called the shake-out or
grind-out machine.
cfd: cubic feet per day
Clean Water Act: 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^).
CO: Carbon Monoxide.
Coastal Oil and Gas Questionnaire: U.S.
EPA, "Coastal Oil and Gas Questionnaire,''
OMB No. 2040-0160, My 1993.
Completion: Activities undertaken to finish
work on a well and bring it to productive
status.
Completion Fluids: Low-solids fluids or dril-
ling muds used when a well is being comple-
ted. They are selected not only for their abili-
ty to control formation pressure, but also for
the properties that minimize formation
damage. Salt solutions, weighted brines,
polymers, and various additives are used to
prevent damage to the well bore during opera-
tions which prepare the drilled well for pro-
duction.
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 distin-
guished from migratory waters that have
flowed into deposits after they were laid
down.
Deck Drainage: All wastes resulting from plat-
form washings, deck washings, spills, rain-
water, and runoff from curbs, gutters, and
drains, including drip pans and wash areas.
Depth Interval: Interval at which a drilling fluid
system is introduced and used, such as from
2,200 to 2,800 ft.
Development Facility: Any fixed or mobile
structure addressed by this document that is
engaged in the drilling of potentially
productive wells.
Dewatering Effluent: The wastewater derived
from dewatering drill cuttings.
Diesel Oil: The grade of distillate fuel oil, as
specified in the American Society for Testing
and Materials' Standard Specification D975-
81.
Disposal Well: A well through which water
(usually salt water) is returned to subsurface
formations.
Domestic Waste: Materials discharged from
sinks, showers, laundries, and galleys located
within facilities addressed by Ms document.
Included with these wastes are safety shower
and eye wash stations, hand wash stations, and
fish cleaning stations.
DMR: Discharge Monitoring Report.
G-2
-------
Drill Cuttings: Particles generated by drilling
into subsurface geologic formations and
carried to the surface with the drilling fluid.
i
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 con-
dition the hole and to counterbalance forma-
tion 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 pre-
sent. 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 pri-
marily of mud storage tanks or pits, mud
pumps, stand pipe, kelly hose4 kelly, drill
string, weE annulus, mud return ftowline, 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. '
Emulsion: A stable heterogenous mixture of two
or more liquids (which are not normally dis-
solved 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 j oil-in-water,
or water-in-oil.
ENR-CCI: Engineering News Record-Construc-
tion Indices.
EPA (or U.S. EPA): U.S. Environmental Pro-
tection Agency. ;
Exploratory Well: A well drilled either in
search of an as-yet-undiscovered pool of oU or
gas (a wildcat well) or to extend greatly the
limits of a known pool. It involves a relative-
ly high degree of risk. Exploratory wells may
be classified as (1) wildcat, drilled in an un-
proven 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/Treat-
ment Facility.
Field: A geographical area in which a number of
oil or gas wells produce hydrocarbons from an
underground reservoir. A field may refer to
surface area only or to underground produc-
tive formations as well. A single field may
have several separate reservoirs at varying
depths.
Filter Backwash: Wastewater generated when
filters are cleaned and maintained.
Filter Sludge: Solids removed via filtration.
Filtration: The process of removing the solids
from a fluid. Filtration can be used on both
produced water or workover/completion
fluids.
Flocculation: The combination or aggregation
of suspended solid particles in such a way that
they form small clumps or tufts resembling
wool.
Flotation: Process by which water that is slight-
ly oil contaminated is circulated to be cleaned
before it is disposed. Since oil droplets cling
to rapidly rising gas, a device such as a bubble
tower is usually installed in the flotation cell to
permit the introduction of gas into the water.
Fluid Injection: Injection of gases or liquids
into a reservoir to force oil toward and into
producing wells. (See also "Water Flooding"
and "Pressure Maintenance.")
G-3
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Footprint: The square footage covered by
various production equipment.
Formation: Various subsurface geological strata.
Formation Damage: Damage to the producti-
vity of a well resulting from invasion of dril-
ling fluid particles or other substances into the
formation.
Fracturing: A method of stimulating production
by opening new flow channels in the rock sur-
rounding a production well. Often called a
fracjob. See "Acidizing/Fracturing Fluids."
Free Water Knockout (FWKO): A vertical or
horizontal vessel into which oil or emulsion is
run to allow any water not emulsified with the
oil (free water) to drop out.
Gas Lift: A means of stimulating flow by aerat-
ing a fluid column with compressed gas.
GOM: Gulf of Mexico.
gph: Gallons per hour.
gpm: Gallons per minute.
hp: Horsepower.
IGF: Improved operating performance of gas
flotation.
Injection Well: A well through which fluids are
injected into an underground stratum to in-
crease reservoir pressure and to displace oil,
or for disposal of produced water and other
wastes.
kW: Kilowatt.
96-hr LCSO: The concentration of a test material
that is lethal to 50% of the test organisms hi a
bioassay after 96 hours of constant exposure.
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 ex-
ploit the premises for minerals; the instrument
that creates a leasehold or working interest hi
minerals.
m: Meters.
Major Pass Facilities: Those oil and gas facili-
ties discharging offshore subcategory pro-
duced water into major deltaic passes of the
Mississippi River below Venice or to the
Atchafalaya River below Morgan City inclu-
ding Wax Lake Outlet.
mcf: Thousand cubic feet.
ug/l: Micrograms per liter.
mg/l: Milligrams per liter.
MMcfd: Million cubic feet per day.
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.
Multiple Completion: A well completion which
provides for simultaneous production from
separate zones.
NOX: Nitrogen Oxide.
NPDES: National Pollutant Discharge Elimina-
tion System.
NPDES Permit: A National Pollutant Discharge
Elimination System permit issued under
Section 402 of the Act.
G-4
-------
NSPS: New source performance standards under
Section 306 of the Act. '
NWQI: Non-water quality environmental impact.
O&M: Operating and maintenance.,
Oil/Water Separation Facilities: See "Pro-
duced Water Separation/Treatment Facilities."
Oil-based Drilling Fluid: A drilling fluid in
which oil is the continuous phase.
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. j
Onshore Subcategory: Those facilities as
defined in 40 CFR 435.30.
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 mataialning
accurate records of the amount bf oU or gas
sold, and for reporting production information
to state authorities. ;
POTW; Publicly Owned TreatmenfWorks.
Pressure Maintenance: The injection of water
or gas into an oil or gas producing formation
to maintain the desired formation pressure.
Priority Pollutants: The toxic pollutants listed
in 40 CFR Part 423, Appendix A.
Produced Sand: Slurried particles used in
hydraulic fracturing and the accumulated for-
mation 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 "faculty" is any group of
tanks, pits, or other apparatus mat can be dis-
tinguished 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 bat-
tery, an off-site gathering center, or a com-
mercial 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.
psi: pounds per square inch.
psig: pounds per square inch gauge.
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.
G-5
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Reserve Pit: A waste pit, usually an excavated
earthen-walled pit. It may be lined with plas-
tic or other material to prevent soil contamina-
tion.
Reserve Pit Liquids: Liquids surfacing to the
top of reserve pits after settling of solids; can
also include rain water, rig wash water, etc.
Reservoir: Each separate, unconnected body of
a producing formation.
Rotary Drilling: The method of drilling wells
that depends on the rotation of a column of
drill pipe with a bit at the bottom. A fluid is
circulated to remove the cuttings.
RRC: Railroad Commission of Texas.
Sanitary Waste: Human body waste discharged
from toilets and urinals located within facili-
ties addressed by this document.
soft standard cubic feet.
Secondary Recovery: The use of waterflood-
ing or gas injection to maintain formation
pressure during primary production and to re-
duce the rate of decline of the original reser-
voir drive.
Settling or Skim Pit or Tank: A pit or tank
into which produced emulsion is piped and in
which water in the emulsion is allowed to
settle out of the oil. Oil can be skimmed off
the top.
Shut In: To close valves on a well so that it stops
producing; said of a well on which the valves
are closed.
SO2: Sulfur Dioxide.
Source Water: The term used for subsurface
waters produced from non-hydrocarbon bear-
ing formations for waterflooding purposes.
Tank Battery: A group of production tanks
located in a field to store crude oil.
TBPF: Trading Bay Production Facility.
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.
Treatment Fluids: Any fluid used to restore or
improve productivity by chemically or
physically altering hydrocarbon-bearing strata
after a well has been drilled. Well treatment
fluids include substances such as acids, sol-
vents, and propping agents. (See "Acidizing/
Fracturing Fluids.")
TSP: Total suspended particulates.
TSS: Total Suspended Solids.
TWC: Treatment, workover, and completion.
UIC; Underground Injection Control.
Upland Site: A site not located in a wetland
area. May be an onshore site or a coastal site
under the Chapman Line definition,
USCG: United States Coast Guard.
USDW: Underground Sources of Drinking Water.
USGS: United States Geological Survey.
Water-based Drilling Fluid: A drilling fluid in
which the continuous phase is water. In
water-based fluids, any additives are dispersed
in the water.
Waterflooding: Water is injected under pressure
into the formation via injection wells to main-
G-6
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tain reservoir pressure and to displaced oil to- Workover Fluid: Salt solutions, weighted
ward ttoe producing wells. ; brines, polymers, or other specialty additives
: used in a producing well to allow safe repair
Workover: The performance of one or more of and maintenance or abandonment procedures.
a variety of remedial operations on a produc- A workover fluid is compounded carefully so
ing oUwell to try to increase production. that it will not cause formation damage.
Examples of workover jobs are deepening,
plugging back, pulling and resetting liners,
and squeeze cementing. |
G-7
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APPENDIX VIM
DRILLING FLUID COMPONENTS
AND APPLICATIONS
A-l
-------
Drilling Fluid Components and Applications
(Chilingarian and Vorabutr, 1983)
Drilling Fluid
Component
Weighting Agents and Viscosifiers
Dispersants
Fluid-Loss Reducers
— "'.'-.t^ ".*'•* ft^— . •• Z&," "
^ Description or Principal;.
.. ;V V-fj; Component' - s, ?<*«•?•<
Barite
Calcium Carbonate
Bentonite
Sub-Bentonite
Attapulgite
Beneficiated Bentonite
Asbestos Fibers
Bacterially Produced Polymer
Sepiolite
Sodium Tetraphosphate
Sodium Acid Pyrophosphate
Quebracho Compound
Modified Tannin
Processed Lignite
Causticized Lignite
Modified Lignosulfonate
Blended Lignosulfonate
Compound
Chrome-Free Lignosulfonate
Organic-Polymer
Pregelatinized Starch
Sodium Carboxymethyl
Cellulose •
Sodium Carboxymethyl
Cellulose
Polyanionic Cellulosic Polymer
Polyanionic Cellulosic Polymer
Sodium Polyacrylate
> '> : \ VtifeHf** "' \
' ! ' Application " ' ' '
For increasing mud weight up to 20 ppg.
For increasing weight of oil muds up to 10.8 ppg.
Viscosity and filtration control in water-base muds.
For use when larger particle size is desired for viscosity and
filtration control.
Viscosifier in saltwater muds.
Quick viscosity in fresh-water, upperhole muds with minimum
chemical treatment.
Viscosifier for fresh-water or saltwater muds.
Viscosifier and fluid-loss control additive for low-solids muds.
Viscosifier in all water-based muds, especially high-
temperature drilling fluids.
Thinner for low pH fresh-water muds where temperatures do
not exceed 180°.
For treating cement contamination.
Thinner for fresh-water and lime muds.
Thinner for fresh-water and saltwater muds alkalized for pH
control.
Dispersant, emulsifier and supplementary additive for fluid-loss
control.
1-6 ratio caustic-lignite dispersant, emulsifier and
supplementary fluid-loss additive.
Dispersant and fluid-loss control additive for water-base muds.
Blended multi-purpose dispersant, fluid-loss agent and inhibitor
for IMCO RD-111 mud systems.
Dispersant and fluid-loss control additive for water base muds.
Controls fluid loss in water-base systems.
Controls fluid loss in saturate salt water, lime and SCR muds.
For fluid-loss control and barite suspension in water-base
muds.
For fluid-loss control and viscosity building in low-solids
muds.
Fluid-loss control additive and Viscosifier in salt muds.
Primary fluid-loss additive, secondary Viscosifier in water-base
muds.
Fluid-loss control in calcium-free low solids and nondispersed
muds.
A-2
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Drilling Fluid Components and Applications (cont.)
(ChUingarian and Vorabutr, 1983)
* ^rillitt£ffiltti4
-' / "' •• OompDirent s ;
Lubricants, Detergents,
Emulsifiers, Surfactants
Defoamers, Flocculants,
Bactencides
Lost Circulation Materials
' , •• Description: ortPriiiCiilal' '
s, , •• '•. Component /•••• "~>s s
Extreme Pressure Lubricant
Processed Hydrocarbons
Water Dispersible Asphalts
Oil Dispersible Asphalts
Oil Soluble Surfactants
Detergent
Blend of Anionic Surfactants
An Organic Entity Neutralized
with Amines
Blend of Fatty Acids,
Sulfonates, and Asphaltic
Materials
Aluminum Stearate
Liquid Surface-Active Agent
Surface-Active Dispersible
Liquid Defoamer
Flocculating Agent
Blended Solutions
Fibrous, Material
Nut Shells: Fine
Nut Shells: Medium
Nut Shells: Coarse
Ground Mica: Fine
Ground Mica: Coarse
Cellophane
Combination of granules, flakes,
and fibrous materials of various
sizes in :one sack.
' " 't '"' ,7*"ia*'y '* "s /
'I "" \ ' "' 'Application - ; ;
Used in water-base muds to impart extreme pressure lubricity.
Used in water-based muds to lower downhole fluid loss and
minimize heaving shale.
Lubricant and fluid-loss reducer for water-base muds that
contain no diesel or crude oil.
Lubricant and fluid-loss reducer for water-base fluids that
contain diesel or crude oil.
Nonweighted fluid for spotting to free differentially stuck pipe.
Used in water-base muds to aid in dropping sand. Emulsifies
oil, reduces torque and minimizes bit-bailing.
Emulsifier for saltwater and freshwater muds.
Supplies the lubricating properties of oils without
environmental pollution.
Invert emulsion that may be weighted to desired density for
spotting to free differentially stuck pipe.
Defoamer for lignosulfonate muds.
Defoamer for all water-base muds.
All-purpose defoamer.
Used to drop drilled solids where clear water is desirable for a
drilling fluid.
Bactericide used to prevent fermentation.
Filler as well as matting material.
Most often used to prevent lost circulation.
Used in conjunction with fibers or flakes to regain lost
circulation.
Used where large crevices or fractures are encountered.
Used for prevention of lost circulation.
Forms a good mat at face of wellbore.
Used to regain lost circulation.
Used where large crevices or fractures are encountered.
A-3
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Drilling Fluid Components and Applications (cont)
(Chilingarian and Vorabutr, 1983)
Drilling Fluid
Component
Corrosion Inhibitors
Specialty Products
Commercial Chemicals
Oil-Mud Additives
%.0eScr8rti<»H' drT^nHCtpaf "°^
\ y f '*•'*•' hvft" •&> iX- >* vh > V*
« «& Pflgpontt* ^ .*' „
Zinc Compound
Liquid Corrosion Inhibitor
A Catalyzed Ammonium
Bisulfite
Filming Amine
Fikning Amine
Organic Polymer
Bentonite Extender
Inhibiting Agent
Synergistic Polymer Blend
Biodegradable Surfactant
High-Temperature Polymer
Multipurpose Polymer
Sodium Chromate
Sodium Hydroxide
Sodium Carbonate
Sodium Bicarbonate
Barium Carbonate
Calcium Sulfate
Calcium Hydroxide
Sodium Chloride
Chrome Alum (chromic
chloride)
Primary Emulsifier
Viscosifier and Gelling Agent
High-Temperature Stabilizer
Stabilizes Borehole Conditions
Dispersant
Calcium Oxide
Fatty Acid Emulsifier
•.,•• V^v ••;* S"r ' ' \ ^ n'f "•' «t*>* '. "•' V ",-AS ' f.
<•.- t '?, •", f & ,., ^nmajy * *',<<•. ; -;-
:>;;y-^^5 , to&tf*a\*,* * :*^ '";.
For use as a hydrogen sulfide scavenger in water-base and oil-
base muds.
Prevent stress cracking of drill strings in an H2S environment.
For use as an oxygen scavenger.
Corrosion inhibitor.
Corrosion inhibitor.
Scale inhibitor.
Increases yield of bentonite to form very low-solids drilling
fluid
Imparts high-temperature fluid-loss control, temperature
stability and increased inhibition.
Rheological stabilization and filtration control.
Foaming agent in air or mist drilling.
High-temperature fluid-loss control.
Polymer for fluid-loss control.
Used in water-base muds to prevent high-temperature gelation.
For pH control in water-base muds.
For treating out calcium sulfate in low pH muds.
For treating out calcium sulfate or cement in high pH muds.
For treating out calcium sulfate (pH should be above 10 for
best results).
Source of calcium for formulating gyp muds.
Source of calcium for formulating lime muds.
For saturated salt muds and resistivity control.
For use in cross-linking XC Polymer systems.
Primary additives to form stable water-in-oil emulsion.
Provides viscosity, weight suspension, and filtration control.
Improves emulsion under high-temperature conditions.
Stabilizes running shale, improves emulsion, weight
suspension, and fluid loss under high-temperature conditions.
Dispersant for reducing rheological properties.
Calcium source for saponification.
Primary emulsifier and stabilizer for oil-base drilling fluids.
A-4
-------
Drilling fluid Components and Applications (cont.)
(Chilingarian and Vorabutr, 1983)
•• '- ^ V i '^i"
Drilling Jiuid , ..
" ' "' Component
Oil Mud Additives
(cont.)
Description or Principal .•
Component
Emulsion Stabilizer
Specially Modified Saponified
Fatty Acid Chemicals
Powdered Wetting Agent
* - ~ ,,;
Primary ~
, , -,„ -- Application ' T
Imparts gels, contributes to viscosity for weight suspension,
and provides filtration control.
Gelling agent for formulating high-gelation casing packs.
Dispersing agent in KEN-X systems with a CaCl2 water
internal phase.
A-5
-------
APPENDIX X-l
WORKSHEETS FOR COOK INLET MODEL WELL AND
FOUR DRILLING WASTE MANAGEMENT SCENARIOS
A-6
-------
Worksheet No. 1, April 30, 1996, Page 1 of 2
Coastal Alaska Oil and Gas Drilling Industry
Zero Discharge Compliance Cost Analysis for Operations in Cook Inlet, Alaska
Cost Estimation for Drilling an Average Injection Weil
A
A
A
B
B
B
B
1A
2A
3A
IB
28
33
4B
1,3
1,256
1,155
3,110
4,130
4,017
3,823
8,477
8,368
8,642
7,999
3,962
8,745
6,240
2,029
2,176
2,343
860
1,478
2,068
2,100
11395
11300
12,140
10,989
11,580
11,830
12,163
9
3
5
23
NA
12
" 15
6
13
9
23
NA
12
' '12' ~
21
32
27
30
30
17
20~
wwwwMwKWvHM;
14
12
13
23
12
12
12
wm
20
20
47
13
12
12
17
mm
11
8
9
23
12
12
"12"
1,528
1,813
1,381
3,313
NA
6,065
7,504
9,325 2,232
8,081 2,101
10,180 2,780
7,334 1,334
9,558 1,583
7,606 2,828
8,838 3,024
13,085
11,395
14,300
11,981
NA
15,997
19,366
>w •SS?-K:i&**^"S~^^¥~:kS^W'^K^':'i^
If
<* A 1A 54 294 220 588 3,567 6,280 339.104
A 2A 39 384 160 583 3,457 5,930 231,266
A 3A 45 351 423 819 4,610 6,628 253,269
B 1B 529 690 299 1,518 4,078 2,687 1,421,229
B 2B NA 380 144 NA 6,722 NA NA
B 3B 144 204 144 492 5,120 10,408 1,498,489
B 4B 180 240 204 624 5,935 9,512 1,712,100
1,846,235 1,381,536
2,277,077 948,782
1,975,500 2,380,731
1,863,777 803,303
NA NA
2,122,859 1,498,489
2,282,800 1,940,380
244
184
219
674
NA
373
448
218
272
229
232
NA
370
366
681
436
1,016
934
NA
72B
924
1.1
1.0
1.2
1.6
NA
1.5
2.0
1.1
1.0
1.2
0.9
1,6
1,3
1.4
1.;
•u
1.!
1.1
1.-
Average Cost of Drilling a 4000 Foot Injection Well =
(Sum of the costs of drilling the first 2,500 feet using the average cost of first drilling fluid system, DFS-01,
and the cost of drilling the last 1,500 feet using the average cost of the second drilling fluid system, DPS -02,
(2,500 x Column 27) + (1,600 x Column 28))
Average Muds and Cuttings Generated from Drilling a 4000 Foot Injection Well (BBLS) =
(Sum of the muds and cuttings (M&C) generated from drilling tha first 2,500 feet of well, using the average unit volume M&C of DFS-01,
and M&C generated from drilling the tost 1,500 feet of the well, using the average unit volume M&C of DFS-02,
(2,500 x Column 80) + (1,500 x Column 31))
Average Number erf Days for Drilling an Average New Wall =
(Sum of the average number of days for each dried interval)
(Column 7 H-Column 9 *Golumn 113
Average Number of Days for Recompleting a Well -
(Set equal to the average number of days spent drilling the third drilled interval of new wells, Column 11)
I $1,313.8971
5.2751
57
Jo]
-------
Worksheet No. 1, April 30, 1996, page 2 of 2
Coastal Alaska Oil and Gas Drilling Industry
Zero Discharge Compliance Cost Analysis for Operations in Cook Inlet, Alaska
Cost Estimation for Drilling an Average Injection Well
(1) Operator ID» are confidential, and uro therefore discussed In n confidential supporting document (Mclntyn, 1988).
(2) Well IDs are confidential, and a>« therefore dtecutsad In a confidential supporting documont (Molntyre, 1890),
(3), (4),arnl(5) Tfcadepth of each driilhs fluid system(DPS) waft oWalisd from the SQiQuesBonnsfre.
(5) The final depth to which the wall was drilled b Ins sum of all drilled Intervals. Column 3 + Column 4 + Column i,
(7), (8), (9), (10), (11), and (12) Oiling Hmt for each drilling Interval was obtained from 308 Quostlonnares.
(13), (14), and (15) Muds and Cuttings (M&C) Volumes are as specified In the 308 Questionnaires a calculated from the reported total volume by
weighted average based on the depth of each Interval.
(1e) Total muds and cuttings genaatedtom each well are as reported In the 308 Questtennatas or me the sum of muds and eutthgsfrom an drilled Intervals,
(17) Average percent of total volume of drilling waste as cuttings was calculated by averaging reported percentages for each drilled interval In the 308 Questionnaires.
Only one faclHtyreparted cuttings fractions,
(1 a) Total hours of drilling the first Interval la the product of total number of drilling days and average number of drilling hows In a day. Column 7 x Column 8.
^ (19) Total hours of drilling the second interval is the product of total number of drilling days and average number of drilling hours In a day. Column 6 x Column 10.
do
(20} Total hours of drilling the Ihtd Interval Is the product of total number of drilling days and average number of drilling hours In a day. Column 11 x Column 12,
(21) Total drilling hours Is the sum of total drilling hours for each drilling Interval, Column 18 * Column 13 +Column 20,
(22) Total drilling costs were obtained from the 398 Questionnaires.
(23) The average hourly drilling cost for each well to calculated by dividing the total cost of drilling by the number of hours spent to drill the well, Column 22/Column21.
(24) Cost of drilling the first Interval Is calculated by multiplying the average hourly drilling cost rate for the entce well by the total hours spent drilling the first interval, Column 23 x Column 1 a.
(25) Cost of drilling the second interval Is calculated by multiplying the average hourly drilling cost rate for the entre wall by the total hours spent drilling the second interval, Column 23 x Column 1S,
(26) Cost of drilling the third interval Is calculated by multiplying the average hourly drilling cost rate for the entre well by the total hours spent drilling the third interval, Column 23 x Column 20.
(27) The cost of drilling per unit depth of the ffrst Interval Is calculated by dividing the total cost of drilling the Interval by total depth of the interval, Column24/Column 3.
(29) The cost of drilling per unit depth of the second interval Is calculated by dividing the total cost of drilling the interval by total depth of the Interval, Column25/Column 4.
(29) The cost of drilling per unit depth of the thrd interval is calculated by dividing the total cost of drilling the interval by total depth of the Interval, ColumnZe/Column 8.
(30) The unit muds and cuttings generated per foot of the first drilled interval is calculated bv dividing the total volume of muds and cuttings for the interval by the total depth of the interval, Column 14/Corumn 3,
(31) The unit muds and cutthgs generated per foot of the second drilled Interval b calculated by dividing the total volume of muds and cutthgs for the interval by the total depth of the Merval, Column 15/Column 4.
(32) The unit muds and cuttings generated per foot of the third dried Interval Is calculated by dividing the total volume of muds and cuttings for the Interval by the total depth of the interval, Column 1 a/Column 5.
NA Data not available or not applicable.
Note: A 400e-foot Injection well Is assumed Based on information provhted by Operator B (Mclntyre, 1998).
-------
Worksheet No. 2, May 17, 1996, Page 1 of 2
Coastal Alaska Oil and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators in Cook Inlet, Alaska
Zero D,Scharge Opt,on by Landfill Disposal (Without Closed-Loop System)
, n081 of Drilling Wastes for A» Operator .
al Costs lot All Operators, Column 1 1)
«3s Total Disposal Cost Per Barrel of Drilling Waste =
{Total Disposal OMtflMtf Vohime * D«h, Wastes, o.to wi 1 aCo.unm 8,
Total Msposal Cost of Drilling Wastes Per Platform =
(bM Dlspoaal CoaVrotal HuBlb.
wttp Drtlllnfl, o.*,
$229.S5g
-------
Worksheet No. 2, May 17,1996, Page 2 of 2
Coastal Alaska OH and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators in Cook Inlet, Alaska
Zero Discharge Option by Landfill Disposal (Without Closed-Loop System)
(1) Operator IDs are confidential, and are therefore discussed In a confidential supporting document (Mclntyre, 1996).
