vvEPA
United States
Environmental Protection
Agency
Office of Water
fWH-552)
Washington DC 20460
EPA 440/1-91/055
March 1991
Development
Document for
Effluent Limitation
Guidelines and
Standards for the
Offshore Subcategory
of the
Oil and Gas Extraction
Point Source Category
Proposed
-------
TABLE OF CONTENTS
Page
I EXECUTIVE SUMMARY
II INTRODUCTION
A. PURPOSE AND AUTHORITY II-l
B. LEGAL BACKGROUND ' II-2
1. Best Practicable Control Technology
Currently Available (BPT) . . II-3
2. Best Available Technology Economically
Achievable (BAT) . II-3
3. Best Conventional Pollutant Control
Technology (BCT) . II-4
4. New Source Performance Standards (NSPS) . II-5
5. Best Management Practices (BMPs) .... II-5
C. PRIOR EPA RULEMAKINGS II-5
1. Previous Rulemaking for the Offshore
Subcategory II-5
2. Summary of the 1985 Proposal by Level
of Control and Waste Stream 11-10
3. The 1988 Notice of Data Availability . . 11-18
D. SUMMARY OF METHODOLOGY 11-19
III INDUSTRY PROFILE
A. INTRODUCTION III-l
B. EXPLORATION III-3
. C. DEVELOPMENT (WELL DRILLING) III-4
D. WELL TREATMENT III-ll
E. COMPLETION/WORKOVER 111-15
F. PRODUCTION . 111-21
G. EXISTING SOURCES ... 111-28
H. NEW SOURCES 111-32
1. Drilling Activity 111-32
2. Production 111-37
iii
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TABLE OF CONTENTS. (Cont'd)
Page
I. CURRENT PERMIT STATUS . 111-39
1. Gulf of Mexico ' 111-39
2. Alaska 111-39
3. California IJI-40
J. REFERENCES ' 111-44
IV INDUSTRY SUBCATEGORIZATION AND DEFINITIONS
A. INTRODUCTION I' -1
B. SHALLOW/DEEP WATERS IV-2
C. DISTANCE FROM SHORE IV-4
D. REGULATORY DEFINITIONS IV-10
1. Inner Boundaries of the Territorial Seas IV-10
2. Domestic Waste IV-11
3. Minor Wastes IV-11
4. Well Treatment, Completion, and Workover
Fluids IV-12
5. Produced Sand IV-14
6. Development Facility and Production
Facil'ty IV-16
7. New Sources . IV-16
E. REFERENCES IV-23
V PRE-1985 MAJOR DATA ACQUISITION EFFORTS
A. INTRODUCTION V-l
B. PRODUCED WATER V-l
C. DRILLING FLUIDS V-3
D. DRILL CUTTINGS V-4
E. OTHER WASTE STREAMS V-4
VI DATA/INFORMATION GATHERING - POST 1985
A. INTRODUCTION VI-1
B. PRODUCED WATER VI-1
IV
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TABLE OF CONTENTS (Cont'd)
Page
B. PRODUCED WATER (Continued)
1 Performance of Granular Media and
Membrane Filtration Technologies on
Produced Waters VI-1
2. An Evaluation of Technical Exceptions
for Brine Reinjection for the Offshore
Oil and Gas Industry ' VI-3
3. Radioactivity of Produced Water VI-5
C. DRILLING FLUIDS AND DRILL CUTTINGS OPERATIONS VI-8
1. American Petroleum Institute Drilling
Fluids Survey VI-8
2. Offshore Operators Committee Spotting
Fluid Survey VI-9
3. The EPA/API Diesel Pill Monitoring
Program VI-12
4. API-USEPA Database VI-23
D. MISCELLANEOUS AND MINOR DISCHARGES VI-23
E. TREATMENT/DISPOSAL TECHNOLOGIES FOR DRILLING
FLUIDS AND DRILL CUTTINGS VI-24
1. Offshore and Coastal Oil and Gas Extrac-
tion Industry Study of Onshore Disposal