(2), (3), (4), and (6) Some of the data In these columns are confidential, and are therefore discussed in a confidential supporting document (Mclntyre, 1996),
(6) Total Incremental Volume of Drilling Waste from new welli Is the product of Iho Average Volume of drilling waste generated from wells recently drilled in Cook Mat, the Total Number of Wells
scheduled for drilling and Percent of total (99%) d rilling waste discharged under current practice. Based on data provided In 1993 Coastal Oil & Gas 308 Survey
Questionnaires, See Worksheet No. 1 tor details.
(7) Total Incremental Volume of Drilling Waste from racompleted wells Is the Product of the Average Volume of drilling waste generated from the third drilled interval of wells recently drilled in
Cook Intel and the total number of wells scheduled for reoomplefon In Cook Inlet and percent of total (89%) drilling waste discharged under current practice,
Based on Information provided In 1993 Coastal Oil & Gas Industry Survey Questionnaires, See Worksheet No. 1 for details.
(8) Total Incremental Volume of Drilling Waste from all wells Is the sum of all Incremental wastes that will be generated in Cook Inlet, Column 5 +• Column 6.
(9) Unit disposal costs for landfill disposal of muds and cuttings generated In Cook Inlet. Data were estimated from Information provided by Cook Inlet operators. Also see Appendix B.
(10) Total Disposal Cost lor new drilling is the product of Unit Disposal Cost and Total Volume of Drilling Waste from drilling new wells, Column (9) x Column (6).
(11) Total Disposal Cost lor recotnpletlons to the product of Unit Disposal Coat and Total Volume of Drilling Waste from Recompletlng existing wells, Column (9) x Column (7),
(12) Total Disposal Cost of drilling wastes from all wels or all drilling activities, Column (10) + Column (11),
MA Not applicable.
-------
Worksheet No. 3, May 17, 1996, Page 1 of 2
Coastal Alaska Oil and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators in Cook Inlet, Alaska
Zero Discharge Option by Landfill Disposal (with Closed-Loop System)
191 2,005
1,976 2,085
570 2,085
Total Disposal Cost of Drilling Waste for All Operators =
(Sum of Disposal Costs for All Operators, Column 18}
Total Disposal Cost of Drilling Waste Per Barrel =
((Total Disposal Cost)/(Total Volume of Drilling Wastes, Column »))
Total Disposal Cost of Drilling Wastes Per Platform =
((Total Disposal Cast)/(Total Number of Platforms with Planned Drilling Program, Column 3))
Total Disposal Cost of Drilling Wastes Per Drilling Event =
((Total Disposal Cosl)/(Tolal Number of Wells, Column 4 4- Column 5})
Total Disposal Cost of Drilling Wastes Per New Development Well =
(Total Disposal Cost Per Barrel x Volume of Drilling Waste per an average new well, (Cost Per Barrel)x(Column 6)/(Column 4))
157.337.8691
$133]
$5,212.486]
I $939.957|
$1.301,436]
Total Disposal Cost of Drilling Wastes Per Recompletion Well =
(Total Disposal Cost Per Barrel x Drilling Waste Volume perfor an average recompletion well, (Cost Per Barrel)x(Column 7)/{Column 5))
$198.9241
-------
Worksheet No. 3, May 17,1996, Page 2 of 2
Coastal Alaska Oil and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators in Cook Inlet, Alaska
Zero Discharge Option by Landfill Disposal (with Closed—Loop System)
(1) Operator IDs are confidential, and are therefore discussed In a confidential supporting document (Mclntyre, 1998).
(2), (3), (4), and (5) Some of the data In these columns are confidential, and are therefcredlscussed In a confidential supporting document (Mclntyre, 1996),
(6) Total Incremental Volume of Drilling Waste from new wells Is the product of the Average Volume of drilling waste generated from wells recently drilled In Cook Inlet, the Total Number of Wells scheduled
fordrllllng, the percent of total (99%) waste discharged under the current practice, and percent reduction (69%) of drilling wasteby Closed-Loop System (SAIC, Oct 10,1994).
Based on data provided In 1993 Coastal Oil & Gas 308 Survey Questionnaires. See Worksheet No. 1 for details.
(7) Total Incremental Volume of Drilling Waste from recompleted wells Is the Product of the Average Volume of drilling waste generated from the third drilled Interval of wells recently drilled In Cook Inlet and
the Total Number of Wells scheduled for recompletlon In Cook Inlet, the percent of total (99%) waste d Ischarged under the current practice, and percent reduction (69%) of drilling waste by closed -
loop system. Based on data provided In 1993 Coastal Oil & Gas 308 Survey Questionnaires. See Worksheet No. 1 for details.
(8) Total Incremental Volume of Drilling Waste from all wells Is the sum of all wastes that will be generated In Cook Inlet, Column 5 + Column 6.
(9) Total Number of Days the High Efficiency Solid Separation Equipment Is Needed Is assumed to be equal to the total number of days It will take to complete all drilling operations.
M [(Column 4 x Number of days to drill a well)+(CoIumn 5 x Number of days to recomplete a well)]
(10) Unit Cost of High Efficiency Solid Separation Equipment was estimated based on Information from drilling operations in Louisiana. Although these costs included labor, additional labor
costs are included In this worksheet (Column 14) to serve as an Inflation factor. See SAIC, May 3,1994 for details.
(11) Total Cost of High Efficiency Solid Separation equipment is the product of total number of days the equipment will be need ed and the cost of the equipment per day, Column 9 x Column 10.
(12) Retrofit Cost of solid separation equipment per platform is estimated based on the need of 450 square feet of deck space and the cost of $600 per square foot of deck space.
See SAIC, May 3,1994 for details.
(13) Total Cost of Retrofitting the platforms Is the product of the unit retrofit cost and the total number of Platforms with a planned drilling program, Column 3 x Column 12.
(14) Unit Cost of Operating Solid Separation Equipment was assumed to be the same as unit cost of operating the Injection equipment provided In correspondence with a 308 Survey Respondent.
See confidential supporting document (Mclntyre, 1996).
(15) Total Cost of Operating the Solid Separation Equipment is the product of the unit operating cost per day and the total number of days the equipment is needed, Column 14 x Column 9.
(16) Unit Cost of Landfilling Drilling Wastes was estimated based on Information provided by the Cook Inlet operators. See Appendix B.
(17) Total Cost of Landfilling Drilling Waste is the product of the total volume of drilling waste and the unit cost of landfilling, Column 8 x Column 16.
(18) Total Disposal Cost of Drilling Wastes is equal to the sum of equipment, retrofit, operating, and landfilling costs, Column 11 + Column 13 + Column 15 + Column 17.
NA Not applicable.
-------
Worksheet No. 4, May 17,1996, Page 1 of 2
Coastal Alaska Oil and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators in Cook Inlet, Alaska
Zero Discharge Option by Dedicated Well Injection
1,097,500
1,097,500
1,097,500
1,837 1,097,500 293,867
1,837 4,390,000 3,596,580
1,537 1,097,500 878,090
:*^:*>:S*¥3*K:&?;5£;M*S*ii™X;£:f
293,507
3,596,580
876,053
750,000
750,000
760,000
1*8
750,000
! 6,750,000
760,000
2,500
2,500
2,600
477,500
4,»40,000
1,428,000
2,834,964
25,797,758
Total Injection Cost of Drilling Wastes for All Operators =
(Sum of the total costs of Injection wells. Injection systems, Platform Retrains, and Operating Injection Systems)
(Column 11 +Colurrm 17 +Column 19 H-Column 21)
Total Injection Cost of Drilling Waste Per Barrel -
((Total Injection Cost)/(Total Volume of Drilling Wastes, Column B))
Total Injection Cost of Drilling Wastes Per Platform -
((Total Injection CoslVfTotal Number of Platforms with Planned Drilling Program. Column 3))
Total Injection Cost of Drilling Wastes Per Drilling Event =
((Total Injection Cost)/(TotaI Number of Wells, Column 4 + Column 5))
Total Injection Cost of Drilling Wastes Per New Development Well =
(total Injection Cost Per Barrel x Volume of Priding Waste for mi average new well, (Cost Per 3arra!}x(poJumn e)/ECo!unin 4))
Total Injection Cost of Drilling Wastes Per Recompletion Well =
(Total Injection Cost Per Barrel x Volume of DrilHn0 Waste for on average recompletfon well, {Cost Per Barrel)x(Co!uRm 7)/(CoIunin 5))
I $35.625.5011
$671
83,238,682|
$884,0251
$808,6231
$123.5881
-------
Worksheet No. 4, May 17,1996, Page 2 of 2
Coastal Alaska Oil and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators in Cook Inlet, Alaska
Zero Discharge Option by Dedicated Well Injection
(t) Operator IDs am confkfenttal and on therefore dbcutsodlns confidential supporting document (Mdntyre, 1090).
(2), P). (4), and (5) Somo ol the data In these columns are conHdenual, nnd are therefore discussed In a confidential supporting document (Mdntyre, 1800).
(8) Tolal Incremental Volume of Drilling Waste from new wells is the product of the Average Volume ol drilling waste generated from wells recently drilled In Cooklnlei, the Total Number of Wells
scheduled for drilling, and the percent of total (80S) waste discharged under the current practice. Based on data provided In 1893 Coastal Oil & Gas 308 Survey
Questionnaires. See Worksheet No. 1 for details.
(7) Tolal Incremental Volume of Drilling Waste from recompiled wells Is the Product of the Average Volume of drilling waste generated from the third drilled Interval ol wells recently drilled in Cook Inlet,
the Total Number of Welle scheduled for recompletlon In Cook Inlet, and the percent of total (00%) generated waste discharged under the current practice.
Based on Information In 1993 Coastal Oil & Gas survey questionnaires. See Worksheet No. 1 for details.
(8) Total Incremental Volume of Drilling Waste from all wells Is the sum of all wastes that will be generated In Cook Intel, Column 6 + Column 7.
(9) Total Number of Injection Wells Needed Is calculated based on Information provided by the Industry which specifies 1 dedicated well for every 4 new development wells (Schmidt, April 7,1994).
The number of dedicated wells needed for recompletlons was assumed to be 1 for ever/ 16 recompletlons, (Column 4/4)+(Column 5/16).
(10) Estimated Cost of Drilling an Injection Well Is calculated In Worksheet 1.
(11) Tolal Cost of Injection Walls Is the product of the total number of Infection wells needed and the estimated cost of drilling an Injection well, Column B x Column 10.
(12) Total Number of Injection Systems was estimated based on the assumption that 11njection system Is needed for ever/ platform with a planned drilling program.
Operator B specified the need for 4 Injection systems since no more than 4 platforms are planned for drilling at one time. See confidential supporting document (Safavl, Jan. 30,1905).
(13) Unit Cost of Injection System Is provided by Operators. See confidential supporting document (Safavi, Jan. 30,1995).
(14) Unit Rental Cost of Injection System Is provided by Operator A. See confidential supporting document (Safavi, Jan. 30,1995).
(15) Buying Cost of Injection System Is the product of the Total Number of Systems needed and Unit Buying cost of injection systems. Column 12 x Column 13.
(16) Rental Cost of Injection System Is the product of the total number of days needed to complete drilling and the unit operating cost per day,
[(Column 4 x number of days to drill a well)+(Column 5 x number of days to tecomplete a well)] x (Column 14).
The average drill time for a new development well or a recompletion was determined In Worksheet Noil and was assumed for Operators A and C. The numbers used for Operators are as specified
In the questionnaires.
(17) Applied Cost of Injection System is either the buying or the renting cost of injection systems depending on which is economically most feasible.
(18) Retrofit Cost of Injection System was provided by Operator B. See confidential supporting document (Safavi, Jan. 30.1995).
(19) Total Cost of Retrofitting Platforms is the product of the Total Number of Platforms with planned drilling programs and the Unit Cost of Retrofitting Platforms, Column 3 x Column 18.
This cost is based on the assumption that each platform with a planned drilling program must be retrofitted for an Injection system.
(20) Unit Cost of Operating Injection Systems is provided by operators. See confidential supporting document (Mclntyre, 1998).
(21) Total Cost of Operating Injection System is the product ol the total number of days needed to complete drilling and the unit operating cost per day,
[(Column 4 x number of days to drill awell)+(Column 5 x number of days to recompute a well)] x (Column 20).
The average drill time for a new development well or a recompletion was determined In Worksheet No. 1 and was assumed for all operators.
(22) Total Injection Cost for all Drilling Waste Is the sum of the total costs In columns 11,17,19,and21.
NA Not applicable.
-------
Worksheet No. 4A, May 17,1996, Page 1 of 2
Coastal Alaska Oil and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators in Cook Inlet, Alaska
Zero Discharge Option by Dedicated Well Injection {With Closed-Loop System)
1,313,887 1,318397
1,313,M7 10,511,178
1,313,887 3,941,891
1,097,SOO
1,097,500
1,097,500
mmiSif"
1,837 1,087,800 283.SS7 883,587
1,537 4,390,000 3,690,680 3,595,560
1,537 1,087,600 876,090 876,090
mm
750,000
750,000
780,000
750,000
6,750,000
750,000
2,500
2,500
2,500
477,600
4,940,000
1,425,000
398,235
4,119,960
1,188,490
270,0(
2.430.0C
270.0C
.
209,718
2,169,648
mm
877,953 3.71R917
8,718,908 34,517,3*4
2,084,310 9,077,081
Total Injection Cost of Drilling Wastes for AH Operators =
(Sum of the total costs of Injection wells, Injection systems, platform Retrofit;, and Operating Injection Systems)
(Column 11 +Column 17 +Co!umn 19 -t-Coknnn 21)
Total Injection Cost of Drilling Waste Per Barrel =
((Tow Injection Cost)/(ToteI Volume of DrilKna Wastes, Column B))
Total Injection Cost of Drilling Wastes Per Platform -
((Total Injection Cost)/(rotal Number of Platforms with Planned Drilling Program, Column 3))
Total Injection Cost of Drilling Wastes Per Drilling Event =
((Total Injection Cost)/(Total Number of Wells, Column 4 + Column 5))
Total Injection Cost of Drilling Wastes Per New Development Well -
(Total Injection Cost Per Barrel x Volume of Drilling Waste for on average new well, (Cost Per Ba/re[)x(Column B)/(Column 4))
Total Injection Cost of Drilling Wastes Per Recompletion Well =
(fetal Infection Cost Per Barrel x Volume of Drilling Waste for an average recompHon well (Cost Per Banei}x(Colurtm 7)/(Column 5))
$47.307.3721
$1101
I $4,300.6701
$776.5311
$1,073.777]
$164.1261
-------
Worksheet No. 4A, May 17, 1996, Page 2 of 2
Coastal Alaska OH and Gas Drilling Industry
BAT Compliance Cost Analysis for Operators In Cook Inlet, Alaska
Zero Discharge Option by Dedicated Well Injection (With Closed-Loop System)
(I)
(2), (3), (4), and (S) Somgc(thida1alnlheiiCf>tmiwrifa^
{!) TotdhcMnwIdVdumidDrWhgWulMiemnewwGflililheprodbctollto^
scheduled for drNlnrj, Iheperccnt of Idol (09%) waste discharged under fie current practice, and percent reduction (09%) of drfrhg waste by closed-loop system (9A1C, October 10, 1984).
Bused on dale provided In 1903 Coastal Oil and Gas Survey Questionnaires. SraWorkdieel No. 1 for details.
(7) Total Incremental Volume of Drllltig Wasta from recompleled wells Is the Product of tie Average Volume of drllhg waste generated from tho IHrd drlled Inlerval of wens recently drilled In Cook Inlet,
Ihe TctalttaberolWells scheduled lor recomplelronhCnk Inlet, the PTO
by closed-loop system (SA1C, October 10, 199q. Based on Information In 1993 Coastal oll&Sas survey questionnaires, Seo Worksheet No. 1 for details.
(6) Total Incremental Volume of Drlllhg Waste from all we«> Is Ihe sum of ell wastes tiat will be generated In Cook Inlet. Column 8 + Column 7.
(») Total Number of Injecltal Wells Needed la calculated based on Information provided by the Industry vdilch cpeclSes 1 dedicated well for every 4 new development wells (Schmidt, April?, 1094).
The number of dedicated wallsneeded for recompleUons was assumed lobe 1 for every 16 reccmpletkns, (ColJmn 4/4 )+(Column 5/10),
(10) EsUnated Cost of Drlllhg an Injection Well Is calculated In Worksheet 1 or provided bylhe operators. Seeccnlldenllal suppcrlhg document (Salavl, Jan. 30, 1995).
(11) Total Cost of Injection Wells Is lie product ol the total number ot hjecllcn wells needed and BIB estimated cost of drlllng an hjedlon well, Column 0 x Column 10.
(12) Total Number of Injection Systems was estimated based on the assumption that 1 hjectlon system is needed for every platform with a planned drllRng program.
Operator B specified Ihe need Ior4 hjectlon systems slnceno more than 4 platforms are planned tor drilEng at one lime. See confidential supporthg document (Safavl, Jan. 30, 1995).
(13) UnHCostotln|«tlmSyslanlsprovldedbyOperatorB. See confidential supporthg document (Salavl, Jan. 30. 1995).
(14) Unit Rental Cost of Injection System Is provided by Operator A. Seeccnlldenllal supporthg document (Salavl. Jan. 30, 1995).
(15) Buying Cost of Injection System Is Ihe product ot Iha Total Number of Systems needed and Unit Buying cost ot tijecllon systems. Column 12x Column 13.
(16) Rental Cost of Injection System Is the product ol the total number of days needed to complete drilling and the unit operating cost per day,
[(Column 4 xnumber of days to drill a well)+(Column 5 x number of days to recomplete a well)] x (Column 1 4).
The average drill time for anew development well or a recompleticn was determined In Worksheet No. 1 and was assumed for Operators A and C. Tne numbers used tor Operator B are as specified
h the questionnaires.
(17) Applied Cost of Injection System is either the buying or the renting cost of hjecllon systems dependhg on which Is economically most feaslbla
(18) Retrofit Cost ol Injection System was provided by Operator B. Sea confidential supporthg document (Salavl, Jan. 30, 1995).
(19) Total Cost ol Retrolitthg Platforms Is he product ol he Total Number ol Platforms wilh planned drlllhg programs and the Unit Cost of Retrofitlhg Platforms. Column 3 x Column 18.
This cost Is based on the assumption that each platform with a plained drilhg program mustbe retrofitted tor an hjectlon system.
(20) Unit Cost of Operating Injection Systems Is provided by operators. See confidential supporthg document (Mclmyre, 1996).
(21) Total Cost of Operating Injection System Is lie product of Ihe total number of days needed toccmplete drilling and Ihe unit cperalhg cost per day,
[(Column 4 xnumber ol days to drill a well)-* (Column 5 x number of days to recomplete a well)] x (Column 20).
The average drill this for anew development well or a reccrnpletlon was determined In Worksheet No. 1 and was assumed for all operators.
(22) Total Cost ol High Efficiency Soil* Control Equipment Is the product of toe total number of days the equipment will be needed and the cost of the equipment per day (Colimn 1 1 , Worksheet 3).
(23) Total Cost of Retrotmhg the platforms Is the product of Ihe unit retrofit cost and Ihe total number of Platforms will planned drlllhg programs (Column 13, Worksheet 3).
(24) Total Cost ot Operating the Solid Separation Equipment Is theprodjct of the unit operating cost per day and thetotal number of days the equipment isneeded (Column 15, Worksheet 3).
(25) Total Cost of Solids Control System Is tie sum ot Columns 22, 23. and 24.
(26) Total InJectlcnCostforallDrlllhgWastelsthesumolalMolalcostslnCoUmns 11, 17. 19,21, and2S.
NA Not applicable.
-------
APPENDIX X-2
CALCULATION OF UNIT LANDFILL COSTS
A-17
-------
Worksheet for Landfill Costs for Operators A&C
Assumptions and input Data
Total waste volume (bbls):
Total waste volume (box—equivalents):
Total cuttings volume (bbls):
Total cuttings volume (boxes):
Total Muds Volume (bbls):
Density of Muds+CutBngs (Ibs/bbl):
Density of Cuttings (Ibs/bbl):
Density of Muds (Ibs/bbl):
186,908
23,364
35,513
4,439
151,395
526
980
420
Supply Boat Capacity: See "Worksheet for Cook Inlet
Supply Boat Frequency"
Supply Boat Cost ($/day): 5,000
Truck Capacity (tons): 22
Truck Capacity (boxes): 10
Cost per Tuckload: 1,800
Per Box Purchase Cost 125
Disposal Facility Cost ($/box): 500
Disposal Facility Cost ($/gaIIon); 1.9
Notes:
Worksheet 2, sum of A+C voLs
Volume / 8 bbl per box
19% of 186,908
Volume / 8 bbl per box
81% of 186,908
(0.19x980) + (0.81 x420)
EPA, February 1995
EPA, February 1995
Mclntyre, 1996
Mclntyre, May 23,1995
(22 x2000)lbs/526 IbspbbI/8 bpbox
Mclntyre, May 23,1995
EPA, February 1995
Mclntyre, May 9 1995
Mclntyre, May 9 1995
Supply Boats;
[(15x13 new)+(1 x 1 recompl)] x 2 days per trip x $5000/day =
$1,960,000
Trucks to Oregon (Based on total box—equivalents of waste, although wastes will be transported as
cuttings In boxes and muds in bulk):
(23,364 box—equ!v./10 boxes per load) x $1,800 per load = ' $4,205,520
Cost of Boxes (Includes only outings boxes, assuming muds will be transported in bulk):
4,439 boxes x $125/box = $554,875
Disposal Facility Cost:
(4,439 cuttings boxes x $500/box) + (6,358,590 gal muds x $1.9/gallon) $14,300,821
TOTAL COST:
Cost per bbl:
$21,021,216
$112
A-18
-------
Worksheet for Landffff Costs for Operator B
Assumptions and Input Data Notes:
Total waste volume (bbls): 422,780 Worksheet 2
Total waste volume (box—equivalents): 52,848 Volume / 8 bbi/box
Total cuttings volume (bbis): 80,328 19% of 422,780
Total cuttings volume (boxes): 10,041 Volume / 8 bbl/box
Density of Cuttings (Ibs/bbI): 980 EPA, February 1995
Density of Muds (Ibs/bbI): ' 420 EPA, February 1995
Per Box Purchase Cost ($/box): 125 EPA, February 1995
Temporary Storage Cost ($/sq-ft/mo): ; 0.1 EPA, February 1995
Supply Boat Capacity; See "Worksheet for Cook Inlet
Supply Boat Frequency"
Supply Boat Cost ($/day): 5,000 Mclntyre, 1996
Truck Capacity (boxes): 12 EPA, February 1995
Trucking Cost ($/day): 300 EPA, February 1995
Barge Capacity (boxes): : 240 Mclntyre, 1996
Barge Cost ($/day): ; 6,000 EPA, February 1995
Platform Handling Cost ($/bbl): 6.9 Mclntyre, 1996
Waste Stabilization Cost ($/bbl); 12.47 Mclntyre, 1996
Landfill Usage Fee ($/bbl): ' 45.38 Mclntyre, 1996
Fill Cell Cost ($/bbl): 8.28 Mclntyre, 1996
Cost of Boxes (Includes only cuttings boxes, assuming muds will be transported in bulk):
10,041 boxes x$125/box = $1,255,125
Temporary Storage (No change from original approach—assumes temp, storage for bulk muds
will be comparable to that of boxed cuttings):
52,848 box-equivalents x 16 sq-ftx $0.10 x 6 months = $507,341
Supply Boats: ;
[(15 x 27 new)+(1x18 recompl)] x 2 days per trip x $5000/day = $4,230,000
Trucks to Temporary Storage (Based on total box-equivalents of waste, although wastes will be
transported as cuttings in boxes and muds in bulk):
(52,848 box-equiv/12 boxes pter load) x $300 x 3 days = $3,963,600
Barges (Based on total box-equivalents of waste, although wastes will be transported as cuttings
in boxes and muds in bulk): ;
(52,848 box-equiv/240 boxes per load) x $6000 x 2 days = $2,642,400
Platform Handling Cost:
422,780 bbl X $6.9/bbl = $2,917,182
Waste Stabilization Cost:
422,780 bbl X $12.47/bbI = $5,272,067
Landfill Usage Fee: "
422,780 bbl x $45.38/bbl = $19,185,756
Fill Cell:
422,780 bbl x $8.28/bbI = $3,500,618
TOTAL COST: ; $43,474,089
Cost per bbi: . $103
; A-19
-------
WORKSHEET lor Cook Inlet Supply Boat Frequency
Assumptions and Input Data
Supply Boat Cuttings Capacity (tons):
Supply Boat Cuttings Capacity (boxes):
Supply Boat Muds Capacity (tons):
Supply Boat Muds Capacity (box-equivalents):
Cuttings Density (Ibs/bbl}:
Muds Density (Ibs/bbl):
Average Cuttings % of Total:
Platform CuHlngs Storage Capacity (boxes);
Regularly scheduled boat trips (per week):
Notes:
300 Mclntyre, May 12,1995
77 (3QOx2000)Ibs/980lbspbbl/Bbblpbox
170 Molntyre, May 12,1995
101 (170 x 2GOO)tbs/420 lbspbbl/8 bWpbox
980 EPA, Februaty 1995
420 EPA, February 199S
19 Worksheet 1
12 Melnty«,1996
2 Melntyre, 1896
Well Depth and Waste Volume Analysis
I
Depth Interval
(feet)
Ft. Per
Interval
M&CVol.
per Interva
(bbls)*
Cuttings
Vol.
(bbls)
0-25S3 2,553 3,462 658
2553-4500*** 1,947 2,283 434
4500-9901 6,401 6,333 1,203
9901-10,000 99 115 22
10,000-11,785 1,765 2.057 391
14,250 2,708
No. Cutting
Boxes
Muds Vol.
(bbls)
Mrs per
Interval
Days Per
Interval**
No. 12-Box
Loads
82 2,804 165 13 7
54 1,849 95 7 5
150 5,130 265 20 13
3 93 12 1 0
49 1.666 216 17 4
339 11,542 753 58 28
Frequency
ofl2-bx
Loads (hrsJL
24
21
21
52
53
172
* Volumes per Interval are 99% of the volumes presented in Worksheet 1. The total per well volume used here is slightly greater than the total
In Worksheet 1 due to rounding differences in Worksheet 1.
** @ 13hoursperworkday(fromWorksheet!),
*** The cut point at 4500 ft is from the Offshore NWQI document (EPA, Jan. 13,1993), Appendix A, that states that drilling significantly
slows down after 4500 ft. The coastal data from Worksheet 1 indicate a significant slowing after 9900 ft
Conclusion:
For New Wells;
To 9901 feet, a boat is required every other day, for a total of 25 trips. Subtracting regularly scheduled boat trips:
25 - (40 dap/7 days perweek * 2 tips perweek) = 14trips
After 9901 feet, one additional dedicated trip will occur at the end of the drilling operation, for a total of 15 boat trips per well.
For feeompletions (that generate only 2172 bbls of muds and cuttings, or 272 box-equivalents):
One dedicated boat trip is included in the calculations. Other regularly scheduled boats will transport the remainder of the waste volume.
-------
APPENDIX X-3
DETAILED POLLUTANT REMOVAL ANALYSIS
A-21
-------
Worksheet No. 10, May 17, 1996, Page 1 of 3
Coastal Alaska Oil and Gas Drilling Industry
BAT Pollutant Loadings Analysis for Operators in Cook Inlet, Alaska
Cumulative Reduction in Pollutant Loadings
Zero Discharge Option
Total Volume of Drilling Waste Currently Discharged, barrels = | 626,07o1
(From Worksheet No. 2; Column 8)
Average Cuttings Percent of Total. % = | 19%|
(From Worksheet No. 1. Column 17)
Total Volume of Wet Cuttings Currently Discharged, barrels = | 116,9531
(Total Volume) x (%Cuttlngs)
Volume of Drilling Muds Adhering to Cuttings, barrels = 5,9481
(5% of Wet Cuttings Volume: EPA, 1995)
Volume of Dry Cuttings, barrels = 113,0061
tf" (95% of Wet Cuttings Volume)
Average Density of Dry Cuttings, pounds per barrel = | gso]
(From SAIC. September 7.1994)
Total Weight of Dry Cuttings Currently Discharged, pounds =
(Average Density of Cuttings x Volume of Dry Cuttings)
I Tills value is used as TSS associated with cuttings |
Total Volume of Drilling Muds Currently Discharged, barrels =
[(Total Drilling Waste Volume) x (81% Fluids)] + (Volume of Muds Adhe
I This value is used as the volumetric amount of muds discharged
Average Percent Dry Solids in Drilling Muds by Volume, % = | n%]
(See SAIC, June 6,1994)
Total Volume of Dry Solids in Drilling Muds, barrels = | 56,43?!
(Percent Dry Solids x Total volume of Mud)
Average Density of Dry Solids in Drilling Muds, pounds per barrel = | 1025|
(See SAIC. June 6,1994)
Total Dry Weight of Muds Currently Discharged, pounds
(Average Density of Mud Solids x Total Volume of Mud Solids)
I This value is used as the dry-basis amount of muds
I discharged and the TSS associated with muds
Note: All volumes and weights are cumulative over 7 years from 1996 through 2002
-------
Worksheet No. 10, May 17, 1996, Page 2 of 3
Coastal Alaska Oil and Gas Drilling Industry
BAT Pollutant Loadings Analysis for Operators in Cook Inlet, Alaska
Cumulative Reduction in Pollutant Loadings
Zero Discharge Option
E
fl)
(2)
(3)
(?)
(«>
' T",,- awed on i* 'Mmibttian
Based on
P)
Total Ourh).ilative -
educl-KJn.in Logdihg
: , aas»« on - «v%
| Conventional Pollutants I Ibs/bbl of mud Barrels
TSS (Associated with Muds)
TSS (Associated with Cuttings)
TSS-(Total) • ™
Total Oil (In Muds+Cuttings) 0.0596 513,064
Total Conventional ''/ - -' 'A""-fr. .,c ' .*> '' ",.
I Priority Pollutants Organies I Ibs/bbl of mud Barrels
Naphthalene 0.0000035 513,064
Fluorene 0.0000563 513,064
Phenenthrene 0.0000084 513,064
Total Priority Pollutants Oraanics : : , ,, 0:0000682 >'" 513064
I Priority Pollutants Metals I Ibs/lb dry mud Pounds
Cadmium 0.0000011 57,848,007
Mercury 0.0000001 57,848,007
Antimony 0.0000057 57,848,007
Arsenic 0.0000071 57,848,007
Beryllium 0.0000007 57,848,007
Chromium 0.0002400 57,848,007
Copper 0.0000187 57,848,007
Lead 0.0000351 57,848,007
Nickel 0.0000135 57,848,007
Selenium 0.0000011 57,848,007
Silver 0.0000007 57,848,007
Thallium 0.0000012 57,848,007
Zinc 0.0002005 57,848,007
T6ta> Privity Pollutants Hetais - >/< • 'OJQOOS25S: ,' ./.; SSWS^uO?
| Non-Conventional Pollutants | Ibs/lb or bbl of mud Pounds or Barrels
Aluminum 0.0090699 57,848,007
Barium 0.1200000 57,848,007
Iron 0.0153443 57,848,007
Tin 0.0000146 57,848,007
Titanium 0.0000875 57,848,007
Alkylated benzenes (a) 0.0021017 513,064
Alkylated naphthalenes (b) 0.0000344 513,064
Alkylated lluorenes (b) 0.0001218 513,064
Alkylated phenanthrenes (b) 0.0000143 513,064
Total biphenyls (b) 0.0001360 513,064
Total dibenzothbphenes 0.0000004 513,064
Total Non ^Conventional Pollutants v .?*.:>' *?"„'.*.'* ' '\..~. >
Pounds % of total I Pounds I
57,848,007 0% 0.0
110,745,522 0% 0.0
188,593,529 " '0% OJO
30,579 0% 0.0
; "' 0%'' -v" *'>, '- ' 0.0, t
Pounds % of total | Pounds |
63.6 0% 0.0
5.8 0% 0.0
329.7 0% 0.0
410.7 0% 0.0
40.5 0% 0.0
13,883.5 0% 0.0
1,081.8 0% 0.0
2,030.5 0% 0.0
780.9 0% 0.0
63.6 0% 0.0
40.5 0% 0.0
69.4 0% 0.0
11,596.5 0% 0.0
** - 30,399.1 <.-" «* • .'.-,0%. * »,,» -, - -0,0 '
Pounds % of total I Pounds I
524,675.6 0% 0.0
6,941,760.9 0% 0.0
887,637.2 0% 0.0
844.6 0% 0.0
5,061.7 0% 0.0
1,078.3 0% 0.0
17.6 0% 0.0
82.5 0% 0.0
7.3 0% 0.0
69.8 0% 0.0
02 0% 0.0
Pounds
57,848,007
110,745,522
168,593,529
Pounds
V* '
Pounds
30,579
24,166'
1.8
28.9
4.3
''3S.O
63.6
5.8
329.7
410.7
40.5
13,883.5
1,081.8
2,030.5
780.9
63.6
40.5
69.4
11,598.5
31
Pounds
*
524,675.6
6,941,760.9
887,637.2
• -V-r«!«a
844.6
5,061.7
1,078.3
17.6
62.5
7.3
69.8
0.2
1 Total Reductions*'-
-------
Worksheet No. 10, May 17, 1996, Page 3 of 3
Coastal Alaska Oil and Gas Drilling Industry
BAT Pollutant Loadings Analysis for Operators in Cook Inlet, Alaska
Cumulative Reduction in Pollutant Loadings
Zero Discharge Option
(1) Pollutant names Include 14 heavy metals, 9 organic constituents, TSS, and Total OH.
The listed pollutants of concern are as specified In Table VII-6 In thel 995 Coastal Development Document (EPA, 1995).
(2) Average concentration of the listed heavy metals were obtained from the Offshore DD (Table XI-6) except the value for Barium (EPA, 1998).
Concentration of Barium in the drilling mud was estimated based on the average mud weight (see SAIC, June 6,1994).
Average concentrations of organic constituents were estimated based on the assumption that the primary source of these compounds in the mud Is mineral oil,
Organic concentrations were estimated based on 0.02% mineral oil by volume (see SAIC, June 7,1994, and Schmidt, July 11,1994).
Average concentration of Total Oil was also estimated based on the use of 0,02% mineral oil (see SAIC, June 7,1994).
(3) Amount of drilling waste currently discharged is given as total dry weight of muds (Ibs) for metals and as total volume of drilling muds (barrels) for organlcs and oil.
These values are calculated on page 1 of this worksheet,
(4) Total cumulative pollutant loadings based on the current practice is the product of the average concentrations of pollutants in drilling muds (Column 2) and
the total amount of muds generated (Column 3).
The caloulationsfor the TSS pollutant loadings are shown on page 1,
(S) Percent passing zero discharge limitation Is zero.
(6) Total cumulative loadings based on zero discharge is zero since no waste is discharged.
(7) Total cumulative reduction in loadings is equal to the loading under the current practices (Column 4) minus Zero Discharge loading (Column 6).
-------
APPENDIX XI-1
CAPITAL COSTS FOR OPTIONS 1 AND 2
GAS FLOTATION
A-25
-------
TABLE A
CAPITAL COSTS FOR OPTIONS 1 AND 2
TRADING BAY PRODUCTION FACILITY
CostCateg^oty^ ->/" "V>~ **^
Materials and Equipment
(4) 40,000 BPD Gas Flotation Units
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to M&E Cost
Subtotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
Total
,/ asaazea Cost _,
827,699
124,155
951,854
951,854
190,371
285,558
76,148
< 'Total Cost *
1,903,708
190,371
285,558
76,148
2,455,786
TABLEB
CAPITAL COSTS FOR OPTIONS 1 AND 2
GRANITE POINT TREATMENT FACILITY
'>**&< 1~W<*\ if',' <,\ r^ I>M> \ ' s ^ ^ >^/v v*^ ^*
Materials and Equipment
5,000 BPD Gas Flotation Unit
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to M&E Cost
Main Equipment Building
Subtotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
"1* 'itemiaiedCost, „
' > ^"'{1995$) v
147,804
22,171
339,948
339,948
325,532
100,543
150,814
40,217
,«. Total Cost T
-, -'Uto&ik* ':
1,005,428
100,543
150,814
40,217
Total 1,297,002
A-26
-------
TABLEC
CAPITAL COSTS FOR OPTIONS 1 AND 2
EAST FORELAND TREATMENT FACILITY
Materials and Equipment
5,000 BPD Gas Flotation Unit
Piping and Instnimentation (15%)
Total M&E Cost with Area Multiplier
Installation ;
Installation equal to M&E Cost
Main Equipment Building
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
Total
Subtotal
147,804
22,171
339,948
339,948
325,532
100,543
150,814
40,217
1,005,428
100,543
150,814
40,217
1,297,002
A-27
-------
TABLED
CAPITAL COSTS FOR OPTIONS I AND 2
DILLON PLATFORM
' •"
Materials and Equipment
10,000 BPD Gas Flotation Unit
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Subtotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 266 SF @ $658.5/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
TOTAL
162,585
24,388
373,945
934,862
130,881
196,320
52,352
175,161
17,516
26,274
7,006
1,308,807
379,553
225,957
1,914,317
A-28
-------
TABLE £
CAPITAL COSTS FOR OPTIONS 1 AND 2
BRUCE PLATFORM
Materials and Equipment
1,000 BPD Gas Flotation Unit |
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&B Cost
Subtotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 112 SF @ S658.5/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
TOTAL
115,7%
17,369
266,331
665,828
93,216
139,824
37,286
73,752
7,375
11,064
2,950
932,159
270,326
95,141
1,297,626
A-29
-------
TABLEF
CAPITAL COSTS FOR OPTIONS 1 AND 2
AI«JNA PLATFORM
- - - '-•' • n-i-S^StSlpi^^SI^ISIIisl^lSl^tti^-
Materials and Equipment
5,000 BPD Gas Flotation Unit
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Subtotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 210 SF @ S658.5/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
147,804
22,171
339,948
849,871
118,982
178,473
47,593
138,285
13,829
20,744
5,531
1,189,819
345,048
178,389
TOTAL 1,713,256
A-30
-------
TABLEG
i
CAPITAL COSTS FOR OPTIONS 1 AND 2
BAKER PLATFORM
,*'" , ,-.',* ' ..
••' '•'•"• '• ," , ..••••- '•,,••. ' ss ,
1 <,»., ;^w '•:•„ * ' , ; v,fs* v***mf, ,,:,,„',,., ..
Materials and Equipment '
5,000 BPD Gas Flotation Unit
Piping and Instrumentation (15%) ,
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Subtotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 210 SF @ S658.5/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
TOTAL
Itemized; Cost
' •"& fl 00? $1< '"'" ' ' '
\Kxra ^)
147,804
22,171
339,948
849,871
118,982
178,473
47,593
138,285
13,829
20,744
5,531
ibtalCosf
" /iQO'^iii Cj'""
v*,~~3 wj ;
1,189,819
345,048
178,389
1,713,256
A-31
-------
APPENDIX XI-2
CAPITAL COSTS FOR OPTION 3
ZERO DISCHARGE VIA INJECTION
A-32
-------
TABLE A
CAPITAL COSTS FOR OPTION 3
TRADING BAY PRODUCTION FACILITY
"' "' ' ' - "' * v '\ r ; *
v;; *_ \ $P* Category ; " -' ^ ^v|
1
Materials and Equipment
(4) Shipping Pumps
(3) Pig Launchers
(2) 15,000 Barrels Storage Tanks
(3) Booster Pumps
Piping and Instrumentation (15 %) :
Total M&E Cost with Area Multiplier
Installation
Installation equal to M&E Cost
Main Equipment Building
SubTotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
Pipeline Costs
Total
- Ju£Il*IZ£fI t^wSl-..
- (1995$), $ ,.
630,062
33,393
1,260,124
220,522
321,615
4,931,430
4,931,430
325,532
1,018,839
1,528,259
407,536
iotaf cost
; 1(1995$)= -;
10,188,392
1,018,839
1,528,259
407,536
33,143,901
46,286,927
TABLES
CAPITAL COSTS FOR OPTION 3
GRANITE POINT TREATMENT FACILITY
- -7, "X,; - ' €osi Caltegory" j "'" '\
Materials and Equipment
5,000 BPD Gas Flotation Unit
5,000 BPD Granular Filtration Unit
Centrifuge
Piping and Instrumentation (15%) ;
Total M&E Cost with Area Multiplier
Installation
Installation equal to M&E Cost !
Main Equipment Building
Engineering (10%) :
Contingency (15%)
Insurance & Bonding (4%)
", Itemized Cost
",'"",. €1995 $J' ' "'
147,804
239,218
46,430
65,018
325,532
231,941
347,911
92,776
TOTAL
;: Total Cost
996,938
996,938
325,532
231,941
347,911
92,776
2,992,036
A-33
-------
TABLEC
CAPITAL COSTS FOR OPTION 3
EAST FORELAND TREATMENT FACILITY
•*••» ^«vn;-; «**
•••'-. ~cos*cafeg^'"^^' "<*:
• • •• •"•w * _. v. v v •"
. ' s 5 •••• > -\ "' w <-M " ' ' -•. .
Materials and Equipment
5,000 BPD Gas Flotation Unit
(2) Shipping Pumps
(1) Pig Launcher
(1) 15,000 Barrels Storage Tank
(1) Booster Pump
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to M&E Cost
Main Equipment Building
SubTotal
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
Pipeline Costs
' '""'
,,, Itemized Cost
1 . eu«*5$r ',j
147,804
315,031
11,131
630,062
73,507
176,630
2,708,328
2,708,328
325,532
574,219
861,328
229,688
, „*:* -/ - ,
Total G&st <
'<1995$K '-
5,742,188
574,219
861,328
229,688
15,297,055
Total 22,704,478
A-34
-------
TABLED
CAPITAL COSTS FOR OPTION 3
KING SALMON, GRAYLING, DOLLY VARDEN PLATFORMS
'"• ^ *" * "? : '
* "'; ' "-' SCostCat%
-------
TABLEE
CAPITAL COSTS FOR OPTION 3
SPARK PLATFORM
v.«: ,!* * :- *• •>, , \ f
y \ kj* % V
Cost Category f ^^^ 7 * J- .
Company Labor and Expense
Project Engineer
Hazard Analysis
Expense
SubTotal
Contract Engineering
Design Contract
Contract Labor
Offshore Piping & Structural
Electrical & Instrumentation
SubTotal
Contract Services
Piping/Supports Prefabrication
Foam Penetrations
Painting
PSM Document Revisions
SubTotal
Materials
Pipeline, Valves, and Fittings
Structural Steel
Construction Consumables
(2) Injection Pumps
SubTotal
Construction Supervision/Inspection
Inspector
X-Ray/Non-Destructive Testing
NDE Contract
Logistics
Boats and Helicopters
Offshore Catering
SubTotal
Alaska Region Indirect Expense
' Itemized Cost „
,;(IS95$)
43,900
18,658
6,585
72,435
340,225
43,900
38,413
8,231
10,975
10,975
137,564
2,101
63,006
64,046
59,265
13,170
32,925
49,388
10,975
' Total Cost , -,
/ <(19»S$)
69,143
72,435
384,125
68,594
202,671
59,265
13,170
82,313
10,975
SubTotal 962,690
Contingency
Contingency (10%)
96,269
Subtotal Capital Costs
Injection Well Costs
(2) Well Recompletions
TOTAL
1,481,625
96,269
1,058,959
1,481,625
2,540,584
A-36
-------
TABLEF
CAPITAL COSTS FOR OPTION 3
SWEPI «C" PLATFORM
*** "• ,« ,, " - ^ " 7 Cost Category^ . \
, '*, '', "< "\ ,\ "~>: ,,-—- * ~ " ! ', ', ;' ^ /
Company Labor and Expense
Project Engineer
Hazard Analysis
Expense '
SubTotal
Contract Engineering ;
Design Contract i
Contract Labor
Offshore Piping & Structural
Electrical & Instrumentation
SubTotal '
Contract Services
Piping/Supports Prefabrication
Foam Penetrations
Painting
PSM Document Revisions
SubTotal
Materials
Pig Receiver
Pipeline, Valves, and Fittings
Structural Steel
Construction Consumables
SubTotal
Construction Supervision/Inspection
Inspector
X-Ray/Non-Destructive Testing
NDE Contract
Logistics
Boats and Helicopters
Offshore Catering
SubTotal
Alaska Region Indirect Expense
SubTotal
Contingency
Contingency (10%) ;
Subtotal Capital Costs •
Additional Centrifuge
TOTAL
^ 5
:: Itemized Cost ,,
0595$) " ;
43,900
18,658
6,585
72,435
340,225
43,900
38,413
8,231
10,975
10,975
11,131
137,564
2,101
63,006
59,265
13,170
32,925
49,388
10,975
97,382
269,481
:, T
-------
TABLEG
CAPITAL COSTS FOR OPTION 3
DILLON PLATFORM
;. ;; .' {'%^y^W''%-^>%v -'-"-, -, " '• *
Cost Category' ' » ^k^\l*"v.i , "-,
Materials and Equipment
10,000 BPD Gas Flotation Unit
Centrifuge
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 266 SF @ S600/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
TOTAL
' '* ••
Itemized Cost ';
"&9s$)"'y^\
162,585
46,430
31,352
. 168,257
252,385
67,303
175,161
17,516
26,274
7,006
' - /' "',
-' Total Cosfe v
: ;xi^>5$>;' '"
480,734
1,201,835
487,945
225,958
2,396,471
A-38
-------
; TABLE H
CAPITAL COSTS FOR OPTION 3
BRUCE PLATFORM
'•'•'*'",A,* , ^ ;,„ ,-"•",'' * ,., f ; ~-, * tN~ •• < ' :"• *' "> /* '"
j /^ :-£-« " .V'« ~<^Cafc8nfer : ^ > , ^ «,
Materials and Equipment
1,000 BPD Gas Flotation Unit
Centrifuge
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 112 SF @ $600/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Injection Well Costs
(2) Injection Pumps ,
Piping and Instrumentation (15%)
Costs x Geog. Multiplier (Equip. Csts x 2)
Installation (2.5 x Equip. Costs)
Engineering (10%)
Contingency (15%) < .
Insurance & Bonding (4%)
SubTotal
(2) Injection Wells
TOTAL
Itemized Cost
1(1^5$) -~
115,796
46,430
24,334
130,592
195,888
52,237
73,752
7,375
11,063
2,950
29,200
4,380
33,580
83,950
11,753
17,630
4,701
2,627,795
"" '"'TolbalCost";""
\* (J58*5$y ''1
. 373,120
932,800
378,717
95,140
185,194
2,627,795
4,592,766
A-39
-------
TABLE I
CAPITAL COSTS FOR OPTION 3
ANNA PLATFORM
Materials and Equipment
5,000 BPD Gas Flotation Unit
Centrifuge
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 210 SF @ S600/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
147,804
46,430
29,135
156,358
234,537
62,543
138,285
13,829
20,743
5,531
TOTAL
446,737
1,116,843
453,438
178,388
2,195,407
A-40
-------
TABLE!
CAPITAL COSTS FOR OPTION 3
BAKER PLATFORM
I""*; =V'';^l\,^^a^e^o^i "'*- - * " V-
* ' ! ' i . ; ,, ,
Materials and Equipment
5,000 BPD Gas Rotation Unit
j
Centrifuge
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 210 SF @ $600/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
; SubTotal
TOTAL
f "" 'f'"'f'-^-^ftn!tf'J^t't' J'*"' "'"'Atp
«! 99T- »1 •
147,804
46,430
29,135
156,358
234,537
62,543
138,285
13,829
20,743
5,531
' V^P*,;;
" ""(IS&S'^} s
446,737
1,116,843
453,438
178,388
2,195,407
A-41
-------
TABLEK
CAPITAL COSTS FOR OPTION 3
TYONEK PLATFORM
",, s f"? i •.•ffV rf^f"<.lf",S .. f f •.
••;••; ^ CostGat^ >"»»,* }%^
- <.-, ^ ^ f ^ ^ •, .. ^
Materials and Equipment
1,000 BPD Multi-Media Filtration System
Centrifuge
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x M&E Cost
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Platform Modifications
Cantilever Deck 400 SF @ S600/SF
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
Injection Well Costs
(2) Injection Pumps
Piping and Instrumentation (15%)
Costs x Geog. Multiplier (Equip. Csts x 2)
Installation (2.5 x Equip. Costs)
Engineering (10%)
Contingency (15%)
Insurance & Bonding (4%)
SubTotal
(2) Injection Wells
TOTAL
Itemized Cost :?
V"O»5f'#'^ 1;
113,154
46,430
23,938
128,465
192,698
51,386
263,400
26,340
39,510
10,536
29,200
4,380
33,580
83,950
11,753
17,630
4,701
2,627,795
, , •Total Cost X
;', C0»0$>,
367,043
917,608
372,549
339,786
185,194
2,627,795
4,809,976
A-42
-------
APPENDIX XI-3
MODEL NEW SOURCE COOK INLET PLATFORM
COMPLIANCE COST WORKSHEETS
A-43
-------
TABLE A
MODEL NEW SOURCE COOK INLET PLATFORM PROFILE WORKSHEET:
ESTIMATION OF PRODUCED WATER GENERATION RATE
Platform
K. Salmon
Monopod
Grayling
G. Point
Dillon
Bruce
Anna
Baker
D. Varden
Steelhead
SWEPIA
SWEPIC
Tyonek
Average
OilPrdn
(bpd)
3,864
1,981
5,207
6,086
841
865
3,117
1,301
4,983
4,184
3,200
1,800
3,119
Oil Wells .
19
22
23
11
10
13
. 23
14
24
4
17
17
--
OilPranYWeU
(bpij)
203
90
226
553
84
67
136
93
208
1,046
188
106
250
GasPrdn
(MMcfd)
165
220
193
Gas Wells
9
13
--
Gas Fran/Welt
(MMcfd)
18
17
--
Water Prdn
(bpd)
40,540
6,230
45,180
226
3,116
199
919
924
31,510
2,270
300
1,400
30
11,068
bblWater/bW
Oil
10.49
3.14
8.68
0.04
3.71
0.23
0.29
0.71
6.32
0.54
0.09
0.78
2.92
bbl Water/
MMcfd
13.76
0.14
(a)
PW Generation for Model New Source CI Platform:
(10 model oil wells x 250 bpd/well x 2.92 bbl PW/bbl oil) + (24 model gas wells x 17 MMcfd/well x 0.14 bbl PW/MMcfd) =
7,353 bpd
(a) The value 13.76 bbl PW/MMcfd gas is not used to calculate an average produced water generation rate associated with gas production because the majority of the produced water
from this platform is due to waterflooding for cil recovery.
-------
TABLEB
MODEL NEW SOURCE COOK INLET PLATFORM CAPITAL AND O&M COSTS
FOR PRODUCED WATER INJECTION (1995 $)
Model Produced Water Flow (BWPD) = 7,353
• r ^ -, ~ ^ -S ^ .. , .,.. , ^ v. , - ,-,Sv « ..,•••• v. , •• ••
- " ', ,.,,," Cast Category ' "v" - * * ; ' " ' x - "
•^ •. V "" . . . . s , . , V
Capital Costs:
Materials and Equipment
10,000 BPD Granular Filtration Unit
Centrifuge
Piping and Instrumentation (15%)
Total M&E Cost with Area Multiplier
Installation
Installation equal to 2.5 x. M&E Cost :
Engineering (10%) '
Contingency (15%)
Insurance and Bonding (4%)
Subtotal
Injection Well Costs
(2) 10,000 BWPD Injection Pumps (Installed)
Piping and Instrumentation (15 %)
Total Injection Pump Cost w/ Area Multiplier
Engineering (10%)
Contingency (15%)
Insurance and Bonding (4%)
Subtotal
(3) 6,000 BWPD Injection Wells !