Facilities for Drilling Fluids and Drill
Cuttings Located in the Proximity of the
Gulf of Mexico .' VI-24
2. Onshore Disposal of Offshore Drilling
Waste - Capacity and Cost of Onshore
Disposal Facilities VI-29
3. Offshore Drilling Safety . . VI-30
F. ANALYTICAL METHODS . VI-31
1. Review of Static Sheen Testing Procedures VI-31
2. Analytical Method for Diesel Oil
Detection and Total Oil Content -
Proposed Method 1651 VI-33
3. Oil and Grease VI-34
4. Drilling Fluids Toxicity Test VI-35
G. REFERENCES VI-44
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TABLE OF CONTENTS (Cont'd)
Page
VII WASTE STREAM SOURCES AND CHARACTERISTICS
A. INTRODUCTION VII-1
B. WASTEWATER SOURCES VII-2
1. Drilling Fluids VII-2
2. Drill Cuttings . . .' Vll-4
3. Well Treatment, Completion, and Workover
Fluids VII-6
4. Produced Water VII-6
5. Produced Sand VII-11
6. Deck Drainage VII-11
7. Sanitary Wastes VII-12
8. Domestic Wastes VII-12
9. Minor Discharges VII-13
C. WASTEWATER CHARACTERISTICS VII-17
1. Drilling Fluids VII-17
2. Drill Cuttings VII-42
3. Produced Water - BPT Effluents VII-44
4. Well Treatment, Completion, and Workover
Fluids VII-52
5. Produced Sand VII-54
6. Deck Drainage VII-58
7. .Sanitary and Domestic Wastes VII-61
8. Minor Discharges VII-65
D. REFERENCES VII-71
VIII SELECTION OF POLLUTANT PARAMETERS
A. INTRODUCTION VIII-1
B. DIESEL OIL VIII-1
C. FREE OIL VIII-3
D. TOXICITY (LC50) VIII-6
1. Effluent Limitations VIII-6
2. Environmental Effects and Testing
Procedures VIII-8
E. OIL CONTENT VIII-10
1. Drilling Fluids VIII-11
2. Drill Cuttings . VIII-11
vi
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TABLE OF CONTENTS (Cont'd)
IX
F.
OIL AND GREASE
1. Effluent Limitations
2. Environmental Effects
G. PRIORITY POLLUTANTS
1. Metals .
2. Organics
H.
I.
J.
FECAL COLIFORM (TOTAL RESIDUAL CHLORINE) .
FOAM
REFERENCES
CONTROL AND TREATMENT TECHNOLOGY
A. INTRODUCTION
DRILLING FLUIDS
B.
C.
D.
E.
1.
2.
BPT Technology . . .
Additional Treatment
DRILL CUTTINGS
1. BPT Technology . . .
2. Additional Treatment
PRODUCED WATER
1. BPT Technology
2. Additional Treatment - Improved
Performance of BPT Technology . . .
3. Additional Treatment - Reinjectiori
4. Additional Treatment - Filtration .
WELL TREATMENT, COMPLETION, AND WORKOVER
FLUIDS
1.
2.
BPT Technology . . .
Additional Technology
F.
PRODUCED SAND
Page
VIII-12
VIII-12
VIII-13
VIII-14
VIII-14
VIII-26
VIII-26
VIII-27
VIII-28
IX-1
IX-2
IX-2
IX-3
IX-14
IX-14
IX-15
IX-20
IX-20
IX-29
IX-31
IX-40
IX-58
IX-58
IX-59
IX-59
vii
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TABLE OF CONTENTS (Cont'd)
G.
H.
I.
J.
K.
X BPT
DECK DRAINAGE ,
*
1. BPT Technology . . . ,
2. BAT
SANITARY WASTES
1. BPT Technology
2. Additional Technologies
DOMESTIC WASTES
MINOR DISCHARGES
REFERENCES
Page
IX-60
IX-60
IX-63
IX-63
IX-63
IX-64
IX-64
IX-65
IX-66
XI REGULATORY OPTIONS CONSIDERED FOR BCT, BAT, AND
NSPS
A.
B.
C.
D.
E.
F.
G.
H.
XII BCT
A.