TOTAL CAPITAL COST ]
O&M Costs:
Standard O&M (10% Capital)
Inj. Well Workovers
Treatment Chemicals
Sludge Disposal
TOTAL O&M COST
Itemized Cost (1995
Wf"". ^
127,381
46,430
26,072
156,358
234,537
62,543
437,454
65,618
50,307
75,461
20,123
3,941,692
809,837
100,000
245,100
162,641
>
v-- -Total Cost % •* '
; % tiSfifa iff
399,765
999,411
453,438
1,006,143
145,891
3,941,692
$8,098,375
$1,517,578
A-45
-------
APPENDIX Xn-1
TWC COMPLIANCE COST CALCULATIONS
A-46
-------
EXISTING SOURCES/OPTION 1 FOR WORKOVER/TREATMENT FLUIDS
Input Data ..-...>< "< ', ^ s , ^ ; ,, , , ,. ""*..' " •• •*- ; ",;,* , .. *
Total 1992 number of wells discharging W/T;fluids (Sect. XII.4.1.1):
Average 1992 volume of W/T fluid discharged/weU/yr (bbl/yr) (SAIC, Jan 31, 1995):
Percentage of Water-Access Facilities (Sect. XII.4.1.1):
Percentage of Land-Access Facilities (Sect. XH.4.1.1):
Percentage of Medium/Large Facilities:
Percentage of Small Facilities:
Cost to treat W/T fluids with gas flotation at water-access sites ($/bbl)
Cost to treat W/T fluids with IGF at land-access sites ($/bbl)
Capacity of small-volume barge (bbls) (Sect. XII.4.1.3):
Assumed portion of barge used per job (i.e., 587 bbls per job require 1/2 of one barge):
Cost of Barge + Tug Transportation ($/round trip) (Sect. XII.4.1.3):
Cost of 50% of barge transportation ($/job) (Sect. XII.4.1.3):
Cost of vacuum truck transportation ($/bbl) (Sect. XII.4.1.3):
Commercial disposal cost for TWC fluids ($/bbl) (Sect. XO.4.1.3):
350
587
0.656
0.344
0.77
0.23
0.021
0.10
1500
0.5
1097.5
548.75
1.92
8.78
Gas Flotation Treatment Costs for Major Pass 'Facilities ..'•'• . ,
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
58
0
58
No. Jobs/yr
at IGF
25*
'• 0
25*
Volume Treated
per year (bbl)
14,675
0
14,675
IGF Treatm't
Cost ($/yr)
308
0
$308
*58 jobs less 33 jobs already going to IGF
:'2^lfecJya^'fcfl5fefor€k^^P«3^F^iHfes - ','" - "^ ' -' - " '"'I' ";;••',,,'"
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
119
93
212
Inj. Cost
($/bbl)
$0.116
i $0.218
Volume Treated
per year (bbl)
69,853
54,591
124,444
Injection
Cost ($/yr)
8,103
11,901
$20,004
Zero Discharge Costs for Small Facilities -' ,,», i. ' -, ' ", i: ,, ^ N' >"'"": "' ""^ " •• x
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
52
28
80
Volume Disposed
Commer'ly (bbl/yr)
: 30,524
16,436
'. 46,960
Transportation
Cost ($/yr)
28,535
31,557
60,092
Disposal
Cost ($/yr)
268,001
144,308
$412,309
Total Transport'n
+ Disposal Cost
$296,536
$175,865
$472,401
TOTAL TRANSPORTATION AND DISPOSAL COST FOR
WORKOVER/TREATMENT FLUIDS ($/YR):
$492,713
A-47
-------
EXISTING SOURCES/OPTION I/COMPLETION FLUIDS
Input Data
Total 1992 number of wells discharging completion fluids (Sect. XII-4.1.1):
334
Average 1992 volume of completion fluid discharged per well/yr (bbl/yr) (SAIC, Jan 31, 1995):
209
Percentage of Water-Access Facilities (Sect. XII. 4.1.1):
0.656
Percentage of Land-Access Facilities (Sect. XD.4.1.1):
0.344
Percentage of Medium/Large Facilities
0.77
Percentage of Small Facilities (dispose of completion fluids commercially):
0.23
Cost to treat completion fluids with gas flotation at water-access sites ($/bbl) (Sect. XII.4.1.2):
0.021
Cost to treat completion fluids with gas flotation at land-access sites (S/bbl) (Sect. XII.4.1.2):
0.10
Capacity of small-volume barge (bbls) (Sect. XH.4.1.3):
1500
Assumed portion ofbarge used per job (i.e., 209 bbls per job require 1/4 of one barge):
0.25
Cost of Barge + Tog Transportation ($/round trip) (Sect. XII.4.1.3):
1097.5
Cost of 25% of barge transportation ($/job) (Sect. XII.4.1.3):
274.38
Cost of vacuum truck transportation ($/bbl) (Sect. XH.4.1.3):
1.92
Commercial disposal cost for TWC fluids ($/bbl) (Sect. Xn.4.1.3):
8.78
^ ^ •*> '•$.. .. FsfV\*v V t*Ay*/S &,,&*<•• f v •J" ~* '• s
Gas Flotation TreatmentCosts for Mstfor Pass Facilities - -^ * "" '-; ' / - '- ,
Facility Location
Water-Access
Land-Access
Total
No. Completion
Jobs/yr
55
0
55
No. Jobs/yr
at IGF
23*
0
23*
Volume Treated
per year (bbl)
4,807
0
4,807
IGF Treatm't
Cost ($/yr)
101
0
$101
*SS jobs less 32 jobs already going to IGF
. • :. y >- <
Zero Discharge Costs for General Permit Facilities s a \* "
Facility Location
Water-Access
Land-Access
Total
No. Comp.
Jobs/yr
114
88
202
Inj. Cost
($/bbl)
$0.116
$0.218
Volume Treated
per year (bbl)
23,826
18,392
42,218
Injection
Cost ($/yr)
2,764
4,009
$6,773
Zero Discharge CosteforSmaEFaciBtfcs ' ^"* \ si' *"•*'/ -"< '.."''," ' ' s -, , J ' <, /
Facility Location
Water-Access
Land-Access
Total
No. Comp.
Jobs/yr
51
26
77
Volume Disposed
Commer'ly (bbl/yr)
10,659
5,434
16,093
Transportation
Cost ($/yr)
13,993
10,433
24,426
Disposal
Cost ($/yr)
93,586
47,711
$141,297
Total transport'n
+Disposal Cost
$107,579
$58,144
$165,723
TOTAL TRANSPORTATION AND DISPOSAL COST FOR
COMPLETION FLUIDS ($/VR):
$172,597
A-48
-------
NEW SOURCES/OPTION 1 FOR WORKOVER/TREATMENT
Input Data J " , ••' " .. " ^ '* '' „'';'''<•• ~ ^ % " •• «»' ' - ""'•
Total number of wells discharging workover/treatment fluids (Sect. Xn.4.1.1):
Average volume of workover/treatment fluid discharged per well/yr (bbl/yr) (SAIC, Jan 31 , 1995):
Percentage of Water-Access Facilities:
Percentage of Land-Access Facilities:
Percentage of Medium/Large Facilities
Percentage of facilities that dispose of W/T fluids commercially:
Cost to treat W/T fluids with gas flotation at water-access sites ($/bbl):
Cost to treat W/T fluids with gas flotation at land-access sites (S/bbl) (Sect. XH.4.1.2):
Cost to inject W/T fluids with produced water at water-access sites ($/bbl):
Cost to inject W/T fluids with produced water at land-access sites ($/bbl) (Sect. XE.4.1.2):
Capacity of small-volume barge (bbls) (Sect. Xn.4.1.3):
Assumed portion of barge used per job (i.e., 587 bbls per job require 1/2 of one barge):
Cost of Barge + Tug Transportation ($/round trip) (Sect. XTJL4.1.3):
Cost of 50% of barge transportation ($/job) (Sect. XH.4.1.3):
Cost of vacuum truck transportation ($/bbl) (Sect. Xn.4.1.3):
Commercial disposal cost for TWC fluids ($/bbl) (Sect. XH.4.1.3):
45
587
0.656
0.344
0.77
0.23
0.021
0.10
0.116
0.218
1500
0.5
1097.5
548.75
1.92
8.78
GasHotefifa Treatment Costefw-MalorTswi'aoBpfe* ; " -.«"'.. , '
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
6
0
6
No. Jobs/yr
Treated i
6
0
6
Vol. Treated
(bbl/yr)
3,522
0
3,522
GFTreatm'tCost
(S/yr)
74
0'
$74
Zero Biseharge Casts for General Permit Facilitiss ^ ° ~'»' ^/ ; - -"' \, *"
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
17
12
29
No. Jobs Injected
17
12
29
Vol. Injected
(bbl/yr)
9,979
7,044
17,023
Injection Cost
($/yr)
1,158
1,536
$2,694
Zero Discharge Costs f or SmaU Facilities : 1"is - ^
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
7
3
10
No. Jobs Disp.d
Commercially/yr
7
: 3
10
* s^ " ', %, ,*"'-, /» ">« *" ''
Volume Disp'd
Comm'ly (bbl/yr)
4,109
1,761
5,870
Transport'n Cost
($/yr)
3,841
3,381
$7,222
Disposal Cost
($/yr)
36,077
15,462
$51,539
Total Transp. +
Disp. Cost
39,918
18,843
$58,761
TOTAL OPTION 1 NSPS COST FOR
WORKOVER/TREATMENT FLUIDS ($/YR):
$61,529
A-49
-------
NEW SOURCES/OPTION 1 FOR COMPLETION FLUIDS
Total number of wells discharging workover/treatment fluids (Sect, xn.4.1.1):
45
Average volume of completion fluid discharged per well/yr (bbl/yr) (SAIC, Jan 31, 1995):
209
Percentage of Water-Access Facilities:
0.656
Percentage of Land-Access Facilities:
0.344
Percentage of Medium/Large Facilities
0.77
Percentage of facilities that dispose of W/T fluids commercially:
0.23
Cost to treat W/T fluids with gas flotation at water-access sites (S/bbl):
0.021
Cost to treat W/T fluids with gas flotation at land-access sites (S/bbl) (Sect. xn.4. 1 .2):
0.10
Cost to treat W/T fluids with produced water at water-access sites (S/bbl):
0.116
Cost to treat W/T fluids with produced water at land-access sites (S/bbl) (Sect. XH.4. 1.2):
0.218
Capacity of small-volume barge (bbls) (Sect. XH.4.1.3):
1500
Assumed portion of barge used per job (i.e., 587 bbls per job require 1/2 of one barge):
0.5
Cost of Barge + Tug Transportation (S/round trip) (Sect. XH.4.1.3):
1097.5
Cost of SOX of barge transportation ($/job) (Sect XH.4.1.3):
548.75
Cost of vacuum track transportation (S/bbl) (Sect. XH.4.1.3):
1.92
Commercial disposal cost for TWC fluids ($/bbD (Sect. XH.4.1.3):
8.78
Gas Flotation Treatment Costs for Maj
Facility Location
Water-Access
Land-Access
Total
No.W/TJobs/yr
6
0
6
' r < \ ^ >
or fassF-actBtics: t '
No. Jobs/yr
Treated
6
0
6
Vol. Treated (bbl/yr)
1,254
0
1,254
GF Treatm't Cost
($/yr)
26
0
$26
Zero Discharge Costs for General Permit Facilities A > J ' s * ' , "
Facility Location
Water-Access
Land-Access
Total
No. W/T Jobs/yr
17
12
29
No. Jobs Injected
17
12
29
Vol. Injected (bbl/yr)
3,553
2,508
6,061
Injection Cost ($/yr)
412
547
$959
Zero Discharge Costs'Jfor Small FacilifieV^ ? 5 „' •> .. * '''•• "" - " - * " ^ t *, , "' Z. '"' „ ..
Facility Location
Water-Access
Land-Access
Total
No. W/T Jobs/yr
7
3
10
No. Jobs Disp.d
Commercially/yr
7
3
10
Volume Disp'd
Comm'Iy (bbl/yr)
1,463
627
2,090
Transport' n Cost
($/yr)
3,841
1,204
$5,045
Disposal Cost
($/yr)
12,845
5,505
$18,350
Total Transp. +
Disp. Cost
16,686
6,709
$23,395
TOTAL OPTION 1 NSPS COST FOR
COMPLETION FLUIDS ($/YR):
$24,380
A-50
-------
EXISTING SOURCES/OPTIONS 2 & 3 FOR WORKOVER/TREATMENT
Input Data "' * „ , " , j -, /-<>">' - •.,—;--"'• ,- - _ >% ' *'" ,
Total 1992 number of wells discharging W/O,T fluids (Sect. XU.4.1.1):
Average 1992 volume of W/O,T fluid discharged per well/yr (bbl/yr) (SAIC, Jan 31, 1995):
Percentage of Water-Access Facilities (Sect. XH.4.1.1):
Percentage of Land-Access Facilities (Sect. XH.4. 1.1):
Percentage of Medium/Large Facilities (W/O,T fluids commingled with PW)
Percentage of Small Facilities that dispose of W/T fluids commercially (Sect. XH.4.1.2):
Cost to inject W/T fluids with produced water at water-access sites ($/bbl) (Sect. Xn.4.1.2):
Cost to inject W/T fluids with produced water at land-access sites ($/bbl) (Sect. XH.4.1.2):
Capacity of small-volume barge (bbls) (Sect. XH.4.1.3):
Assumed portion of barge used per job (i.e., 587 bbls per job require 1/2 of one barge):
Cost of Barge + Tug Transportation ($/round trip) (Sect. XH.4.1.3):
Cost of 50% of barge transportation ($/job) (Sect. XJJ.4.1.3):
Cost of vacuum truck transportation ($/bbl) (Sect. XU.4.1.3):
Commercial disposal cost for TWC fluids ($/bbl) (Sect. Xn.4.1.3):
'" ^ - ' "(' V
350
587
0.656
0.344
0.77
0.23
0.116
0.218
1500
0.5
1097.5
548.75
1.92
8.78
Zero Discoarge Costs at Medium/Lar^-^olume Facilities -- •
Facility Location
Water-Access
Land-Access
Total
No. W/O.C
Jobs/yr
177
93
270
jNo. Jobs/yr
Injected
; 177
93
270
Vol. Injected
(bbl/yr)
103,899
54,591
158,490
Injection Cost
($/yr)
.12,052
11,901
$23,953
Zero Discharge Cosis at Small- Volume FacOiiies - 5 L -„ '< "> : - ,
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
52
28
80
No. Jobs Dis-
posed
Commer'ly/yr
''• 52
28
80
Volume Disp'd
Comm'ly
(bbl/yr)
30,524
16,436
46,960
Transport 'n
Cost
($/yr)
28,535
31,557
$60,092
Disposal
Cost
($/yr)
268,001
144,308
$412,309
Total Transp.
+
Disp. Cost
296,536
175,865
$472,401
TOTAL ZERO DISCHARGE COST FOR
WORKOVER/TREATMENT FLUIDS ($/YR):
$496,354
A-51
-------
EXISTING SOURCES/OPTIONS 2 & 3 FOR COMPLETION FLUIDS
Input Data '?'-'/ J\ "'""*** \" ,' «. ,- ' ' ' 5' %!! ' *-' ,
Total 1992 number of wells discharging completion fluids (Sect. XE.4.1.1):
Average 1992 volume of completion fluid discharged per well/yr (bbl/yr)
(SAIC, Jan 31, 1995):
Percentage of Water-Access Facilities (Sect. XU.4.1.1):
Percentage of Land-Access Facilities (Sect. Xn.4.1.1):
Percentage of Medium/Large Facilities
Percentage of Small Facilities (dispose of completion fluids commercially,
Sect. XH.4.1.2):
Cost to inject completion fluids with produced water at water-access sites ($/bbl)
(Sect. XH.4.1.2):
Cost to inject completion fluids with produced water at land-access sites ($/bbl)
(Sect. Xn.4.1.2):
Capacity of small-volume barge (bbls) (Sect. XU.4.1.3):
Assumed portion of barge used per job (i.e., 209 bbls per job require 1/4 of one barge):
Cost of Barge + Tug Transportation ($/round trip) (Sect. XU.4.1.3):
Cost of 25% of barge transportation ($/job) (Sect. XH.4.1.3):
Cost of vacuum truck transportation ($/bbl) (Sect. XE.4.1.3):
Commercial disposal cost for TWC fluids ($/bbl) (Sect. XE.4.1.3):
* ~ 4 ^s
334
209
0.656
0.344
0.77
0.23
0.116
0.218
1500
0.25
1097.5
274.38
1.92
8.78
Injection Costs at Medium/Large-VblumeFaciaities*
Facility Location
Water-Access
Land-Access
Total
# Comp.
Jobs/yr
169
88
257
No. Jobs/yr
Injected
169
88
257
Vol. Injected/yr
(bbl)
35,321
18,392
53,713
Injection Cost
($/yr)
4,097
4,009
$8,106
f* .,,.«,,.,•/• fqr-. ^\f. jfjf _, / f f ', f 'S f t -.^ "., v X ' f •'•f f
Disposal Costs at Small-Volume Facilities '' ' " - ;; ' -'",'' ' '.. - "" " ' "/ /i, "',' ; ,/'
Facility Location
Water-Access
Land-Access
Total
No. Comp.
Jobs per yr
51
26
77
No. Jobs Disp.d
Commercially/yr
51
26
77
Volume Disp'd
Comm'ly
(bbl/yr)
10,659
5,434
16,093
Transport'n
Cost ($/yr)
13,993
10,433
$24,426
Disposal
Cost ($/yr)
93,586
47,711
$141,297
Total Transp.
+ Disp. Cost
107,579
58,144
$165,723
TOTAL INJECTION COST FOR
COMPLETION FLUIDS ($/YR):
$173,829
A-52
-------
NEW SOURCES/OPTIONS 2 & 3 FOR WORKOVER/TREATMENT FLUIDS
JaputBata '" V ™" , " ^ " ' =° " " " " .
Total number of wells discharging workover/treatment fluids (Sect. XH.4.1.1):
Average volume of workover/treatment fluid discharged per well/yr (bbl/yr)
(SAIC, Jan 31, 1995):
Percentage of Water-Access Facilities:
Percentage of Land-Access Facilities:
Percentage of Medium/Large Facilities
Percentage of facilities that dispose of W/T, fluids commercially:
Cost to inject W/T fluids with produced water at water-access sites ($/bbl):
Cost to inject W/T fluids with produced water at land-access sites ($/bbl)
(Sect. XH.4.1.2):
Capacity of small-volume barge (bbls) (Sect. XH.4.1.3):
Assumed portion of barge used per job (i.e.; 587 bbls per job require 1/2 of one barge):
Cost of Barge + Tug Transportation ($/rouhd trip) (Sect. Xn.4.1.3):
Cost of 50% of barge transportation ($/job) (Sect. XH.4.1.3):
Cost of vacuum truck transportation ($/bbl) (Sect. Xn.4.1.3):
Commercial disposal cost for TWC fluids ($/bbl) (Sect. XH.4.1.3):
45
587
0.656
0.344
0.77
0.23
0.116
0.218
1500
0.5
1097.5
548.75
1.92
8.78
Zero Discharge Costs for Medium/Large FacOitfe , ' " ''' ' -
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
23
12
35
No!. Jobs/yr
Injected
23
: 12
i 35
Vol. Injected
(bbl/yr)
13,501
7,044
20,545
Injection Cost
($/yr>
1,566
1,536
$3,102
' ' ^ • ^ f ' ^ f f f '•. :•-'. w. - ff •. ff ^ ^ ;. f " •> V>AJ.%X 1. _^ .
Zero Discharge Costs for SmalOaeilities , „ ,„,„,,. „ mi, „„,„,-*,„ ,„ „„ ,* , 4 , \, "
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
7
3
10
No. Jobs Disp'd
Commer'ly/yr
; 7
3
10
Volume Disp'd
Comm'ly
(bbl/yr)
4,109
1,761
5,870
Transport'n
Cost ($/yr)
3,841
3,381
$7,222
Disposal
Cost ($/yr)
36,077
15,462
$51,539
Total Transp.
+
Disp. Cost
39,918
16,666
$58,761
TOTAL OPTION 2 & 3 NSPS COST FOR
WORKOVER/TREATMENT FLUIDS ($/YR):
$61,863
A-53
-------
NEW SOURCES/OPTIONS 2 & 3 FOR COMPLETION FLUIDS
IhputData .'. $^\>&£$SJ&/^ * *';>;, / ^ '-. * ' % ' *'-/' ;
Total number of wells discharging workover/treatment fluids (Sect. xn.4. 1.1):
Average volume of completion fluid discharged per well/yr (bbl/yr) (SAIC, Jan 31, 1995):
Percentage of Water-Access Facilities:
Percentage of Land-Access Facilities:
Percentage of Medium/Large Facilities
Percentage of facilities that dispose of W/T fluids commercially:
Cost to inject W/T fluids with produced water at water-access sites ($/bbl):
Cost to inject W/T fluids with produced water at land-access sites ($/bbl) (Sect. Xn.4.1.2):
Capacity of small-volume barge (bbls) (Sect. XE.4.1.3):
Assumed portion of barge used per job (i.e., 587 bbls per job require 1/2 of one barge):
Cost of Barge + Tug Transportation ($/round trip) (Sect, xn.4.1.3):
Cost of 50% of barge transportation ($/job) (Sect, xn.3.1.3):
Cost of vacuum truck transportation ($/bbl) (Sect. XH.4.1.3):
Commercial disposal cost for TWC fluids ($/bbl) (Sect. XH.4.1.3):
45
209
0.656
0.344
0.77
0.23
0.116
0.218
1500
0.5
1097.5
548.75
1.92
8.78
Zero Discharge Costs for Mediuni/la?ge"Facnilie^'"vrrVw ^ \^ /"'/-, '\ .
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
23
12
35
No. Jobs/yr
Injected
23
12
35
Vol. Injected
(bbl/yr)
4,807
2,508
7,315
Injection Cost
($/yr)
- 558
547
$1,105
Zero Discharge Costs for SmaD FacmtieS^f ™^ '" \p V" - $«">"*', '-"'*.., ', ',, & ', ', -/ /, /"
Facility Location
Water-Access
Land-Access
Total
No. W/T
Jobs/yr
7
3
10
No. Jobs Disp.d
Commercially /yr
7
3
10
Volume Disp'd
Comm'ly (bbl/yr)
1,463
627
2,090
Transport1 n
Cost ($/yr)
3,841
1,204
$5,045
Disposal Cost
($/yr)
12,845
5,505
$18,350
Total Transp.
+
Disp. Cost
16,686
6,709
$23,395
TOTAL OPTION 2 & 3 NSPS COST FOR
COMPLETION FLUIDS ($/YR);
$24,500
A-54
-------
APPENDIX Xn-2
TWC POLLUTANT REMOVALS CALCULATIONS
A-55
-------
ANNUAL POLLOTANT REMOVALS; OPTION1 FOR EXISTING SOURCES OF WORKOV1R/TREATMENT FLUIDS
Pollutant Parameter
Conventional:
Oil & Grease
Solids, Total Suspended
Total Conventional?
Priority Poll, Orgardcs
Benzene
Ethylbenzene
Methyl Chloride
(Chloromethane)
Toluene
Fluorene
Naphthalene
Phenanthrene
Phenol
Total P.P. Organlcs
Priority Poll. Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total P.P. Metals
CoDcetrtrollonO'g/l)
Current-Level
• Effeat
231,688,00
320,375,00
1,341,00
1,149.00
29,00
891.00
62.00
525.00
64.00
263.00
29.60
166.00
8.64
26.08
616.82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94
Gas Flotation
, Effluent
23,500,00
30,000.00
1,225.91
62.18
29.00
827.80
62.00
92.02
64.00
263.00
29.60
73.08
8.64
14,47
616.82
277.20
124,86
115.52
42.94
1.60
13.46
133.85
Zero Dlsch.
Etfluent
0.00
0.00
0.00
0,00
0.00
0.00
0.00
0.00
0.00
0,00
0,00
0.00
0.00
0,00
0,00
0,00
0.00
0.00
0.00
0.00
0.00
0.00
Vol.
Currently
WscbargMl
(hhls)
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079 '
186,079
186,079
186,079
186,079
186,079
186,079
186,079
Vol. Using
IGF
(bbls)
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
Vol. Using
Zero Discli.
(bbls)
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
Loading (Ibs)
Curr.-Lcvd
. Effluent .
15,078
33,865
48,943
87
75
2
58
4
34
4
17
281
2
11
1
2
40
18
90
8
3
0
1
24
200
GasFtot'n
OTuent :
121
154
275
6
0
0
4
0
0
0
1
11
0
0
0
0
3
1
1
1
0
0
0
1
7
Zero Discli.
Effluent
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
Removals
flbs)
Incrementnl
14,957
33,711
48,663
81
75
2
54 '
4
34
4
16
270
2
11
1
2
37
17
89
7
3
0
1
23
193
-------
ANNUAL POLLUTANT REMOVALS: OPTION 1 FOR EXISTING SOURCES OF WORKOVER/TREATMENT FLUIDS
'V-iV'. ,'' -Y*»v''
-^|a^;j
Non-Conventionals
Aluminium
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylenes
4-Melhyl-2-Pentanone
Dibenzofuran
Dibenzothiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane (N-C12)
N-Eicosane (N-C20)
N-Hexacosane (N-C26)
N-Hexadecane (N-C16)
N-Octacosane (N-C28)
N-Octadecane (N-C18)
N-Tetracosane (N-C24)
N-Tetradecane (N-C14)
P-Cymene
Penlamethylbenzene
1-Methylfluorene
2-MethyInaphthalene
-',;!-- <-• -~ t •>•>-"'•'•„- 'jf ^--^ '!"-
. < ., * -.••'? *• o<- ^ 'Ct0tt£^fltJ3m0& u%|} '•> * -•-- •> •• ' ~ .•
*'->Giirre&t>'Leyel '
6,468.40
498.10
15,042.00
10,284,000.00
8.18
52.00
384,412.00
5,146.00
5,052,280:00
63.00
18,886,000.00
142,720.00
245,300.00
27.00
74.58
1,156.00
41.92
7,205.00
58.00
2,675.00
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
Tot. Non-Conventionals
--•'Gas Flotation*
."Jifefflul^f;'
49.93
498.10
15,042.00
10,284,000.00
8.18
52.00
3,146.15
74.16
5,052,280.00
63.00
18,886,000.00
142,720.00
245,300.00
27.00
4.48
1,156.00
41.92
7,205.00
58.00
378.01
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
Grand Total Pollutant Loadings/Removals
;-Ze,rpXHsch.j
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
*'\ '"- ' * ' * f'
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
o'^ok Using *
, slip? (bb)|}/
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
14,675
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
171,404
, , ' •>' "v\ - - -f » A:- '-')tt:\'S-fi ,4 * ': -
' ••- .. '**' •• ? vk^wPg (WSJ o , ^ v% - ,
-*•> Effluest'* ' ~
421
32
979
669,264
1
3
25,017
335
328,793
4
1,229,066
9,288
15,964
2
5
75
3
469
4
174
197
9
7
18
50
37
15
31
26
14
70
52
81
5
4
5
53
2,280,573
2,329,997
* '
0
3
77
52,781
0
0
16
0
" 25,930 '
0
96,929
732
1,259
0
0
6
0
37
0
2
16
1
1
1
4
3
1
2
2
1
6
4
6
0
0
0
4
177,824
178,117
-''•Effluent »
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
'• tt ''• *i'"'<^A*s
TT^y^V^^Cv^J' S
rfS^ij
421
29
902
616,483
1
3
25,001
335
302,863
4
1,132,137
8,556
14,705
2
5
69
3
432
4
172
181
8
6
17
46
34
14
29
24
13
64
48
75
5
4
5
49
2,102,749
2,151,880
-------
ANNUAL POLLUTANT REMOVALS: OPTION 1 FOR EXISTING SOURCES OF COMPLETION FLUIDS
Pollutant Parameter
Conventional!
Oil & Grease
Solids, Total Suspended
Total Conventional!
Priority Poll. Organlcs
Benzene
Ethylbenzene
Methyl Chloride
(Chloromethane)
Toluene
Fluorene
Naphthalene
Phenanthrene
Phenol
Total P.P. Organics
Priority Poll. Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total P.P. Metals
Concentration fag/l)
Current-Level
Effluent
231,688.00
520,375.00
1,341.00
1,149.00
29.00
891.00
62.00
525.00
64.00
263.00
29.60
166.00
8.64
26.08
616.82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94
G 35 Flotation
Effluent
23,500.00
30,000.00
1,225.91
62.18
29.00
827.8
62.00
92.02
64.00
263.00
29.60
73.08
8.64
14.47
616.82
277.20
124.86
115.52
42.94
1.60
13.46
133.85
Zero Dlsch.
Effluent
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Vol. Cur-
really
Discharged
(bbls)
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
•Vol. Using
IGF
(bbls)
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
Vol. Using
Zero Dlsch.
(bbls)
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
Loading (llw)
Curr.-Level
Effluent
5,114
11,487
16,601
30
25
1
20
1
12
1
6
96
1
4
0
1
14
6
30
3
1
0
0
8
68
Gas Flot'n
Effluent
40
50
90
2
0
0
1
0
0
0
0
3
0
0
0
0
1
0
0
0
0
0
0
0
1
Zero Dlsch,
Effluent
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
Removals (Ihs)
Incremental
5,074
11,437
16,511
28
25
1
19
1
12
1
6
93
1
4
0
1
13
6
30
3
1
0
0
8
67
I
-------
ANNUAL POLLUTANT REMOVALS: OPTION 1 FOR EXISTING SOURCES OF COMPLETION FLUIDS (Continued)
' Pollutant Parameter ,
Non-Conventionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylenes
4-Melhyl-2-Pentanone
Dibenzoturan
Dibenzothiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane (N-C12)
N-Eicosane (N-C20)
N-Hexacosane (N-C26)
N-Hexadecane (N-C16)
N-Octacosane (N-C28)
N-Octadecane (N-C18)
N-Tetracosane (N-C24)
N-Tetradecane (N-C14)
P-Cymene
Pentamethylbenzene
1-Methylfluorene
2-Methylnaphthalene
f •- ''**'; , ,,,," ' " .
* „ , • »^9' '«*Is). ',
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
4,807
"
' Vol: Using
'.^tef "
r >t J*
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311-
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
58,311
, '' " , ',*',-,--
- ,, ',- Loading Otis) - t'V
"Cuny-Levei
143
11
332
227,014
0
1
8,486
114
111,527
1
416,899
3,150
5,415
1
2
26
1
159
1
59
67
3
2
6
17
13
5
11
9
5
24
18
27
2
1
2
18
773,572
790,337
/GasFIot'n
0
1
25
17,289
0
0
5
0
8,494
0
- 31,751
240
412
0
0
2
0
12
0
1
5
0
0
0
1
1
0
1
1
0
2
1
2
0
0
0
1
58,247
58,341
Zero Dfech.
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
JL"- '•> ''( --it, % ^
Removals flbs)
• Incremental ,
143
10
307
209,725
0
1
8,481
114
103,033
1
385,148
2,910
5,003
1
2
24
1
147
1
58
62
3
2
6
16
12
5
10
8
5
22
17
25
2
1
2
17
715,325
731,996
-------
ANNUAL POLLUTANT REMOVALS; OPTION 1 FOR NEW SOURCES OF WORKOVER/TREATMINTIMJTOS
Pollutant Parameter
Convcnllonals
Oil & Grease
Solids, Total Suspended
Total Conventlonnls
Priority Poll. Organlcs
Benzene
Ethylbenzene
Methyl Chloride
(Chloromahanc)
Toluene
Fluorene
Naphthalene
Phenanthiene
Phenol
Total P.P. Organics
Priority Poll. Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
SUver
Thallium
Zinc
Total P.P. Metals
C CKWsnl ration (w£/1)
Current-Level
Effluent
231,683.00
520.37S.OO
1,341.00
1,149.00
29.00
891.00
62,00
S2S.OO
64.00
263.00
29.60
166.00
8.64
26.08
616,82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94
Gas Flotation
Effluent
23,500.00
30,000.00
1,225.91
62.18
29.00
827.8
62.00
92.02
64.00
263.00
29.60
73.08
8.64
14.47
616.82
277.20
124.86
115.52
42.94
1.60
13.46
133.85
ZeroDbcta.
Eltln«nt
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Tola!
Volume
(bbls)
24,654
24,654
24,654
24,654
24,04
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
Vollfctog
TOP
(bbls)
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
Yol,tJstBg
Zero Dbch,
(l)bU)
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
22,893
Loading (Ibs)
Ciirr.-X.evd
Effluent
1,998
4,487
6,485
12
10
0
g
1
5
1
2
39
0
I
0
0
5
2
12
1
0
0
0
3
24
Gas Flot'n
Effluent
14
18
32
1
0
0
1
0
0
0
0
2
0
0
0
0
0
0
0
0
0
0
0
0
0
ZcroDkch.
Effluent
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
Removals
WM)
Incremental
1,984
4,469
6,453
11
10
0
7
I
5
1
2
37
0
1
0
0
5
2
12
1
0
0
0
3
24
-------
ANNUAL POLLUTANT REMOVALS: OPTION 1 FOR NEW SOURCES OF WORKOVER/TREATMENT FLUIDS (Continued)
/• ?X -- -».!*:
Non-Conventionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylenes
4-Methyl-2-Pentanone
Dibenzofuran
Dibenzothiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane (N-C12)
N-Eicosane (N-C20)
N-Hexacosane (N-C26)
N-Hexadecane (N-C16)
N-Octacosane (N-C28)
N-Octadecane (N-C18)
N-Telracosane (N-C24)
N-Tetradecane (N-C14)
P-Cymene
Pentamethylbenzene
l-Methylfluorene
2-Methylnaphthalene
: D:; «.: ;£™*?1^ ifjj'i ;: ;;; :";
''currS^Uvel^
I ''"Efflffiarf # "
6,468.40
498.10
15,042.00
10,284,000.00
8.18
52.00
384,412.00
5,146.00
5,052,280.00
63.00
" 18,886,600.00
142,720.00
245,300.00
27.00
74.58
1,156.00
41.92
7,205.00
58.00
2675
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
Tot. Non-Conventionals
;G~4'Mbtatfe«f'
f *v]f£fBue»it' ;" *
49.93
498.10
15,042.00
10,284,000.00
8.18
52.00
3146.15
74.16
5,052,280.00
63.00
"18,886,000.00
142,720.00
245,300.00
27.00
4.48
1,156.00
41.92
7,205.00
58.00
378.01
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075,00
801.00
1,237.00
72.00
54.00
82.00
817.00
Grand Total Pollutant Loadings/Removals
'WtfoStr.,
iMuenii ':
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
: \3xifti >$.
:-%n$J£>?
"T " ,- ,.". , It
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
^A., < ,\'ft
i,yfl. Using |
Vj^fl)''^
,•>./<. :.-,-,%
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761"
1,761
1,761
1,761
•* ff 'v , < *
' VolcUsHij^S
^,.-
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
•< ,,,!• ">,-%>.
Removals s:
! '/vVc- -
'!r?r*-HeR*?''
56
4
121
82,338
0
0
3,313
44
40,450
- - . .1 .
151,210
1,143
1,964
0
1
9
0
58
1
23
24
1
1
2
7
5
2
4
3
2
8
7
10
1
0
1
6
280,820
287,334
-------
ANNUAL POLLUTANT REMOVALS: OPTION 1 FOR NEW SOURCES OF COMPLETION FLUIDS
Pollutant Parameter
Conventional;
Oil & Grease
Solids. Total Suspended
Total Conventional*
Priority Poll. Organks
Benzene
Ethylbenzene
Methyl Chloride
(Chloromethane)
Toluene
Fluorene
Naphthalene
Phenanthrene
Phenol
Total P.P. Organics
Priority Poll. Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total P.P. Metals
Concentration (ftg/l)
Current-Level
Effluent
231,688.00
520,375.00
1,341.00
1,149.00
29.00
891.00
62.00
525.00
64.00
263.00
29.60
166.00
8.64
26.08
616.82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94
Gits Flotation
Effluent
23,500.00
30.000.00
1,225.91 .
62.18
29.00
827.8
62.00
92.02
64.00
263.00
29.60
73.08
8.64
14.47
616.82
277.20
124.86
115.52
42.94
1.60
13.46
133.85
ZeroDIscb.
Effluent
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Total
Volume
(bWs)
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
Vol. Using
IGF
(bbls)
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
Vol. Using
Zero Dlsch.
(bbb)
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
Loading (tbs)
Curr.-Level
Effluent
711
1,598
2,309
4
4
0
3
0
2
0
1
14
0
1
0
0
2
1
4
0
0
0
0
1
9
GnsFlot'n
Effluent
5
7
12
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Zero Dlsch.
Effluent
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
Removals
(Ibs)
Increroenta
70<
1.591
2,29:
<
i
(
(
\
(
1'
(
(
(
-
(
(
(
(
<
-------
ANNUAL POLLUTANT REMOVALS: OPTION 1 FOR NEW SOURCES OF COMPLETION FLUIDS (Continued)
•Cil-5 V// ',',,*,>,- \™'*>
|*?;|: J|v-! , ; ; * «, t t* t
1 ' ' J^Hutant Parameter < i
AMS:;' -'<• $•»<*:•/-*
Non-Conventionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylenes
4-Methyl-2-Pentanone
Dibenzoftiran
Dibenzothiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane (N-C12)
N-Eicosane (N-C20)
N-Hexacosane (N-C26)
N-Hexadecane (N-C16)
N-Octacosane (N-C28)
N-Octadecane (N-C18)
N-Tetracosane (N-C24)
N-Tetradecane (N-C14)
P-Cymene
Pentamethylbenzene
1-Methylfluorene
2-Methylnaphthalene
/ - - >-',„ , > v, ,- t- * -'* , x '•-'" > ° -t .' '<. '*y
y? :/>„ |I' 4~" vl|«^%%KM!£ ' ^ s I
;"°, ^YV^S
£S!!L"V
6,468.40
498.10
15,042.00
10,284,000.00
8.18
52.00
384,412.00
5,146.00
5,052,280.00
63.00
18,886,000.00
142,720.00
245,300.00
27.00
74.58
1,156.00
41.92
7,205.00
58.00
2675
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
Tot. Non-Conventionals
,v^' "x ,„„'
SMit*".
49.93
498.10
15,042.00
10,284,000.00
8.18
52.00
3146.15
74.16
5,052,280.00
63.00
18,886,000.00
142,720.00
245,300.00
27.00
4.48
1,156.00
41.92
7,205.00
58.00
378.01
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
Grand Total Pollutant Loadings/Removals
? 'ft -' -*,'-Iii, *
^'laftuenfc \
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
- ',ilf\-/' ^'
^ < - '•! '•-.' ',-. '1
f <-, Total -
' _\ ->•. v>
yt ^yoiumfe^ ^
r^f-'r
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
/*<*,*.» i
^'VX^"--^'
t Vol.' using £
'! '.,. ^" ?* S
^ (b^J|)''t'
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
% . -,<-> < (^ "ffii
,tv6l/XJsrag,,
4%$*J$f¥r'~
r^?K.;j;
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8.T51
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
8,151
,-'., ;*^ .>,--)' * '"* -': ^,r«v, "/?"=>; ~-»
" f ; : r*c r ,-| M?"? ?^C !* % ;»r ~t
A- ' ' '"•• '•
-^ju^|?l,
20
2
46
31,572
0
0
1,180
16
15,510
0
57,979
438
753
0
0
4
0
22
0
8
9
0
0
1
2
2
1
1
1
1
3
2
4
0
0
0
3
107,580
109,912
•i. ^ ' ' '
KEWlueni ''
0
0
3
2,255
0
0
1
0
1,108
0
4,141
31
54
0
0
0
0
2
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
7,596
7,608
t ''* ' ' "•
viaffari!?'*
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
£•' *•<.'•:
* * Si'
f '•.*,"' ;
,%-ren^ta
a
4
29,31'
1
1
1,17!
ti
14,40:
1
53,83!
40'
69!
1
1
,
1
21
1
]
1
1
i
(
(
(
99,98<
102,30'
-------
ANNUAL lOLLOTANT REMOVALS: OPTIONS 2 AND 3 FOR EffliMNe OF WOMCO'VER/TREAfMENT FLUIDS
Pollutant Ponrmcter
Conventional
Oil & Grease
Solids, Total Suspended
Total Conventional:
Priority Pollutant
Organ! cs
Benzene
Ethylbenzene
Methyl Chloride
(Chloromethane)
Toluene
Fluorene
Naphthalene
Phenanthrene
Phenol
Total P.P. Organlcs
Priority Pollutant Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total P.P, Metals
Flora & Rucks (IGF to zero disdiarpc)
Cwwentarttan (pg/0
Current-Level
EtniWDf-w
23,500.00
30,000,00
1,225,91
62,18
29.00
827,80
62.00
92,02
64.00
263.00
29.60
73.08
8.64
14.47
616.82
277.20
124.86
115,52
42.94
1.60
13.46
133.85
Trejrfment-tevel
Effluent
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0,00
0,00
0.00
0.00
0.00
0.00
0.00
Volume
Currently
Discharged
(bbls)
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
All others (scl Illng effluent to zero discharge)
Concentration (pgfl)
Current-Level
Effluent
231,688.00
520,375.00
1,341.00
1,149.00
29,00
891.00
62.00
525.00
64.00
263.00
29.60
166.00
8.64
26.08
616.82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94
Treatment-Level
Effluent
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0,00
0,00
0.00
0.00
0.00
0,00
0.00
0,00
0.00
0.00
0.00
0.00
0.00
Volume
Cunxntly
Discharged
(obis)
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
186,079
Loadings 0bs)
Current-Lev
el
Effluent
15,237
34,068
49,305
96
75
2
64
4
35
5
19
300
2
11
1
2
44
20
90
8
3
0
1
25
207
Treat-Level
Effluent
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
Removals
fthiA
yDsj
Incremental
15,237
34,068
49,395
96
75
2
64
4
35
5
19
300
2
11
1
2
44
20
90
8
3
0
1
25
207
(a) Concentrations in this column are from the Offshore Development Document
(b) For the purpose of regulatory analysis, these concentrations arc substituted using the settling effluent concentrations either because no data were available in the Offshore Development
Document or because the Offshore Gas Flotations value was greater than the settling value.
-------
ANNUAL POLLUTANT REMOVALS: OPTIONS 2 AND 3 FOR EXISTING SOURCES OF WORKOVER/TREATMENT FLUIDS (Continued)
,- * "' ,- '
* Pollutant PSTStttcler
r v* ' * * *• '
Non-convenlionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylenes
4-Methy!-2-Pentanone
Dibenzofuran .
Dibenzothiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane (N-C12)
N-Eicosane (N-C20)
N-HeMcosane(N-C26)
N-Hexadecane(N-C16)
N-Octa«isane(N-C28)
N-Ocladecane (N-CI8)
N-Tetracosane (N-C24)
N-Tetradecane(N-C14)
P-Cymene
Pentamethylbenzene
1-Melhylfluorene
2-Metliylnapbtlialene
Total Non-Conventionals
Hires SKucisHSFto wo dllsciajrgej ; *
\'~\ ** Concentration ©g/1)
Vwrent-ilftr
, Efflupnf1*'1" ' %
49.93
498.10
15,042.00
10,284,000.00
8.18
52.00
3,146.15
74.16
5,052,280.00
63.00
18,886,000.00
142,720.00
245,300.00
27.00
4.48
1,156.00
41.92
7,205.00
58.00
378.01
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
Treatment-level ,
fittlnmf
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
... .. o.oo
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Volume Cursrently
- JMSchatgefl -
% AKIeV
% / {DDJSJ ^ , f
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19371
19,371
19,371
19,371
19,371.
19,371
19,371
19,371
19,371
19.371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
19,371
» ' All'otheBWfflteeflltrtottMel
v' Ctraeen
-------
ANNUAL POLLUTANT REMOVALS: OPTIONS 2 AND 3 FOR EXISTING SOURCES OF COMPLETION FLUIDS
PeHutimt Parameter
Conveolfonats
Oil & Grease
Solids, Total Suspended
Hottt & Rucks <1GF to zero dtenarec)
Cmccnrratton (fijfl)
Currcnt-Ltrcl
RfnnmrW
23500
30000
TrtalratnMcKl
RrfUrtiif
0
0
Total Conventional!
Priority Pollutant Organic*
Benzene
Ethylbcnzene
Methyl Chloride
(Chlorometlune)
Toluene
Fluorcnc
Naphthalene
Phenanlhrene
Phenol
Total P. P. Organic:
Priority Pollutant Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
1225.91
62.18
29
827.80
62.00
92.02
64.00
263.00
29.60
73.08
8.64
14.47
616.82
277.20
124.86
115.52
42.94
1.60
13.46
133.85
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Volume Currently
Discharged
(bob)
6,688
6.688
All othrrs feel** effluent to urn dlKtarK)
Concentration ((i|/l)
Cumnl-Letel
Effliiiftf
231,688.00
520,375.00
TraHracnt-Urtl
WHuwI
0
0
Volume
Currently
Discharged
(bilk)
63,118
63.118
Loadings 0b9)
Currtnt-Levd
rcmifent
5.169
11,557
18,360
6.688
6.6S8
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
1,341.00
1,149.00
29.00
891.00
62.00
525.00
64.00
263.00
29.60
166.00
8.64
26.08
616.82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
32
26
1
22
2
12
2
6
Tr«l.-L
-------
ANNUAL POLLUTANT REMOVALS: OPTIONS 2 AND 3 FOR EXISTING SOURCES OF COMPLETION FLUIDS (Continued)
* ',""• 7 -. V" % * v < '
^^t£i^.wr,
~ , * '^ ^ " « ,' * *
'\ ,- '. " % * * <* ' « " ,, i
Non-Coavenftonals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylenes
4-Methyl-2-Pentanone
Dibenzoturan
Dibenzolhiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane(N-C12)
N-Eicosane(N-C20)
N-Heiacosane(N-C26)
N-Hejadecane(N-C16)
N-Octacosane (N-C28)
N-Octadecane(N-ClS)
N-Tetracosane (N-C24)
N-Tetradecane(N-C14)
P-Cymene
Pentamethylbenzene
1-Melhylfluorene
2-Melhylnaphthalene
Total Non-Conventional!
* v <• ^nol^&RtfcIs (IGI|>t0££?0.di£cliarge'} ;•;<$*„<, ?
»' ;7^te»ir,;&|4H^
*s'< *' '?*
% Current-bevel
*, ,im,,«,iS.>> *
49.93
498.10
15,042.00
10,284,000.00
8.18
52.00
3,146.15
74.16
5,052,280.00
63.00
18,886,000.00
142,720:00
245,300.00
27.00
4.48
1,156.00
41.92
7,205.00
58.00
378.01
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
Grand Total Pollutant Loadlng5\Removals
^ ^ * * ^ •. *
'. '-1 KnUUHftco.!
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
|;jM»m?:l
>yX)tgc1)flt!&ect. /
,.X - 'dBfsf - ." '
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6i688"
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
6,688
* v "v , ,,f jUi oHier&lseitlihg gftlueAi iQ^ejCo^dbfibjFge) <.,x^gd)fv f ^ f *
Cur^g)ii-JLe.yei ' v
\'.', ^~RfFluent ,"S
6,468.40
498.10
15,042.00
10,284,000.00
8.18
52.00
384,412.00
5,146.60
5,052,280.00
63.00
18,886,000.00
"142,720.00"
245,300.00
27.00
74.58
1,156.00
41.92
7,205.00
58.00
2,675.00
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
•*K^eafnierrt-L§Vel" ,
* .fcnfifnit 'f*°
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
IfjwB^;
Y ^Dijchaf ged f '
i $ AfUblsfc- - ;•
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
63,118
si 4 "<. 1% '/* ^ * \[^ \ I ••••
|g;\ ?*?£$? V,:^
* Cur&ht-i#ve"I *
*$ - Effluent %- -! '
143
12
367
251,069
0
1
8,493
114
123,344
2
461,074
3,484
5,989
1
2
28
1
176
1
60
74
3
3
7
19
14
6
12
10
5
26
20
30
2
1
2
20
857,222
875,759
'.•irjce&ktJiiaV'et..
' IMilMlf "•
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
-. * \ ,. '* *
-ft*?****:
<1 •• i ^ ' * '*. ,
-, {ncfefltenlal ,^
143
12
367
251,069
0
I
8,493
114
123,344
2
461,074
3,484
5,989
1
2
28
1
176
1
60
74
3
3
7
19
14
6
12
10
5
26
20
30
2
1
2
20
857,222
875,763
(a) Concentrations in this column are from the Offshore Development Document
(b) For (lie purpose of regulatory analysis, these concentrations are substituted using the settling effluent concentrations either because no data were available in the Offshore Development Document or because the Offshore Gas
Flotation value was greater than the settling effluent value.
-------
ANNUAL POLLUTANT REMOVALS: OPTIONS 2 AND 3 FOR NEW SOURCE OF WORKOVER/TREATMENT FLUIDS
Pollutant Parameter
Conventional:
Oil & Grease
Solids. Total Suspended
Total Conventional*
Priority Pollutant Organic:
Benzene
Eihylbenzene
Methyl Chloride
(Chloromethane)
Toluene
Fluorene
Naphthalene
Phenanthrene
Phenol
Total P.P. Organics
Priority Pollutant Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total P.P. Metals
Flora & Rucks (IGF to zero discharge)
Concentration Oijfl)
Current-Level
Effluent**
23,500.00
30,000.00
1,225.91
62.18
29.00
827.80
62.00
92.02
64.00
263.00
29.60
73.08
8.64
14.47
616.82
277.20
124.86
115.52
42.94
1.60
13.46
133.85
Treatment-
Level Effluent
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Volume
Currently
Discharged
(bbls)
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
All others (tetUtng effltcent to zero discharge)
Concentration (fjg'l)
Current-Level
Effluent
231,688.00
520.375.00
1,341.00
1,149.00
29.00
891.00
62.00
525.00
64.00
263.00
29.60
166.00
8.64
26.08
616.82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94
Treatment-Level
Effluent
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Volume
Currently
Discharged
(bbls)
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
Loading; (Ibs)
Current-Level
Effluent
2,012
4,505
6,517
12
10
0
8
1
5
1
2
39
0
1
0
0
6
3"
12
1
0
0
0
3
26
Treatmenl-Lercl
Effluenl
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
Removals (Ibs)
Incremental
2,012
4,505
6,517
12
10
0
8
1
5
1
2
39
0
1
0
0
6
3
12
1
0
0
0
3
26
(a) Concentrations in this column are from the Offshore Development Document.
(b) For the purpose of regulatory analysis, these concentrations are substituted using the settling effluent concentrations either because no data were available in the Offshore Development Document or because the Offshore Gas
-------
i i rumvivj v
\jrii\jn& 4 unit j rvjjx nay*
vvvjivivvj vn/iv
CL/UU/O vvuiuuiueaj
t;v*"t*-V* ••"-*••- '~;;
",<)»<.;»"?, >-.',<,- j j ' *
« - * IfollnfaHt-fafainetwi^' -
'/x% '^~ '-'-.-•*• * A .. 1 * '1 •* t v<-v.-
Non-Conrentionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
-Molybdenum - - -
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylenes
4-Methyt-2-Pentanone
Dibenzofuran
Dibenzothiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane (N-C12)
N-Eicosane (N-C20)
N-Hexacosane (N-C26)
N-Hexadecane (N-C16)
N-Octacosane (N-C28)
N-Octadecane (N-C18)
N-Tetracosane (N-C24)
N-Tetradecane (N-C14)
P-Cymene
Pentamethylbenzene
l-Methylfluorene
2-Methylnaphthalene
Total Non-Conventionals
Grand Total Pollutant Loading
'^;:W**
, , .,',. , ^-...<-<
-xr-^w??*
CattenirlefA
^E(ttueh£*8'l>^ •- '
49.93
498.10
15,042.00
10,284,000.00
8.18
52.00
3,146.15
74.16
5,052,280.00
-63.00
18,886,000.00
142,720.00
245,300.00
27.00
4.48
1,156.00
41.92
7,025.00
58.00
378.01
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
^/Removals
^ v *
**« *** f' * "'•
t|on'(ff'l>v''- •.