INTRODUCTION
DRILLING FLUIDS AND CUTTINGS
1. Options Considered
2. Alaskan Waters
PRODUCED WATERS
DECK DRAINAGE , ,
PRODUCED SAND ,
WELL TREATMENT, COMPLETION, AND WORKOVER
FLUIDS ,
SANITARY AND DOMESTIC WASTES ,
REFERENCES ,
OPTIONS SELECTION AND COSTS
METHODOLOGY ,
XI-1
XI-1
XI-1
XI-5
XI-6
XI-10
XI-11
XI-11
XI-11
XI-12
XII-1
viii
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TABLE OF CONTENTS (Cont'd)
Page
B. DRILLING FLUIDS AND CUTTINGS XII-3
1. Options Considered XII-3
2. Options Selection XII-5
C. PRODUCED WATERS XII-10
D. DECK DRAINAGE XII-11
E. PRODUCED SAND XII-15
F. WELL TREATMENT, WORKOVER, AND COMPLETION
FLUIDS XII-16
G. SANITARY WASTE/DOMESTIC WASTE XII-16
XIII BAT AND NSPS OPTIONS COSTS
A. INTRODUCTION XIII-1
B. DRILLING WASTES XIII-1
1. Data Base and Cost Scenarios XIII-1
2. Basis for Analysis and Assumptions . . . XIII-5
3. Results of Analysis XIII-9
C. PRODUCED WATER . . XIII-30
1. Data Base and Cost Scenarios XIII-32
2. BAT XIII-33
3. NSPS XIII-45
XIV NON-WATER QUALITY ENVIRONMENTAL IMPACTS
A. ENERGY REQUIREMENTS AND AIR EMISSIONS .... XIV-1
1. Drilling Waste XIV-1
2. Produced Water XIV-4
3. 6 and 8 Mile Regulatory Options XIV-10
4. Constrained vs. Unconstrained Growth
Scenarios XIV-22
B. SOLID WASTE GENERATION XIV-23
C. CONSUMPTIVE WATER LOSS XIV-27
D. SAFETY XIV-27
IX
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TABLE OF CONTENTS (Cont'd)
Page
E. UNDERGROUND-INJECTION OF PRODUCED WATER . . . XIV-27
F. REFERENCES . . ' XIV-30
XV BEST AVAILABLE TECHNOLOGY OPTIONS SELECTION
A. BAT EFFLUENT LIMITATIONS GUIDELINES XV-1
B. DRILLING FLUIDS AND DRILL CUTTINGS XV-1
1. Opt 3ns Considered XV-1
2. Options Selection . XV-8
C. PRODUCED WATER XV-9
1. Options Considered XV-9
2. Selected Options •. XV-10
D. DECK DRAINAGE XV-11
E. PRODUCED SAND XV-13
F. WELL TREATMENT AND COMPLETION FLUIDS XV-14
G. DOMESTIC AND SANITARY WASTES XV-16
XVI NEW SOURCE PERFORMANCE STANDARDS
XVII BEST MANAGEMENT PRACTICES
XVIII GLOSSARY AND ABBREVIATION,
APPENDIX 1 - ANALYSIS OF ALTERNATIVE COST AND CONTAMINANT
REMOVkL FOR GRANULAR MEDIA FILTRATION TECHNOLOGY
APPENDIX 2 - DRILLING WASTE: EXAMPLE CALCULATION FOR FUEL
REQUIREMENTS AND AIR EMISSIONS FOR ZERO
DISCHARGE REQUIREMENT
APPENDIX 3 - PRODUCED WATER: EXAMPLE CALCULATION OF ENERGY
REQUI~ ^MENTS AND AIR EMISSIONS FOR FILTRATION
AND D CHARGE ALL OPTIONS FOR GULF OF MEXICO
APPENDIX 4 - CONTAMINANT REMOVAL BY MEMBRANE FILTRATION
ACCORDING TO REGION AND REGULATORY OPTION
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LIST OF TABLES
Page
II-1 1979 Offshore Subcategory BPT Effluent
Limitations t II-7
II-2 Summary of Offshore Oil and Gas Subcategory
Federal Register Notices 11-11
II-3 Previously Proposed BAT Effluent"Limitations . . . 11-14
II-4 Previously Proposed NSPS Effluent Limitations
(Shallow Water) . 11-15
II-5 Previously Proposed NSPS Effluent Limitations
(Deep Water) 11-16
II-6 Previously Proposed BCT Effluent Limitations . . . 11-17
III-l Offshore Drilling Activity 111-12
III-2 Number of Existing Production Facilities by
Geographic Region and Production Type 111-30
III-3 Production and Value of U.S. Crude Oil and
Condensate Onshore - Offshore 111-33
III-4 Production and Value of U.S. Natural Gas
Onshore - Offshore 111-34
III-5 Annual Drilling Activity for New Sources
(For 1986 to 2000, Based on $21/barrel 111-38
III-6 New Source Production Platforms