*,Tre'sWnt- *
'-liraFEmriSnt
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
- 0.00 -
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00 '
0.00
0.00
,ks»*ste)v:
w- ^, -
^OWw' *
'^fecta^v
;. cv° (Bbls)*'vv
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
1,761
,t :|MB^-
v •;; - !> , A.
» <- ,,-VlWP
*Ctoenli«veV
••" * 'Effiuftft' '-
6,468.40
498.10
15,042.00
10,284,000.00
8.18
52.00
384,412.00
5,146.60
5,052,280.00
63.00
18,886,000.00
142,720.00
245,300.00
27.00
74.58
1,156.00
41.92
7,205.00
58.00
2,675.00
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
ettog effluent t^
t , &f tlf j, , ,o^»
w°^W'J,^ '^
n&frn#l/nA
" * fefflm>fit *' ; *
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00 -
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
&»'4*!Mtl6)''.,
^ ''~\ /> & w« ^S"5
gyoiume^-.^
» Discharged !<
' '-• (bbls)^ r \f*
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
24,654
'* #'*. $ '?\ *,*
• >/„ > . %t. /""?" '••
' ',Cnrrent«Ley|l '•
' ••* Efflitent ®$ f
56
5
139
95,006
0
0
3,316
44
46,674
1
174,473
1,318
2,266
0
1
11
0
67
1
23
28
1
1
3
7
5
2
4
4
2
10
7
11
1
0
1
8
323,496
330,078
-i > , , ,.;*-
•>" ^ ' ",.. * ; ,
38^8),', !!,!,.,',
^Utaent-IJYel
'•• '' •• ^EfRfietit * 3 '*'
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
45^:^:;
^ksmoMs.flfel'
' " ."•?-' :'.'
.,V;Y'*' ,\
- '*> ^cF*ra®?' * -^
56
5
139
95,006
0
0
3,316
44
46,674
-1
174,473
1,318
2,266
0
1
11
0
67
1
23
28
1
1
3
7
5
2
4
4
2
10
7
11
1
0
1
8
323,496
330,078
(a) Concentrations in this column are from (he Offshore Development Document.
(b) For the purpose of regulatory analysis, these concentrations are substituted using the settling effluent concentrations either because no data were available in the Offshore Development Document or because the Offshore Gas
Flotation value was greater than the settling effluent value.
-------
ANNUAL POLLUTANT REMOVALS: OPTIONS 2 AND 3 FOR NEW SOURCES OF COMPLETION FLUIDS
Polluton! Parameter
Conventional:
Oil & Grease
Solids, Total Suspended
Tout Convenlkmals
Priority Pollutant Organic:
Benzene
Elhylbenzene
Methyl Chloride
(Chloromethane)
Toluene
Fluorene
Naphthalene
Phenanthrene
Phenol
Total P.P. Organics
Priority Pollutant Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total P.P. Metals
Floras & Rucks (IGF to zero discharge)
Concentration (pgfl)
Current-Level
Effluent'1*'
23,500.00
30,000.00
1,225.91
62.18
29.00
827.80
62.00
92.02
64.00
263.00
29.60
73.08
8.64
14.47
616.82
277.20
124.86
115.52
42.94
1.60
13.46
133.85
Treatment-
Level Effluent
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Volume
Discharged
(bbls)
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
All others (settling effluent to zero discharge)
Concentration (
-------
Pollutant Parameter- .
" ' " ,'/•'-'
<•,--","-
/- -' ':!\,
Non-Conventionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide, Total
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone
(2-Butanone)
Total Xylencs
4-Methyl-2-Pentanone
Dibenzofuran
Dibenzolhiophene
N-Decane (N-C10)
N-Docosane (N-C22)
N-Dodecane (N-C12)
N-Eicosane (N-C20)
N-Hexacosane (N-C26)
N-Hexadecane (N-C16)
N-Octacosane (N-C28)
N-Octadecane (N-C18)
N-Tetracosane (N-C24)
N-Tetradecane (N-C14)
P-Cymene
Pentamelhylbenzene
l-Methylfluorene
2-MethylnaphthaIene
Total Non-Conventionals
Grand Total Pollutant Loading1
>/ » - « /-,
' • * '' f\ i*.
Current-Level
Effluent"*
49.93
498.10
15,042.00
10,284,000.00
8.18
52.00
3,146.15
74.16
5,052,280.00
_63.00
18,886,000.00
142,720.00
245,300.00
27.00
4.48
1,156.00
41.92
7,025.00
58.00
378.01
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
i/Removals
V . '
floH (iisll\ ' *
; treatment-^
Level Effluent
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
- 0.00 .-
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
11 ' ~" " ,
:'v1 "'
Currently
. Discharged '
627
627
627
627
627
627
627
627
627
- 627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
627
All Others (S
' ''' f *'' Y
% 4 V«-"V*(IHt
,- Efflitent.
6,468.40
498.10
15,042.00
10,284,000.00
8.18
52.00
384,412.00
5,146.60
5,052,280.00
- ... 63.00
18,886,000.00
142,720.00
245,300.00
27.00
74.58
1,156.00
41.92
7,205.00
58.00
2,675.00
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
• • ,,*,' ""•' "
ettung effluent to z
, - r « t
MI0R v^&f) *
•}* ' .. -,' , '
Treatment-Level
*- '- Effluent --'
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
^ -,, . ,
ero disease)'- '*
.- -yinm *
Currently
. Discharged
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
8,778
" V Loadin
'.. * ' ' * *
Cuitrenf-Cevel *
i- ' Effluent
20
2
49
33,827
0
0
1,181
16
16,618
, ... 0
62,121
469
807
0
0
4
0
24
0
8
10
0
0
1
3
2
1
2
1
1
4
3
4
0
0
0
3
115,180
117,524
f •> -/; ",-t
gs(%s) -' -
* --•• J fs, •• ••
'
.Treatment-Level
- Effluent1
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
'\, "": ' -'
V % ' "
•&Btt0f4^lM'
•> , '
"Incremental
20
2
49
33,827
0
0
1,181
16
16,618
0
62,121
469
807
0
0
4
0
24
0
8
10
0
0
1
3
2
1
2
1
1
4
3
4
0
0
0
3
115,180
117,524
(a) Concentrations in this column are from the Offshore Development Document.
(b) For the purpose of regulatory analysis, these concentrations are substituted using the settling effluent concentrations either because no data were available in the Offshore Development Document or because the Offshore Gas
Flotation value was greater than the settling effluent value.
-------
APPENDIX Xin-1
ENERGY REQUIREMENTS AND AIR EMISSIONS
DETAILED CALCULATIONS FOR COOK INLET
DRILLING WASTE ZERO DISCHARGE SCENARIO 1:
CLOSED-LOOP SOLIDS CONTROL AND LANDFILL
A-72
-------
UIL. AND UAO
DRILLING WASTE - COOK INLET ZERO DISCHARGE BASED ON LANDFILL * CLOSED-LOOP
FUEL USAGE, HORSEPOWER REQUIREMENTS, AND AIR EMISSIONS
Page 1 of 6
D8IWNQ WKST& VOLUME
Tolaiyafttine MudsSCuWnp Huffifeero! Number of Smelts NunsfcsroI^IIG Vriumftof
Dr.EigV'.'asM Pe-Well Vfeb Using Biignj to TuKklnjU Bass
(Its) (Mil) WntCcoklnM Omgon (tils;
«S,D14 (a) E,S» 41(1) 28 (a) 13 (a) a 1,22565
Recomplalton 29,874 H 1,499 20 (a) 19 (a| 1 (a) 9 K7.31
TeW 431.SB6
SWWVBOAT !WlWS/r FUit COWSUHPTON
No.llKnrmnM Tolal'.volls tlumtafci MllnPir Tsui Doal Avsraga Dcat QH>( TMalDKMl
BoitTi^ispaf Boatma BoatTi^i f*aas Sissed UsassSsts Usage
W* (IBIHO (J«l»«) a»lj
MwWlll 15 is) 41 615 60(b) 30,730 11.5 (=) 139(4 34?,«I9
Hraniplolon 1(1) 20 20 60(4 1,000 11.EIC) 1:S (J) 11,304
TOBI 358,913
3»
T D/Hro tttm&eref Proportion 01 Ntrrtirol Well Total V.'alls Numosrol Miles Pel ToHBtrp AveragsBarco DIBSC!
VWIWwls VlSsnvolunm BmseTrtps Bata«Trtp Mifcs speed Usage RaB Uwae
VolumaperBox PerBerge (mlmn taaurul (gal)
Nev/W.11 240 (a) 0.000815892 0.1958 28 142.99 50(0) 7,150 8(0 24 (() 29,599
R«a»npl8lfan S40(«) 0.0055379580 1.J811 19 14.83 60 («) 74! «J> 21(8) 2,968
TOUI 31,585
-------
COASTAL OIL AND CAS
DRILLING WASTE - COOK INLET ZERO DISCHARGE BASED ON LANDFILL + CLOSED-LOOP
FUEL USAGE, HORSEPOWER REQUIREMENTS, AND AIR EMISSIONS
Page 2 of 6
SUPPLY BOAT MANEUVERING FUEL CONSUMPTION
Drilling Total Marmvering Time Diesel Total Fuel
Operation Number of Per Trip Usage Rate Consumption
Boat Trips (hrs) (gal/hr) (gal)
New Well 615 1 (h) 25.3 (h) 15.530
Recomplelion 20 1 (h) 25.3 (h) 503
Total 16,066
SUPPLY BOAT LOADING FUEL CONSUMPTION (AT PLATFORM)
Drilling Total Loading Time Diesel Total Fuel
Operation Number of Per Trip Usage Rate Consumption
Boat Trips (hrs) (gal/hr) (gal)
if* NewWell 615 4.15 (I) 25.3 (j) 64,572
^ Recompletion 20 4.15 (i) 25.3 (j) 2,100
Total 66,672
SUPPLY BOAT AUXILIARY ELECTRICAL GENERATOR (IN PORT)
Drilling Total Generator Hours Diesel Total Fuel Generator Total
Operation Number of Per Trip Usage Rate Consumption Power Rating Generator
Boat Trips (gal/hr) (gal) (hp) Horsepower-Hours
NewWell 615 24 (k) 6 (k) 88,560 60 (h) 885,300
Recompletion 20 24 (k) 3 (k) 2,880 60 (h) 28,800
Total 91,440 914,400
cidrzd.wkS
-------
DRILLING WASTE - COOK INLET ZERO DISCHARGE BASED ON LANDFILL + CLOSED-LOOP
FUEL USAGE, HORSEPOWER REQUIREMENTS, AND AIR EMISSIONS
Page 3 of 6
NewWBl
RecOT
Total
SUPPLY 8MT
f&misref
Total Ciaae
UBsf*«
Round Tifp
Musfesrof
Per Hew
833 (m)
32,275
1JJ50
33^24
TolaiCrana
Brate Hcraepoww-
HMIR
526,932
17,138
944,068
Total NtffAer
of Boat Trips
tow
1Q(k)
6,717
583
6,310
Ctane
Brake Horsepower
Total Craae
Brake Horsepower-
WES BrG?EfMTOS "
TrudJoad
(bbtej
12(0)
12 Co)
Preporfofiof
Well Wasto
Volume p« Bolt
0,000615692
per Truck
0.009T90?
0.064QSS5I
Total
Number of
Truck Trips
2.B6S
jsper
ckTOp
Total Fuel
Consumption
feat)
7,1Se
Number of WeH
Waste Volumes
per Tmck
0.00916162
Totel
Number
-------
COASTAL O»L AND CAS
DRILLING WASTE - COOK INLET ZERO DISCHARGE BASED ON LANDFILL + CLOSED-LOOP
FUEL USAGE, HORSEPOWER REQUIREMENTS, AND AIR EMISSIONS
Page 4 of6
WHEEL TRACTOR TOR GRADING AT LANDFILL
Drilling Total Wells Tractor "flam Tote! Trader Diesel Usage Total Fusl
Operation Per Wai! Time Rats Consumption
(hrs) (his) (gal/hr) (gal)
New Well 41 8 (s) 328 1.67 (s) 648
Recompletion 20 8 (s) 160 1.67 (s) 267
Total 488 815
TRACK-TYPE DOZER/LOADER FOR SPREADING WASTE ATLANDFARKI
' Drilling Total Wells Dozer Time Total Dozer Diesel Usage Total Fuel
1 Operation Per Well Time Rate Consumption
(hrs) (hrs) (gal/hr) (gal)
New Well 41 16 (s) 656 22 (a) 14,432
Recomptetton 20 16 (s) 320 22 (s) 7,040
Total 876 21,472
DECANTING CENTRIFUGE FOR CLOSBS-LOOP SOLIDS CONTROL
Drilling Total Wells CenfrifUga Centr, Operating Centrif, Total Centrif. Fusl
Operation HP Requirement Hours Par Well HP-hre Usage
(scf nat'l gas)
NewWfell 41 40 (t) 733 (u) 29,320 278,540
Reoompletion 20 40 (t) 240 (u) 9,600 91,200
Total 38,920 368,740
cidrzd.wkS
-------
DRILLING WASTE - COOK INLET ZERO DISCHARGE BASED ON LANDFILL + CLOSED-LOOP
FUEL USAGE, HORSEPOWER REQUIREMENTS, AND AIR EMISSIONS
Page 5 of 6
AIR EMISSION FACTORS
Category
DIESEL
Supply Boats
Transit
Maneuvering
Idling
Demurrage (aux ganj
BSIfQS
Transit
Cranes
- Drill Site
In-Port
Trucks
Wheel Tractor
, DozerfLoader
NATURAL GAS
Gas-fired Turbine
Units
(lb/1000 gal)
(IbMOOO gal)
(!b.'1000gal)
(gfchjHir)
(IWIOOBgal)
jg/bhp-hr)
(Bfthp-hr)
(gfinlle)
CWhr)
(Whr)
(g/hp-hr)
NOx
391.700
419.600
419.600
14,000
391.700
14.000 '
14.000
11.230
1.269
0.827
1.300
THC
1S.800
22.600
22.800
1.120
18.800
' - - ' ' -1.120' '
1.120
2.490
0.188
0.098
0.180
SO2
28.480
28.480
28.480
0.931
28.480
' " 0.931
0.931
NA
0.090
0.076
0.002
CO
78.300
59.800
S9.800
3.030
78.300
- ~"3.ma
3.030
8.630
3.590
0.201
0.830 '
TSP
33.000
33.000
33,000
1.000
33.000
- 1,060
1.000
NA
0,136
O.OS8
NA
cttzdwkS
-------
COASTAL OIL AND GAS
DRILLING WASTE - COOK INLET ZERO DISCHARGE BASED ON LANDFILL + CLOSED-LOOP
FUEL USAGE, HORSEPOWER REQUIREMENTS, AND AIR EMISSIONS
Page 6 of 6
TOTAL AIR EMISSIONS-ZERO USCHAfieEBASED ON TRANSPORT TO LANDFILL
Category
DIESEL
Supply Boals
Trsntlt
Maneuvering
Loading
Dumurrage(auxgan)
Total
Barge
Transit
Supply Boat Cranes
Barge Cranes
Trucks Used by Operator *B"
Trucks to Oregon
Wheel Trader
Dozer/Loader
Decanting Centrifuge
TOTAL FUEL USAGE
TOTAL EMISSIONS -tons
Total Dle««4
Firt Usage
(1000 gal)
356.91
16.07
60.67
91.44
633.09
31.56
33.32
6.31
7.89
686.65
asi
21.47
1,621.11
ToMNtn Power
G»s Usage Requirements
(1000 KO (ip-lir)
NA
NA
NA
914.400
NA
544.068
103,027
NA
NA
NA
NA
369.74 38.920
369.74
NOx
Totel
flora)
7020
3.37
13.99
14.10
101.75
6.18
8.39
1.59
039
43.86
0.31
0.40
0.06
162.93
TOO
TOW
(tons)
3.01
0.18
0.76
1.13
S.07
0.27
0*7
0.13
0.09
9.73
0.05
0.05
0.01
16.07
SO2
Total
(tons)
5.11
0.23
0.95
0.94
7.23
0.45
0.56
0.11
0.00
0.00
0.02
0.04
turn
8.41
CO
ToW
14.05
0.46
1.99
3.05
19.67
1.24
1.82
0.34
0.30
33.32
0.68
0.10
0.04
57.61
TSP
Total
(tons)
5.92
0.27
1.10
1.01
8.30
0.62
0.60
0.11
0,00
0.00
0.03
0.03
0.00
9.59
TOTAL
(Ions)
141.92
8.66
12.04
2.28
0.78
86.91
1.29
0.62
0.11
254.61
Summary Data
Total Air Emissions (tons):
Total Fuel Usage (BOB):
Total Drilling Waste to
Landfill (bbls):
Seven Years
264.61
36,293
431,918
Annua
36.37
6,163
61,713
-------
Appendix XIH-l
Footnotes for Drilling Waste Zero Discharge Scenario 1
Closed-Loop Solids Control and Landfill
(a) Chapter X and Appendix X-l.
(b) Distance from platforms in Trading Bay Field and Granite Point Field is approximately 25 miles
(50 miles round trip) to the East Foreland Facility. Supply boats unload at ports near the East
Foreland Facility. From Marathon/Unocal, "Drilling Waste Disposal Alternatives - A Cook Inlet
Perspective," March 1994.
(c) Average boat speed is 11.5 miles per hour. From Walk, Haydel & Associates, Inc., "Water-
Based Drilling Fluids and Cuttings Disposal Study Update," January 1989.
(d) U.S. EPA, "Trip Report to Campbell Wells Landfarms and Transfer Stations in Louisiana," June
30, 1992. Note that the analysis for the Offshore Guidelines used 169 gallons per hour (gph)
which is based on 100% utilization of supply boat engine maximum power output. Actual fuel
consumption was rated at i 110 gph. The 130 gph consumption rate is considered to be a
conservative and realistic estimate. Vessels serving Gulf of Mexico platforms are considered
comparable to those serving Cook Inlet platforms.
(e) Distance from east side of Cook Inlet to the west side near Trading Bay Field is approximately
25 miles (50 miles round trip).
(f) SAIC, "Produced Water Injection Cost Study for the Development of Coastal Oil and Gas
Effluent Limitations Guidelines," March 8, 1993.
(g) U.S. EPA, "Trip Report to Campbell Wells Landfarms and Transfer Stations in Louisiana," June
30, 1992. Vessels serving Gulf of Mexico platforms are considered comparable to those serving
Cook Inlet platforms.
(h) 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.
(i) Loading time is equal to crane tune plus one hour.
(j) Diesel usage rate for loading at platforms is equal to the usage rate for maneuvering because
supply boats are not able to dock at drilling platforms in Cook Inlet due to strong currents.
(k) Walk, Haydel & Associates, Inc., "Water-Based Drilling Fluids and Cuttings Disposal Study
Update," January 1989.
(1) Four boxes per lift at the drill site and at the port. The loading time of 6.3 hours (240 boxes/4
boxes per lift/ 10 lifts per hour) is consistent with the time of four to six hours cited in
Wiedeman, A., U.S. EPA,' "Trip Report to Alaska Cook Inlet and North Slope Oil and Gas
Facilities, August 25-29, 1993," August 31, 1994.
A-79
-------
Appendix XHI-1
Footnotes for Drilling Waste Zero Discharge Scenario 1
Closed-Loop Solids Control and Landfill
(continued)
(m) Crane fuel usage rate at Campbell Wells was 25 gallons for three hours or 8.33 gph. From
Wiedeman, 1994.
(n) Assumes 10 boxes per lift at the port and at the beach since boxes are placed in shipping
containers that hold 10-12 boxes each. Barge capacity is 240 boxes. From Marathon/Unocal.
March 1994.
(o) U.S. EPA, Development Document for Proposed Effluent limitations Guidelines & Standards
for the Coastal Subcategorv of the Oil and Gas Extraction Point Source Category. January 31,
1995.
(p) Distance from barge landing to landfill at Kustatan is three miles (six miles round trip).
Marathon/Unocal, March 1994. Distance from East Foreland port to the storage area is two
miles (four miles round trip). Total trucking distance is 10 miles.
(q) Trucks to Oregon have a 22-ton capacity. From Mclntyre, J., SAIC, Record of telephone call
with Josh Stenson of Carlisle Trucking, regarding "Costs to Truck Wastes from Kenai, Alaska
to Arlington, Oregon," May 23, 1995. This capacity converts to 10 boxes per load as calculated
in Appendix X-2.
(r) One-way truck trip from Kenai, Alaska to Arlington, Oregon is approximately 2,200 miles.
(s) Time for a wheel tractor for grading wastes from one well is one day (8 hours). Time for a
dozer/loader for spreading wastes from one well is two days (16 hours). From U.S. EPA, "Non-
Water Quality Environmental Impacts Resulting from the Onshore Disposal of Drilling Fluids and
Drill Cuttings from Offshore Oil and Gas Drilling Activities," January 13, 1993.
(t) Gauthier Brothers, Equipment and Services Catalog, 1993.
(u) Calculated from Worksheet 1 hi Appendix X-l:
New Well: (11 days x 13 hours) + (25 days x 14 hours) = 733 hours
Recompletion: (20 days x 12 hours) = 240 hours
A decanting centrifuge is assumed to run continuously, although this is a conservatively high
assumption.
A-SO
-------
APPENDIX Xm-2
ENERGY REQUIREMENTS AND AIR EMISSIONS
DETAILED CALCULATIONS FOR COOK INLET
DRILLING WASTE ZERO DISCHARGE SCENARIO 2:
GRINDING AND SUBSURFACE INJECTION
A-81
-------
QMmu.gn.Maow
OHUM9WMK
HStlOti
Ming Total Vakim MucJilCUHos) Numbwol
OptnMn nsngwuo PerWol mil
{(*&) (MM)
NawWi* 602,028 («J 14,210 {<) 41 (I)
Rocomplodon 49,441 (a) 2.172 («) 20 (a)
NKton 63.300 (a) 5.275 (a) 12 (I)
Total 6«J,370
DMng ToKIWMI iMidngt InJedmM1 F(-ocos5 Equip. ptowss Equ'p, Process CquiJ. Injaulixi Equip. lrje:l'on Equip. ki]scl'on Etjjlp- ToM
C^amtla) Eqt^aiU2 Roi^adngKP ReqtA^nerUs Qpsnonsn Hours Tcris)l^4irs FugiUssge C^a^Ki Houra ToEatHp-ira Fust Usage ^Ntvs
Roquiremtr,1^ PaVVcl (scf rariass) PsrMt (icfMdgn)
NmWrt 41 Him 8» (0 M* » 22,449,891 213.271.115 47.37 (n) 071.0ffl 6.224.S59 23,410,639
RecompleBMl 20 747 (b) 600 (c) 24A (4 3,555,600 M.063.5.CC 7,24 (e) 72/0! 667.816 3.656X102
fr,CHbn 12 747 0J 600 (c) 211 (d) 1,891,404 17.060,333 17.58 (o) 106,600 1,002.250 1.096,004
Total 27,916,695 2E5,3D2,6S3 1,MB,960 10,915,026 2S,076,S«
-------
DRILLING WASTE - COOK INLET ZERO DISCHARGE BASED ON GRINDING AND INJECTION
FUEL USAGE, HORSEPOWER REQUIREMENTS, AND AIR EMISSIONS
Page 2 of2
AIR EMISSION FACTORS
Category Units
Gas-fired Turbine (g'hp-hr)
NOx
1.300
THC
0.180
S02
CO
0.002
0.830
TOTAL AIR EMISSIONS • ZERO DISCHARGE BASED ON GRINDING AND INJECTION
Category
NATURAL GAS
QrtndingiProeess Equipment
Injection Equipment
TOTAL
Nat. Gas
Fusl Usage
(1000 80()
265,303
10,913
276,218
Power
Requirements
- ' (hp-hr)
27,926,585
1,148,980
NOx
(tons) -
39.98
1,64
41.82
THC
(tarn)
5.S4
0,23
8.77
S02
(Ions)
O.OS
0.00
0.06
CO
(tons)
25,53
1.05
26.58
TOTAL
" ((ant)
71.11
2,82
74.0S
SUMMARY DATA
Total Air Emissions (tons):
Total Fuel Usage (BOE):
Total Drilling Waste Injected (bbls):
Seven Years
74.03
49,167
889,370
Annua
10.58
7,024
98,481
ddrzd.wkS
-------
Appendix XTH-2
Footnotes for Drilling Waste Zero Discharge Scenario 2
Grinding and Subsurface Injection
(a) Chapter X and Appendix X-l.
(b) Schmidt, R., Unocal, Correspondence with Manuela Erickson, SAIC, regarding Drill Cuttings
and Fluid Discharge Economic Impacts, April 18, 1994.
(c) Marathon/Unocal, "Drilling Waste Disposal Alternatives - A Cook Inlet Perspective," March
1994.
(d) Calculated from Worksheet 1 in Appendix X-l.
New Well: (11 days x 13 hours) + (25 days x 14 hours) - 733 hours
Recompletion: (20 days x 12 hours) = 240 hours
Injection Well: (2500/2553)(11 days x 13 hours) + (1500/7348)(25 days x 14 hours) = 211 hrs
(e) Based on an injection rate of 5 barrels per minute and the total drilling waste volume per well.
From Marathon/Unocal, March 1994.
A-84
-------
APPENDIX Xffl-3
ENERGY REQUIREMENTS AND AIR EMISSIONS
DETAILED CALCULATIONS FOR COOK INLET
PRODUCED WATER CONTROL OPTIONS 1 AND 2:
IMPROVED GAS FLOTATION
A-85
-------
NON-WATER QUALITY ENVIRONMENTAL IMPACTS
FUEL REQUIREMENTS AND AIR EMISSIONS
COOK INLET PRODUCED WATER: DISCHARGE FOLLOWING IMPROVED GAS FLOTATION
PAGE 1 OF 1
Facility/
Platform
Trading Bay
Granite Point
East Foreland
Anna
Baker
Bruce
Dillon
Tyonek
TOTALS
Prod. Water
Flow
(BPD)
127.468
929
1.700
919
• - 924
119
3.116
30
135.205
New Gas
Flotation
System ?
no
yes
yes
yes
yes
yes
yes
yes
Gas FloLn
Capacity
(BPD)
MA
5,000
5,000
5,000
5,000
1,000
10,000
NA
Total HP
Required
0
15.53
15.53
15.53
15.53
12.25
20.5
0
94.87
SCFNG
per year
0
1.292.407
1 .292.407
1,292,407
1,292,407
1.019,445
1,706,010
0
7,895,083
Tola)
hp-hr
Required
0
136.043
136.043
136,043
136,043
107,310
179,580
0
831,062
AIR EMISSIONS (tons/year)
CO
0.000
0.124
0.124
0.124
0.124
0.098
0.164
0.000
0.758
NOX
0.000
0.195
0.195
0.195
0.195
0.154
0.257
0.000
1.191
HC
0.000
0.027
0.027
0.027
0.027
0.021
0.036
0.000
0.165
SO2
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Totals
0.000
0.346
0.346
0.346
0.346
0.273
0.457
0.000
2.114
SUMMARY DATA
Total Air Emissions (tons/vr):
Total Fuel Usage (BOE/yr)
2.11
1,405.32
Air Emis'n Factors for Gas-Fired Turbines
(converted to tons/hp-hr) Ref: Table 3
CO
9.1E-07
NOX
1.4E-06
HC
2.0E-07
S02
2.2E-09
cipwnwqi.wkS
-------
APPENDIX Xm-4
ENERGY REQUIREMENTS AND AIR EMISSIONS
DETAILED CALCULATIONS FOR COOK INLET
PRODUCED WATER CONTROL OPTION 3:
SUBSURFACE INJECTION
A-87
-------
HON-WWER OUAUIYEHV)ROI9.ia(T«. IMPACTS
FUiLRGOUIREMeNTS/WDMREUISSIONS
COOK (MET PltOOUCEO VMTER: ZERO DieCHAROE VMItUECTIOH
PACE t OF 1
Witt**"
Fto*
ItwOu
FfebHoa
Swtem?
GjlFfcln
dp**/
tBPD)
fouli*
WHKi
System?
rarer
R57
ton
Snlnn?
5.000
3fe
"•piety
(ft-
Ha
VSL.
_ia
jjjMgr
O.D023
030231
at.
m
iSSSSL
0.00779
MA"
"lOiio"
SA~
JOOO
~»4.8?
0.33?«
IS-
HP For All
Equipment
4,900.32
135.53
1,315.53
15.53
15.53
54.25
20.51
52.00
6,509.20
Total hp-hr
Required
42L926,803
1,187,243
11.524,043
136,043
136,043
475,230
179,668
455,520
57,020,593
AIR EMISSIONS (tons/year)
CO
39.239
1.085
10.534
0.124
0.124
0.434
0.164
0.416
52.120
NOX
61.459
1.700
16.499
0.195
0.195
0.680
0.257
0.652
81.637
HC
8.510
0.235
2.285
0.027
0.027
0.094
0.036
0.090
11.304
S02
0.095
0.003
0.025
0.000
0.000
0.001
0.000
0.001
0.125
Totals
109.303
3.023
29.343
0.346
0.346
1.209
0.457
1.159
145.186
SCF per yr:
541,695,634
(a) Two centrifuges were added to each of Dolly Varden, King Salmon, and Grayling platforms which
receive treated produced water from Trading Bay Treatment Facility.
(b) One centrifuge was added to Platform "C" which receives treated produced water from East Foreland Treatment Facility.
SUMMARY DATA
Total Air Emissions (tons/yr):
Total Fuel Usage (BOE/yr):
145.19
96,421.82
Air Emis'n Factors for Gas-Fired Turbines
(converted to tons/hp-hr) Ref: Table 3
CO-
9.1E-07
NOX
1.4E-06
HC
2.0E-07
S02
E
2.2E-09
cipwnwqi.wM
-------
APPENDIX Xni-5
ENERGY REQUIREMENTS AND AIR EMISSIONS FOR LOUISIANA OPEN BAY
DISCHARGERS AND TEXAS DISCHARGERS SEEKING INDIVIDUAL PERMITS
OPTION 1: IMPROVED GAS FLOTATION
A-89
-------
LOUISIANA OPEN BAY PRODUCED WATER DISCHARGERS' NWQI ANALYSIS
OPTION 1
GAS FLOTATION FOR MEDIUM/URGE-VOLUME FACILITIES
Current Avg. Elactrlc Power
Permit-Outfall Vol (bpd) From Diesel
Number (bpd) (hp) (hp-hr/yr)
2915 130 11.59 101,549
2952 223 11.80 103,387
2704 524 12,48 109,337
2901 1,076 13.73 120.249
3072 1,489 14.66 128,413
3002 2,017 15,85 138,891
2816 t 2,871 16,42 143,872
> 2825*- " > ^.2,910 17.87 156,303
t 2898 T „*> 1^,3,617 19.46 '"170,479
! 1866 «!- , * 4,6"'2y%&* 21,73"-' -190,326
2273 4,621 21.73 190,326
2995 4,621 21.73 190,326
3014 4.621 21.73 190,326
4206 ' 4,621 21.73 190,326
2681 5,010 0.00 0.00
i> " " J- .252$>'|: '; V ' , s f • , 5,364 :,; j < ^ 0.00 „ , :,. 0,00
, \ ° ,_72860, "-4 '^ "- '6,800 ' -, 0,00' , , JO.OO
•t'-'ySi'i, $'? I'l "-"vB,S6&V; x ",/ 0.00^ V',a,v, -.0.00
' '-'- ; 2859 ?"' ' •' I* 10,807 -;'"' ' V 0,00 * <",'; .'?'Q.DO
', »<;;-/S063',;>,', },-tf- "'11,500;', T • 0.00 ;-'-' , V 0.00
2142 12,076 0.00 0.00
1856 15,000 0.00 0.00
1934 15,675 0.00 0.00
2084 16,743 0.00 0.00
2618 22,500 0.00 0.00
-' t-f ^3320,^ "•" ^ 'v '-"£2,»57'9"r"' 0,00 " " ' V* 0,00
<4"5? ' - , 20^2 , * ' '"* | 37i750 ' v '- 0.00 ' -v" '.0.00
, " "iao'i ----- 4ii70o-x -- '0.00 - - b.oo
TOTAL 329,678 — 2,124,270
Diesel Fuel
Requmnl's
toal/yr)
6,702,23
6,82334
7,216.24
7,936.43
8,475,26
9,164,17
„ ',. 9.495,56
s 10,326,20
* 1-11,251,61
, \ 12,561,52
12,561.52
12,561.52
12,561.52
12,561.52
0.00
*\ *-, -0,00
" r, -',0:00
S ,„' ' , * 0.00
'4- ;v'' 0.00
* ,sl' , 0.00
0.00
0.00
0.00
0.00
0.00
'"^''^f.^OJXl
^x ,;,r ;o,oo'
' 'ft:: , ,-,- 27.4? ' ,""/2ib,199
4%- ''• 31^48 '''"?" '27-5J,765
^^-^ ^ 37.82 ,'^"? ^"331 ,303
't^"' 3<9:6rJiM?^34e,984
"41.11 % '360,124
48.70 426,612
50.45 441,942
53.22 466,207
68.16 597,082
-•'Y,!eB,S6!< -f\ ,o,op
0.00
0.00
0.00
0.00
1.89
,','; " .-{1^97
r A *"-228
';',,, ,,-• ,5.62
' $" ,,3,!5
(', ; v,'^3.3Q
3.42
4.05
4.20
4.43
5.67
,*" 5,69
-, --J5.85
-* • :r 8,8$
,« I 8.97
11 / 9.82
76.14
Emissions (tons/yr)
CO NOx S02 THC TSP Total
0.34 1.57 0.10 0.13 0.11 2.25
0.35 1.59 0.11 0.13 0.11 2.29
0.36 1.69 0.11 0.13 0.12 2.41
0.40 1,85 0.12 0.15 0.13 2.65
0.43 1.98 0.13 0.16 0.14 2.84
0,46 2,14 0,14 0,17 0,15 3,06
0.48 2,22 0.1B 0,18 0,16 8,10
0,52 i 3,41 0,18 0,19 0,17 3,4§
O.S7 f 2,63 , 0(17 0,21 0,1$* 3,77
„ «0,64 > j.^2,93 X 'pJaOj! 0,23 Q,2t „ ;4,21
0.64 2.93 0.20 0.23 0.21 4.21
0.64 2.93 0.20 0.23 0.21 4.21
0.64 2.93 0.20 0.23 0.21 4.21
0.64 2.93 0.20 0.23 0.21 4.21
0.35 2.64 0.00 1.08 0.00 4,07
0.37s' -fx'2,73 -t' ' OiDQ»-&- ,,,1 .l'£h" j? 0.00;5 1 s A'23
"^ 0,'42 - >'3>17 ^X"'0.80->1 '* 1 30' O.OO""1' 489
; '0^49°. 43!64;'»'5<'0.<30';''-',1.49 r^«0.'QO?--">5',6,2
o.sa*',v^4.38;^ 6jx$*' ")'%&• ; o'.b'qf-"»;e'!78
, ; 0.61- , 4,B9j;,->3.23' " : 0,00 12,20
t';<-!1>09-, '^ 8.14 vJ'O.O'olU '-3,32*' 0,00 - 1,2,55
" 1,64 12,28,^4003,1 5.01" j,0,00- 'i8,,9,3
'^1,86 ' 12,47*"-' 0,00 -*5.0B"" ' 0.00 , " 19.22
' {,82- 13.86-;- 0.00* -5.5B,"*: O.OQ --21.06
21.22 138.65 2.18 45.85 2.33 210.23
I
Medium/Large LA Open Bay Produced Water
Gas Flotation NWQI Summary Data
Total Fuel Use
16,891.06 BOE/yr (a)
Total Air Emissions
210.23 tons/yr
(a) BOE (barrels of oil equivalent) per year is the total diesel volume required converted to equivalent oil volume (by the factor: 1 BOE •-
and the volume of natural gas required converted to equivalent oil volume (by the factor: 1,000 scf = 0.178 BOE).
42 gal)
OBPWNWQ.WK3
-------
LOUISIANA OPEN BAY DISCHARGERS
OPTION 1
SMALL VOLUME FACILITIES"
Commercial Disposal of Produced Water via Barge
s
< -' •' "Solace """/'
Pump +
Compressor
Tug
Total
s f f ssf
Diesel Usage
"""(gAtyrjt""
159.21
55,881.12
56,040.23
f f ss s
V ,-" ' =
"'It&Wyr'"
'. 3.79
1,330.50
1,334.29
, s Atr ESm&siexi^
-------
TEXAS INDIVIDUAL PERMIT APPLICANTS' NWQI ANALYSIS
OPTION 1
SMALL VOLUME FACILITIES
Commercial Produced Water Disposal via Truck
Permit
NP.
Location
Current
Vol. (bpd)
No. of Truck
Trlps/yr
Miles
Troveled/yr
Diesel Fuel
Usage (gal/yr)
CO
NOx
Emissions (tons/yr)
SO2
THC
TSP
Total
13
37
41
71
104
119
236
282
284
628
663
I
733
752
919
924
925
Corpus Christ! Bay
Kellers Bay
San Antonio Bay
Cox Bay
Tabbs Bay
Goose Creek
Goose Creek >
Mustang Island
Corpus Christ! Bay
Aransas Bay
Mustang Island
Corpus Christ! Bay
Corpus Christ! Bay
Copano Bay
Cedar Lake
Aransas Bay - '„
Matagorda Bay ,
Sabine River
Matagorda Bay
Matagorda Bay
Matagorda Bay
Matagorda Bay',
Tabbs Bay *
Aransas Bay ,,'„.
Laguna Madre. >...<'.
7
5
15
40
3
49
2
40
15
i
44
1
22
24
10
21.47
15.34
46.01
122.69
9.20
160,89
6.13
49,08
$.07
134.96
3.07
67.48
73.61
30.67
X-r *M
,' ./ > 30,67
2,576.40
1,840.80
5,521.20
14,722.80
1,104.00
18,03480
735.60
14,722,80
' 5,889 BO
16,195.20
368.40
8,097.60
8,833.20
3,680.40
, 368.40
>< 3,'680.40
644.10
460.20
1,380.30
3,680.70
276.00
4,808,70
18390
8,680.70
i,47Z,40
92,10
4,048.80
92.10
2,024.40
2,208.30
920.10
0,00
0.00
0.00
0.00
0.00
-> 0.00
: ' "0 00
s '10.00
0.00
10,00
0.00
0.00
0.00
0.00
0.00
se's^o
$20.10
•, 92,10
6.13
88.95
184.03
95.08
211.64
735.60
10,674.00
22,083.60
11,409.60
25,396.80
183.90
2,668.50
5,520.90
2,852.40
6,349.20
0.00
0.00
0.00
0.00
0.00
,15,826.80
', 368.40
"«.' -.•* 230,04
**' 0,34
0.01
0.01
0.02
0.04
0.00
0.05
000
0,04
0,02
p,oo
0.04
0.00
0.02
0.02
0.01
0.00
0.03
0.06
0.03
0.07
pt'0,04
?>v 0.00
J'f 0.08:
0.00
0.00
0.00
0.00
0.00
0,00
0.00
< 0,00
0.00
^0,00
0.00
0.00
0.00
0.00
0.00
TOTAL FOR GAS FLOTATION
656
2,012.10
241,452.00
60,363.00
2.27
2.99
0.00
0.66
0.00
5.92
' TRC permit pending
TX Produced Water Small Facilities
Gas Rotation Option NWQI Summary Data
Total Fuel Use
Total Air Emissions
1,437.21 BOE/yr (b)
5.92 tons/yr
(a) This outfall Is classified as a small-volume discharger only for the gas flotation option.
(b) BOE (barrels of oil equivalent) per year is the total diesd volume required converted to equivalent oil volume (by the factor: 1 BOE = 42 gal)
and the volume of natural gas required converted to equivalent oil volume (by the factor: 1,000 scf = 0.178 BOE).
TXOBNWQI.WK3
-------
TEXAS INDIVIDUAL PERMIT APPLICANTS' PRODUCED WATER NWQI ANALYSIS
OPTION 1
GAS FLOTATION FOR MEDIUM/LARGE-VOLUME FACILITIES
- * ; *-., •CurrsnUWg ' Blecl»6Pcij»r
Peitnt-Otol ' , VoT(bpa) , Ffbm Diesel,
Number ^ - * '(bodi .. ..- (ho> \.,..fhB~hr/vn"
90S 63 11.49 100,652
675 92 11.51 100,626
* 93 11.51 100,826
927 95 11.51 100,626
242 104 11.53 101,003
264 114 11S6 101568
* US 11,88 (01,868
568 t* » 11,61 < 101,704
922- «3 1162. 101,791
60S , ' ISO -1194 > 101,966
202 153 11.64 101,966
664 165 11.67 102,229
694 165 11.72 102,667
637 200 11.76 102,930
822 200 11.75 102,930
970 • ;-- , 260 ,11,86 1 {03,894
'' >T10 , ;> tx.«S8'. 12,11 r»* 106,084
' >, 174, >"','"'" * 'S84 , J' 12-17- "10.6,609
> , 96f '\ ' t o ,-997 ' 12,19,, / ' 1«8,7$4
. - 941 , --- 4tO "- 1422*,- M07,a47
679 454 12.32 107,923
124 455 12.33 108,011
236 515 12,46 109,150
619 536 12.61 109,668
968 540 12.62 109,675
<666 S28, *ffc72 f 11,427
10S- > 650 , 1477 JJ186B
93? 669 '12.79 (12040
x 60 i " 688 1264 112478
• 167 690 12,86 , 1)2,654
166 1029 13.62 119,311
20 1151 13.90 121,764
904 1360 14.37 125,881
65 1379 14.41 126,232
45 1400 14.46 126.070
* 969 ,' ?4!» 1494 128846
•-SO 14B8 1*67 - 129509
1 * 8185 ' 1623 142,175
81 3090 18.27 160,045
77 35S2 19.31 169,156
164 4353 21.12 185,011
813 4693 22.34 195,698
952 4980 22.54 197,450
"-" ,113; x- , - 61S7 „ OOCT- < 0,00
VB54 ,' 7384"' "/OOP,,-,,/ '000
!% 953., '- - "!93J6-' " P0Q , ' "OQO
TOTAL 67,117 — 5,349,382
, Diesel piel
Requmnfa
6,654.62
665462
6,654.62
6,666.18
6,68363
6,6® S3
<5>1244
• 6,?iB22
6,729:78
6,729.78
6,747.13
6,776.04
6,79338
6,79a38
' ,6,6Rre8
7,001,58
' * 7jOS6»
.'•*J',tM7i77
* 4,666.1ft
7,122.93
7,12871
7,20a87
7,232.78
7,238.56
7J36480
788316
7,39467
' 7^23.57
„ ^asii
7,874.54
8,036.42
8,308.16
8,331.29
8,360.19
8,48428
8^161
1 8,48739
8,86054
9,88384
10,562.98
11,16457
12,210.74
12,916.09
13,031 73
-,; "o.iio
; \, 0,00
' 0,60
353,059
- EjESlhoPCMiSt 4
% 'Rrqm Natural 6as
0.00 0.00
0.00 0.00
0.00 0.00
0.00 0.00
0.00 0.00
000 OflO
000 000
oca OQO
000 " 000
van poo
0.00 0.00
0.00 0.00
0.00 0.00
0.00 0.00
0.00 0.00
,> ,* , o.0a ' '-0,00
<• ooa o«p
' ' 0,00,,', 0,00
' 0,00 - ' MO
tutSh •- , Ooo
0.00 0.00
0.00 0.00
0.00 0.00
0.00 0.00
0.00 0.00
0,00 000
ODD OOO
; x ODD ooo
f 000 OQO
i 000 0,00
000 000
0.00 0.00
0.00 0.00
0.00 0.00
0.00 0.00
000* 000
OQO 000
000 < 000
OQD < 000
ODD' OW
0.00 0.00
0.00 0.00
0.00 0.00
0.00 . 0.00
0.00 0.00
\; 28 08 - aK,18"f
V -'28,93 " 853,487
: .33>9S;- £97,402
753,010
Nat.QaBFJe!
ROTmnf^
.1MMscf/vr)
0.00
0.00
0.00
0.00
0.00
000
000
ooo
000
000
0.00
0.00
0.00
0.00
0.00
,: ftoo
;. , QSO
* "0.00
- - ,• OiW
- 'boa
0.00
0.00
0.00
0.00
0.00
0.00
t «DOO
000
0,00
000
0.00
0.00
0.00
0.00
0.00
000
- 000
000
000
•000
0.00
0.00
0.00
0.00
0.00
,-<" , ^ ' 2i41
2*8^
7.16
> - , ' > - „ v - ' - . ,
Bmisslotis (toisM)
.CO' . NOx -,.SO2. - IHC... .- TSi?»'.*»'»TBtari.
0.34 1.55 0.10 0.12 0.11 2.23
. 0.34 1.55 0.10 0.12 0.11 2.23
0.34 1.55 0.10 0.12 0.11 2.23
0.34 1.55 0.10 0.12 0.11 2.23
0.34 1.56 0.10 0.12 0.11 2.23
0,34 * tSB 0 t ,0,19,,' 0;ia , * S<36
-••' -oa$l „ - 1-84' \' :oH*>" ;' 0.18 , '- '$2. ,a,«s
, ,0,38s -,, g»° ; 0,1-1- -"• OilSI « 0,12 8?»
"036 « 1,65, O.t1 ' S.13- 0.14 '647
0.36 1.66 0.11 0.13 0.12 239
0.36 1,67 0.11 0.13 0.12 2.39
• 0.36 1.66 0.11 0.13 0.12 2.41
0.37 1,69 0.11 0.14 0.12 2.42
0.37 1.69 0.11 0.14 0.12 2.43
037 178 011 0,14 0,18 , 2.4?
* 037 1,?2 Of1 OJ41 0,12 447
037 , -m Qfl '014 012, ' 248
038 173 012 < 014 012 249
0,SB 174 OlS 014 x 0181' 849
0.40 1.84 0.12 0.15 0.13 2.64
0.41 1.88 0.12 0.15 0.13 269
0.42 1.94 0.13 0.16 0.14 2.78
0.42 1.95 0,13 0.16 0.14 2.79
0.42 1.95 0.13 0.16 0.14 2.80
0,43 198 019 0,16 0,14, 284
, 0,43 1.9$ OW xl< 0,16 014 2,84
043 198 , 0,J4 0,J6 0,14 284
045 . 207 014 «17 v 015 a«8
047- 218 Ot8 Om "016 814
0.53 2.47 0.16 0.20 0.18 3.54
0.56 2.61 0.17 0.21 0.19 3.74
062 2.85 0.19 0.23 0.20 4.09
0.65 3.02 0,20 024 022 4.33
0.66 3.04 0.20 0.24 0.22 4.37
' t'<'ttS6 < -2,67, ," ,0,00 , 1.09 'OS*' V4.12
0,45* ; *335 -'; '0,00f '",1.37 * 0.00 ' -5,1&
052' ,'993>:"-0,00 1,60 - '0,00''""" 606
19.18 92.43 5.49 10.66 5.89 133.65
•TRC perm it pending
Medium/Large TX Ind. Peimit Applicant Produced Water
Total Fuel Use
Total Air Emissions
9,680.65 BOE/yr (a)
133.65 lons/yr
(a) BOE (barrels of dl equivalent) per year Is the total diesel volume required converted to equivalent oil volume (by the factor. 1 BOE = 42 gal)
and the volume of natural gas required converted to equivalent oil volume (by the factor: 1,000scf = 0.178 BOE).
OBPWNWQ.WK3
-------
APPENDIX Xm-6
ENERGY REQUIREMENTS AND AIR EMISSIONS FOR LOUISIANA OPEN BAY
DISCHARGERS AND TEXAS DISCHARGERS SEEKING INDIVIDUAL PERMITS
OPTIONS 2 AND 3: ZERO DISCHARGE VIA SUBSURFACE INJECTION
A-94
-------
LA OPEN BAY PRODUCED WATER DISCHARGERS' NWQI ANALYSIS
OPTIONS 2 AND 3
INJECTION FOR MEDIUM/LARGE-VOLUME FACILITIES
Number '
Volume -,
(bidl - (hi))
Elsies Power
' - Ifse--
-flits- firAir) taal/vri~
1;; 'Prom Natural Sas
Fwlnj Pumps
-.IIW.-
' PuetUse
o (MMScfMl
NOlt V
THO
T8P
&
2915
2952
2704
2901
3072
'SOOt
2825'
2898
* 18fe
2273
2995
3014
4206
2881
2142
1856
1934
2084
2618
(.3320
!'*'' 2604
130
223
524
1,076
1,489
2,017 ,'
- 2^910 *'-
•3,617 v
•" 4,621 ,
4,621
4,621
4,621
4,621
5,010
- S,3|,-, ,24.tfO-• ' 2"JO;249'-
' 84,00" -, $10,249
' 24.00-- 210,240
445,534
580,087
-'1,04^00,6
,tS2.e9;, \WSQp!K-
182.68 1,600,277
182.68 1,600,277
182.68 1,600,277
182.68 1,600,277
197.14 1.726,946
70 C ,2,810,612
4,028,549
4,980,936
5,200,812
5,548,672
7,423,837
4.38
5.71
'1S74
15.74
15.74
15.74
15.74
J6.99
-,22,7»
0.19 0.90
0.29 1.32
0.58 2.67
0.81 6.10
1.06 7.94
137 „,. 10.29?
, 37,79
39.63
49.00
51.17
54.59
72.52
72.77
.139083-* -12,183,671 , !*'-'? 117.74
7.35
9.09
9.49
10.13
13.45
•1350 '
13 93-,
, 21 84,
1,90 -
2,32 I7*t» >
292 -21.90
2.92 21.90
2.92 21.90
2.92 21.90
2.92 21.90
3.15^ 23.63
422 ' -31.61
-5X57
55.14
68.17
71.18
75.94
100.89
101.23
0.06
0.09
0.18
0.00
0.00
•q.oa
'. o'so
euro „
0.00
0.00
0.00
0.00
,0.00
o!oi
1 oil.
0.01 22.51
0.01 27.84
0.01 29.07
0.01 31.01
0.02 41.20
0.02 ',' 41.34 -
0.00
0.01
0.01
2.49
3.24
4 -7,12
-- S.94
8.94
8.94
8.94
8.94
9.65
''10.36
-'12.91
'• ,,,15,76,
20.20,
163.80
.1,.5S1^9..L^3,677,776 .- •.;. $fM
^447,, -, 183S4-
"0.03 , 66.86,
,0,03, ' 08.00" '
.0.03,.' .74.95-.
0.00
0.00
0.00
0.00
0.00
0..00 •
to,!do-
0.00
0.00
0.00
0.00
0.00
0.00..
», 0,00,
0.00>i-
' o^oo':
, 0,00 •
0.00
0.00
0.00
0.00
0.00
000 ,
",0,00,
,,-'o.oo -
1.16
1.70
3.44
9.4O
12.24
,,16,87;
33,77
33.77
33.77
33.77
33.77
36,44
4BJ*
59,51
85.01
105.11
109.75
117.09
155.56
«^»
"'2S2.B5
329,678
317,462 20,953
-- 2,899.862
-- 109.665,652
1,070
199.59 1.493.87
0.57 608.02
0.00 2.30Z05
Medium/Large LA Open Bay Produced Water
Zero Discharge NWQI Summary Data
Total Fuel Use
Total Air Emissions
191.016 BOE/yr (a)
2,302 tonsM
(a) BOE (barrels of oil equivalent) per year is the total diesel volume requked converted to equivalent oil volume (by the factor: 1 BOE = 42 gal)
and the volume of natural gas required converted to equivalent oil volume (by the factor: 1,000 scf = 0.178 BOE).
OBPWNWQ.WK3
-------
LOUISIANA OPEN BAY DISCHARGERS
OPTIONS 2 AND 3
SMALL VOLUME FACILITIES3
Commercial Disposal of Produced Water via Barge
Source
Pump +
Compressor
Tug
Total
::
Diesel Usage
(gal/yr)
159.21
55,881.12
56,040.23
* s^ ^
^ *>."'•
•fe y^ to* ^V.''"''''-'- *
*B0E/5fe
3.79
1,330.50
1,334.29
*"- , \ *f " \ " , ; ',! '&#>'* *' * '' n ' " ''"'" j ''
I ,,',;-'' Air'Emissions (ions/yr) ' - ',
£ ' ; f •• f -.'**' ~f, ,-•••'',
\ NOy ,THC SO2 CO "'- TSP , Total
0.037 0.003 0.002 0.008 0.003 0.053
10.94 0.47 0.80 2.19 0.92 15.32
10.977 0.473 0.802 2.198 0.923 15.373
* Detailed calculations of the above values are presented in Appendix XD1-7.
A-96
-------
TEXAS INDIVIDUAL. PERMIT «TUCANrs'PnOOUC£D WATER NWQI ANALYSIS
OPTIONS 2 AND 3
INJECTION FDR MEDIUMfl-AHGE-VOLUME FACILITIES
* TRC permit pending
Medium/LcugeTXInd. Remit Applicant Prodi Feed Water
Zero Dlsctiama NWQI Summary Dafc
TrtalRielUsB
Total Air Emissinns
36,020.60 BOEftt I
44B.B1 tcns/yr
s of
-------
TEXAS INDIVIDUAL PEBM1T APPLICANTS' NWQI ANALYSIS
OPTIONS 2 AND 3
SMALL VOLUME FAC1UT1ES
Commercial Produced Water Disposal vta Truck
Permit
No.
Location
Current
Voi. (bpd)
No. ofTru
Trips/yr
Miles
: Travaledfrr
Diesel Fuel
Usage {galft
CO
NOX
Emissions (tons/yr)
SO2
THC
TSP
Total
Corpus Christ! Bay
Kellers Bay
San Antonio Bay
Cox Bay
Tabbs Bay
2,576.40
1,840,80
5,521.20
14,722.80
1,104.00
(loose Creek
Mustang *-«
Corpus Christ) Pay>
.'**.
736,60
Mustang Island
Corpus Christt Bay
Corpus Chrlsti Bay
Copano Bay
Cedar Lake
* S684ti
16,195.20
368.40
8,097.60
8,833.20
3,680.40
644.10
460.20
1,380.30
3,680.70
276.00
4,508,70
, 183,90
<9,680,70
•A 1,472.40
; ' 92,10,
4,048.80!
92.10.
2,024.40
2,208.30
920.10
ir, -'
Sablne River
Matagorda Bay
Matagorda Bay
Matagorda Bay
itfiSSS^iii^fciS^S
785,80
10,674.00
22,083.60
11.4CH.80
25,396.80
183,90
2,668.50
5,520^0
2,852.40
6,849,20
TOTAL
581
213.847.20
53.461.80
2.01
2.64
0,00
0.59
0.00
5.24
* TRC permit pending
TX Produced Water Small Facilities
Zero Discharge Option NWQI Summary Data
Total Fuel Use
Total Air Emissions
1.272.90 BOgyr (a)
5.24 tons/yr
(a) BOE (barrelsof oil equivalent) peryear is the total dfessi volume required converted to equivalent oil volume (by the factor: 1- BOE = 42 gal)
and the volume of natural gas required converted to equivale nt oil volume (by the factor; 1,000 scf = 0.178 BOE).
TXOBNWQI.WK3
-------
APPENDIX Xm-7
CALCULATIONS FOR ENERGY REQUIREMENTS AND AER EMISSIONS FOR
LOUISIANA OPEN BAY SMALL VOLUME FACILmES
A-99
-------
LOUISIANA OPEN BAY DISCHARGERS
SMALL VOLUME FACILITIES
NWQI Calculations for AH Options
Calculations are based on the methodology presented in Chapter XI of the 1995 Coastal Oil and Gas
Development Document (EPA, 1995).
1. Each facility has one onsite storage tank sized to hold one week's produced water volume, as
follows.
• Facilities with flows less than or equal to 21 bpd will install one 150 bbl storage
tank.
• Facilities with flows greater than 21 bpd but less than or equal to 43 bpd will
install one 300 bbl storage tank.
• Facilities with flows greater than 43 bpd but less than or equal to 71 bpd will
install one 500 bbl storage tank.
2. Barges are used to transport produced water from facilities. Barge capacity is 3,000 bbl. Each
barge will service multiple facilities to full capacity or as close to full as possible, given each
facility's onsite storage capacity.
3. Barge trip frequency and the order of pick up from each facility is dependent on the facility's
produced water flow and onsite storage tank capacity.
4. The total annual diesel fuel consumption associated with the transportation of produced water was
calculated based on yearly barge trip cycles.
5. Loading of produced water into the barge is accomplished by gravity.
6. Unloading of produced water from the barge is accomplished by vacuum pump.
Input Data (Appendices referenced below are in the 1995 Coastal Oil and Gas Development
Document):
• Distance between facilities (Appendix XI-1, EPA, 1995) 10 miles
• Distance between port and facility (Appendix XI-1, EPA, 1995) 50 miles
• Distance to disposal facility (Appendix XI-1, EPA, 1995) 50 miles
• Tug fuel consumption (Appendix XVI-5, EPA, 1995) 24 gal diesel/hr
• Tug traveling speed (Appendix XI-1, EPA, 1995) 6 miles/hr
• Time to load/unload barge (Appendix XI-1, EPA, 1995) 8 hours
• Time to dock (Appendix XI-1, EPA, 1995) 1 hour
• Time to leave each facility (Chapter XVI, EPA, 1995) 15 minutes
• 4" vacuum pump rate (Appendix XVI-5, EPA, 1995) 60,000 gal/hr
• 4" vacuum pump fuel consumption (Appendix XVI-5, EPA, 1995) 0.60 gal diesel/hr
• Compressor fuel consumption (Appendix XVI-5, ref. 4) 3.5 gal diesel/hr
A-100
-------
Louisiana Open Bay Small-Volume Discharger Facilities
(For Both Gas Flotation and Injection Options)
Operator
and Permit
Number
1. 2827
2.2856
3.3023
4.2479
5. 2857
6. 1870
7. 3032
PW
Volume fbpcD
1.0
3.0
3.4
10
20
49
50
Storage Tank
Capacity fbbD
150
150
150
150
150
500
500
Storage Tank
Capacity (days)
150
5
44.1
15
7.5
10.2
10
Pick-up
Order
7
6
5
4
1
3
2
A-101
-------
CYCLE A WITH OPERATORS 4, 5, 6 AND 7
Day Number"
1-6
6.25
6.64
6.78
6.94
7.05
Time
6:00 am
2:20 pm
3:20 pm
3:42 pm
3:57 pm
5:37 pm
6:37 pm
7:32 pm
7:47 pm
9:27 pm
10:27 pm
11:22 pm
11:37 pm
1:17 am
2:17 am
2:27 am
2:42 am
11:02 am
12:02 pm
2:24 pm
2:39 pm
10:59 pm
ll:59pm
ff •> ^-wx S-^^'frW'-W-'v^X •£ f \.f
•. 5-"" """' •• ^ -.
" \ ^ c > ^ -.-. s-. •- &*,-* u
- • '1 Activity $ , -
> ^ ••^y f t\ ^ •• •^
5 •• ' •. > 5 ^ i^
Barge leaves port
Barge arrives @ #5
Barge docks @ #5
PW loaded (132.8)
Barge leaves #5
Barge arrives @ #7
Barge docks @ #7
PW loaded (339)
Barge leaves #7
Barge arrives @ #6
Barge docks @ #6
PW loaded (340.06)
Barge leaves #6
Barge arrives @ #4
Barge docks @ #4
PW loaded (70.5)
Barge leaves #4
Barge arrives @ Disp. Fac.
Barge docks @ Disp. Fac.
PW unloaded (882.36)
Barge leaves Disp. Fac.
Barge arrives @ port
Barge docks @ port
'" Tune '
f!ftr)\
-
8:20
1:00
0:22
0:15
1:40
1:00
0:55
0:15
1:40
1:00
0:55
0:15
1:40
1:00
0:12
0:15
8:20
1:00
2:22
0:15
8:20
1:00
Distance
Travelfeif,
:
-
50
0
0
0
10
0
0
0
10
0
0
0
10
0
0
0
50
0
0
0
50
0
Total
Time Tag
Operating
r ;
-
8.33
1.00
.37
.25
1.67
1.00
0
0.25
1.67
1.00
0
0.25
1.67
1.00
0.20
0.25
8.33
1.00
0
0.25
8.33
1.00
37.82
1 "ihuel
Consumed
'<§&> "
-
199.92
24
8.88
6
40.08
24
0
6
40.08
24
0
6
40.08
24
4.8
,6
199.92
24
0
6
199.92
24
907.68
n P^r
; Loaded
$bb)'
.-
132.8
339
340.06
70.5
* The day number multiplied by the facility's produced water flow equals the produced water volume loaded. See notes on produced water
barge trip cycles following these tables.
A-102
-------
CYCLE B WITH OPERATORS 2, 3, 4, 5, 6, AND 7
Bay^umfeer*?-
'•. -S"^
-.•:
1-6 (1-42)
6.25 (42.25)
6.64 (42.64)
6.78 (42.78)
6.94 (42.94)
7.05 (43.05)
7.22 (43.22)
7.36 (43.36)
8.30 (44.30)
,,, time-
s
6:00 am
2:20 pm
3:20 pm
3:42 pm
3:57 pm
5:37 pm
6:37 pm
7:32 pm
7:47 pm
9:27 pm
10:27 pm
ll:22pm
ll:37pm
1:17 am
2: 17 am
2:27 am
2:42 am
4:22 am
5:22 am
5:46 am
6:01 am
7:41 am
8:41 am
9:02 am
9:17 am
5:37 pm
6:37 pm
9:43 pm
9:58 pm
6:18 am
7:18 am
, „ ,;, •• ,„ „ „. , '„ ,„„ ,
J ''• *"•
'Ac4^^W;
Barge leaves port
Barge arrives @ #5
Barge docks @ #5
PW loaded (132.8)
Barge leaves #5 =
Barge arrives @ #7
Barge docks @ #7
PW loaded (339) '
Barge leaves #7
Barge arrives @ #6
Barge docks @ #6
PW loaded (340.06)
Barge leaves #6
Barge arrives @ #4
Barge docks @ #4
PW loaded (70.5)
Barge leaves #4 •
Barge arrives @ #3
Barge docks @ #3,
PW loaded (146.95)
Barge leaves #3
Barge arrives @ #2
Barge docks @ #2
PW loaded (130.08)
Barge leaves #2
Barge arrives @ Disp. Fac.
Barge docks @ Disp. Fac.
PW unloaded (1159.39)
Barge leaves Disp. Fac.
Barge arrives @ port
Barge docks @ port
Tome
Elapsed
-"WBfr^
-
8:20
1:00
0:22
0:15
1:40
1:00
0:55
0:15
1:40
1:00
0:55
0:15
1:40
1:00
0:12
0:15
1:40
1:00
0:24
0:15
1:40
1:00
0:21
0:15
8:20
1:00
3:06
0:15
8:20
1:00
Distance ..
Travelled
;- -M)^ '
-
50
0
0
0
10
0
0
0
" 10
0
0
0
10
0
0
0
10
0
0
0
10
0
0
0
50
0
0
0
50
0
Total
gfaKfee -
Operating
--: W /
.
8.33
1.00
.37
.25
1.67
1.00
0
0.25
1.67
1.00
0
0.25
1.67
1.00
0.20
0.25
1.67
1.00
0.39
0.25
1.67
1.00
0.35
0.25
8.33
1.00
0
0.25
8.33
1.00
44.40
- Ifcel-; *
Consumed .
»l"&a? y
.
199.92
24
8.88
6
40.08
24
0
6
40.08
24
0
6
40.08
24
4.80
6
40.08
24
9.36
6
40.08
24
8.40
6
199.92
24
0
6
199.92
24
1,065.60
^ FW
Loaded :
' .{bWs)..,
-
132.8
339
340.06
70.5
146.95
130.08
a The day number multiplied by the facility's produced water flow equals die produced water volume loaded. See notes on produced water barge trip cycles
following these tables. !
A-103
-------
CYCLE C WITH ALL OPERATORS
Day Number*
1-6 (1-126)
6.25 (126.25)
6.64(126.64)
6.78 (126.78)
6.94 (126.94)
7.05 (127.05)
7.22 (127.22)
7.36(127.36)
7.50 (127.50)
8.45 (128.45)
Time
6:00 am
2:20 pm
3:20 pm
3:42 pm
3:57 pm
5:37 pm
6:37 pm
7:32 pm
7:47 pra
9:27 pm
10:27 pm
11:22 pm
ll:37pm
1:17 am
2:17 am
2:27 am
2:42 am
4:22 am
5:22 am
5:46 am
6:01 am
7:41 am
8:41 am
9:02 am
9:17 am
10:57 am
11:57 am
12:18 pm
12:33 pm
8:53 pm
9:53 pm
1:19 am
1:34 am
9:54 am
10:54 am
^ '• ; -S- 4
-
Atiivtty 4
<* v v ,*•* -S-
-s?
Barge leaves port
Barge arrives @ #5
Barge docks @ #5
PW loaded (132.8)
Barge leaves #5
Barge arrives @ #7
Barge docks @ #7
PW loaded (339)
Barge leaves #7
Barge arrives @ #6
Barge docks @ #6
PW loaded (340.06)
Barge leaves #6
Barge arrives @ #4
Barge docks © #4
PW loaded (70.5)
Barge leaves #4
Barge arrives @ #3
Barge docks @ #3
PW loaded (146.95) •
Barge leaves #3
Barge arrives @ #2
Barge docks @ #2
PW loaded (130.08)
Barge leaves #2
Barge arrives @ #1
Barge docks @ #1
PW loaded (127.50)
Barge leaves #1
Barge arrives @ Disp. Fac.
Barge docks @ Disp. Fac.
PW unloaded (1286.89)
Barge leaves Disp. Fac.
Barge arrives @ port
Barge docks @ port
< /n»e
* Elapsed
< x#*r
.
8:20
1:00
0:22
0:15
1:40
1:00
0:55
0:15
1:40
1:00
0:55
0:15
1:40
1:00
0:12
0:15
1:40
1:00
0:24
0:15
1:40
1:00
0:21
0:15
1:40
1:00
0:21
0:15
8:20
1:00
3:26
0:15
8:20
1:00
Distance "
Travelled -
frri)
-
50
0
0
0
10
0
0
0
10
0
0
0
10
0
0
0
10
0
0
0
10
0
0
0
10
0
0
0
50
0
0
0
50
0
Total
Tune Tug
Operating
flu-)
-
8.33
1.00
.37
.25
1.67
1.00
0
0.25
1.67
1.00
0
0.25
1.67
1.00
0.20
0.25
1.67
1.00
0.39
0.25
1.67
1.00
0.35
0.25
1.67
1.00
0.35
0.25
8.33
1.00
0
0.25
8.33
1.00
47.67
Pud
Consumed
&al)
.
199.92
24
8.88
6
40.08
24
0
6
40.08
24
0
6
40.08
24
4.8
6
40.08
24
9.36
6
40.08
24
8.4
6
40.08
24
8.4
6
199.92
24
0
6
199.92
24
1,144.08
FWI^ed
(bbls)
-
132.8
339
340.06
70.5
146.95
130.08
127.50
1 The day number multiplied by the facility's produced water flow equals the produced water volume loaded. See notes on produced water barge trip cycles
following these tables.
A-104
-------
Notes on Produced Water Barge Trip Cycles for Small Volume Louisiana Facilities
• The first number of days represents the amount of time needed for the first operator to reach produced water
storage capacity. This amount of time varies with the addition of operators to each cycle. That is, for operator
5, days 1 through 6 are needed to reach capacity. These days are included in the tables for all cycles because
operator 5 is included in all cycles. For operator 3, days 1 through 42 are needed to reach capacity. These
days are included in the tables for cycles B and C only. For operator 1, days 1 through 126 are needed to reach
capacity. These days are included in cycle C only.
• The produced water volume accumulated is calculated as follows:
Day number x flow (bpd) = Produced water volume accumulated (bbl)
• Cycle A occurs 52 times a year. Operators 4, 5, 6, and 7 must have their produced water picked up every six
days. Operator 5 determines the cycle frequency since its storage capacity is limited to 7 days. The order of
pick up by the barge is dependent pn the number of days of produced water storage capacity of each facility.
• Cycle B occurs 6 times a year. In addition to the operators in cycle A (i.e. operators 4, 5, 6, and 7), cycle B
also includes operators 2 and 3. For operators 4, 5, 6, and 7 the produced water pick up cycle begins on day
6. However, for operators 2 and 3, cycle B begins on day 42.
• Cycle C occurs 2 times a year and picks up produced water from all operators, including operator 1. For
operator 1, cycle C begins on day 126.
• In each cycle, the day number corresponding to each facility's pick up schedule multiplied by the facility's
produced water flow (in bpd) equals the volume of produced water loaded onto the barge.
A-105
-------
Tug Boat Fuel Consumption Calculation:
*• (cycle A iterations per year x 907.68 gal) + (cycle B iterations per year x 1,065.60 gal) + (cycle C iterations x 1,144.08 gal)
- (52 x 907.68 gal) 4- (6 x 1,065.60 gal) + (2 x 1,144.08 gal)
- (47,199.36 gal) -I- (6,393.60 gal) + (2,288.16 gal)
-55,881.12 gal diesel/yr
Auxiliary Equipment Fuel Consumption Calculation:
Cycle A:
(882.36 bbl PW) x (42 galfbbt) - 37-059-12 8al PW _ 0 61g hrfcycie
60,000 galfhr
Pump = 0.60 gal/hr x 0.618 hr/cycle = 0.37 gal/cycle
* 0.37 gal/cycle x 52 eycles/yr = 19.27 gal/yr
Compressor = 3.5 gal/hr x 0,618 hr/cycle x 52 cycles = 112.48 gal/yr
Cycle B:
(1.159.39 bbl FW) x (42 galtbbt) = Q gl2
60,000
Pump = 0.60 gal/hr x 0.812 hr/cycle x 6 eyeles/yr = 2.92 gal/yr
Compressor = 3.5 gal/hr x 0.812 hr/cycle x 6 = 17.052 gal/yr
Cycle C:
(1.286.89 bbl PW) x (42 gallbbl)
60,000 galfhr
0.901 hr
Pump — 0.60 gal/hr x 0.901 hr/cycle x 2 eycles/yr = 1.08 gal/yr
Compressor *« 3.5 gal/hr x 0.901 hr/cycle x 2 cycles/yr = 6.31 gal/yr
A-106
-------
TOTAL DIESEL FUEL CONSUMPTION
"" " - -v, ' >, j*r
.. JFuel; Consur
- ^ Tug : '' ;""Pmp'
55,881.12 23,27
ap'fioa (gaf/yr)
" I 'Compressor'
135.84
* - ,
~ Total' ~
56,040.23
viofejri..;'.
1,334.3
BOE (barrels of oil equivalent) per year is the total diesel volume required converted to
equivalent oil volume by the factor: 1 BOE = 42 gallons.
AIR EMISSIONS
Source ;
Pump +
Compressor
Tug
159.21
55,881.12
,r /^'AkE^sionsio^j;' ,r Y±
!
0.037
10.94
Total
*m/"* s'^' c^i x -f^fZk
i, XX>-' O-v2 Xxv
0.003 0.002 0.008
0.47 0.80 2.19
TSI? Total ..,
0.003 0.053
0.92 15.32
15.373
EMISSION FACTORS
*• s V *%•'•
Pomp +
Compressor1
Tug2
f tftt, <•/ / Sf* ttt'ffttt
„ N%/
469
391.7
iTnissioii
THC
37.5
16.8
"-"-;'", /
'J&1«
31.2
28.48
i&/I#£ai
" * CO^-
102
78.3
~
-------
APPENDIX Xin-8
CALCULATIONS FOR ENERGY REQUIREMENTS AND AIR EMISSIONS FOR
TEXAS SMALL VOLUME FACILITIES
A-10S
-------
TEXAS INDIVIDUAL PERMIT DISCHARGERS
SMALL FACILITIES
' NWQI Calculations
Input Data:
All data is from Chapter XVI of the 1995 Development Document (EPA, 1995)
• Truck capacity ! 119 barrels
• Truck diesel fuel usage J 4 mi/gal
• Round-trip distance between each facility and the commercial disposal facility 120 miles
Sample Calculation:
(For a facility generating 7 bpd produced water)
« Number of trucks per year:
(2,555 bbl PW/yr)/(119 bbl/track) - 21.47 trucks/yr
i
• Truck fuel consumption:
(21.47 traeks/yr) x (1 gal/4 miles) x 120 miles/truck = 644.1 gal diesel/yr
A-109
-------
APPENDIX Xm-9
GULF OF MEXICO TREATMENT, WORKOVER AND COMPLETION
FLUID VOLUME CALCULATIONS FOR
EXISTING AND NEW SOURCES
A-110
-------
TABLE A
TWC FLUID VOLUME CALCULATIONS FOR EXISTING SOURCES
.. ^' < '" "
;/: ' : '• :" • \"
Medium/Large Facilities:
Major Pass Dischargers
General Permit Facilities
Small Facilities:
Water-Access
Land-Access
•'Number '<
,,p'fW/T -
X, *, ,
25
212
52
28
^•gj*;
587
587
587
587
total ,'•;
V$/TYol/-
* -f, ft)
14,675
124,444
30,524
16,436
Completion
•> .Jobs/yr* [
WIO^L :'-'
23
202
51
26
^ Completion
^vol'»^Job f ^
v' , "
209
209
209
209
•:'"}*$3&.S\:C^^
Medium/Large Facilities'1
Small Facilities:
Water-Access
Land-Access
270
52
28
587
587
587
158,490
30,524
16,436
257
51
26
209
209
209
!,. Total.'*/
Completion
. V<»|. (bbj/yr) /
',
4,807°
42,218
10,659
5,434
'£'t, v,'.t:
53,713
10,659
5,434
"f ofa|,TWp Volume' "
"v " ^ * ~"
-.'•-,** ^ - f
19,482
166,662
41,183
21,870
;;Vyf '::*-"'-"» ;\>
212,203
41,183
21,870
" Source: Avanti Corp., "Compliance Costs and Pollutant Removals for Coastal Gulf of Mexico Oil and Gas Well Treatment, Workover, and Completion Fluids," September 16,
1996.
b Source: SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31, 1995.
0 The number of major pass discharger W/T and completion jobs per year for Option 1 excludes the number of jobs at facilities with existing IGF or gas flotation treatment systems
(i.e., 33 W/T jobs/yr and 32 completion jobs/yr have been excluded).
d Includes all major pass dischargers and general permit facilities (see also definitions in Section 4.0).
-------
TABLES
TWC FLUID VOLUME CALCULATIONS FOR NEW SOURCES
Facility Type
-
Medium/Large Facilities:
Major Pass Dischargers
General Permit Facilities
Small Facilities:
Water-Access
Land-Access
"3
Medium/Large Facilities
Small Facilities:
Water-Access
Land-Access
Number
of W/T
Jobs/yr*
*-'<&''/>
6
29
7
3
s? :;
35
7
3
W/T
, Voh/Job"
$$y&
s'i*. "' '- '-',
587
587
587
587
* * ',*:
587
587
587
Total
W/T Vol.
(bbl/yr)
v AV}jt^_&J,VJr
3,522
17,023
4,109
1,761
oyrioNsa
20,545
4,109
1,761
Number of
Completion
Jobs/yrJ _
si , , "•$<'-¥
6
29
7
3
^W3 r v
35
7
3
Completion
Vol./Job"
(bbj/yr) -
•*<, - Vr.,*
209
209
209
209
- > v^>
209
209
209
Total
Completion
Vol. (bbl/yr)
- ' t* *L '
1,254
6,061
1,463
627
\* ' *^*
7,315
1,463
627
Total TWC
Volume
, -
27,860
5,572
2,388
G
a Source: Atanti Corp., "Compliance Costs and Pollutant Removals for Coastal Gulf of Mexico Oil and Gas Well Treatment, Workover, and Completion Fluids," September 16,
1996.
b Source: SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31,1995.
-------
APPENDIX Xm-10
SUMMARY FUEL CONSUMPTION CALCULATIONS FOR
SMALL FACILITIES
A-113
-------
SUMMARY FUEL CONSUMPTION CALCULATIONS FOR SMALL FACILITIES3
jMsting Facilities:
Lund-Access Facilities':
• Number of track trips per year:
(21,870 bbyyr)/(119 bbl/truck) = 183.8 trueks/yr
• Truck fuel consumption:
(183.8 trucks/yr) x (1 gal/4 Dalles) x (120 miles/truck) = 5,513 gal/yr
^Voter-Access Facilities:
• Tag and barge transit fuel consumption:
(103 trips/yr) x (100 miles/trip) x (24 gal/far) x (1 hr/6 miles) = 41,200 gal/yr
* Auxiliary equipment fuel consumption:
1(1 hr/trip) x (103 trips/yr) x (6 gal/hr)] 4- [(4.1 gal/hr) x (1.05 hr/trip) x (103 trips/yr)] - 1,061 gal/yr
l^few Facilities;
cess Facilities:
* Number of truck trips per year:
(2,388 bbl/yr)/(l 19 bbl/truck) = 20.1 trucks/yr
• Truck fuel consumption:
(20.1 trucks/yr) x (1 gal/4 miles) x (120 mEes/ttuck) = 602 gal/yr
Waiter-Access Facilities:
* Tug and barge transit fuel consumption:
(14 trips/yr) x (100 miles/trip) x (24 gal/hr) x (1 hr/6 miles) = 5,600 gal/yr
* Auxiliary equipment fuel consumption:
[(I hr/trip) x (14 trips/yr) x (6 gal/hr)] + [(4.1 gal/hr) x (1.05 hr/trip) x (14 trips/yr)] = 144 gal/yr
* All data presented here are from: EPA, "Development Document For Effluent Limitations Guidelines and
Standards for the Coastal Subeategory of the Oil and Gas Extraction Point Source Category," February, 1995.
A-114
-------
|