(For 1986 to 2000, Based on $21/barrel . 111-38
III-7 General Permits Used to Develop "Current"
Baseline Costs and Loadings 111-42
III-8 Summary of Current Requirements for Drilling
Fluids and Cuttings for the Offshore Permits . . . 111-43
IV-1 Number of Existing Producing Structures by
Production Type and Water Depth IV-5
IV-2 Number of New Wells Drilled Annually According
to Water Depth (Unconstrained Growth) IV-5
IV-3 Number of New Wells Drilled Annually According
to Water Depth (Constrained Growth) IV-5
-4 New Structures During 1986-2000 According to
Water Depth (Unconstrained Growth) IV-6
xi
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LIST OF TABLES (Continued)
Table Page
IV-5 New Structures Ducing 1986-2000 According to
Water Depth (Constrained Growth) IV-6
IV-6 Existing Structures According to Distance From
Shore IV-8
IV-7 New Wells Drilled Annually According to Distance
From Shore (Unconstrained Growth) IV-8
IV-8 New Wells Drilled Annually According to Distance
From Shore (Constrained Growth) IV-9
IV-9 New Producing Structures According to Distance
From Shore (Unconstrained Growth) IV-9
IV-10 New Producing Structures According to Distance
From Shore (Constrained Growth) IV-9
VI-1 Percent Diesel Recovered Vs. Quantity of Extra
Buffer Hauled Ashore for Disposal: Dataset 3 ... VI-15
Vi-2 Pi ,..iminary Results of Round Robin Toxicity
.Testing VI-40
Vll-l Functions of Some Common Drilling Mud Chemical
Additives VII-18
VII-2 Analysis of Trace Elements in Barite Samples ... VII-21
vil-3 Comparison of Results of Solubility Experiments in
Barite Samples to Sea Water Concentrations .... VII-22
VII-4 Proposed Drilling Fluid Discharge Rates for a Gulf
of Mexico Well Drilling Program VII-26
VII-5 Summary of Drilling Fluid and Cuttings Discharge
Rates by Geographical Location (bbl/day/well) . . VII-27
VII-6 Basic Drilling Fluid Additives Usage Versus Depth
of Well VII-28
VII-7 Average Well Depth and Drilling Waste Volume . . . VII-30
VII-8 EPA Generic Drilling Fluids List VII-31
VII-9 Conventional Parameters for Generic Drilling
Fluids . VII-33
VII-10 Organic Pollutants Detected in Generic Drilling
Fluids VII-3
xii
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LIST OF TABLES (Continued)
Le . Page
VII-11 Metal Concentrations in Generic Drilling Fluids . VII-36
VII-12 Results of Acute Toxicity Tests with Generic
Drilling Fluids and Mysids (Mysidopsis Bahia) . . VII-39
VII-13 Organic Constituents of Diesel and Mineral oils . VII-40
VII-14 Metal Concentrations in Commercially Available
Water-based Drilling Fluids VII-41
VII-15 Sources, Discharge Rates, and Discharge Frequency
of Continuous Discharges from a Single Well
Located in Lower Cook Inlet, Alaska VII-43
VII-16 Characteristics of Platforms Selected for the
Gulf of Mexico Sampling Program VTI-46
VII-17 Average Produced Water Volumes for Model
Structures VII-48
vil-18 Percent Occurrence of Organics for Treated
Effluent Samples Gulf of Mexico Sampling
Program VII-49
VII-19 BPT Effluent Concentrations for Produced Waters
(Reanalysis of 3.0-Platform Study VII-51
VII-20 Arithmetic Mean Effluent Produced Water Concentrations
Found in Cook Inlet VII-53
VII-21 Summary of the Chemical Quality of Workover, Completion,
And Well Treatment Fluids Discharged in the Cook
Inlet, Alaska VII-55
VII-22 Chemical Compounds Discharged During Workover,
Completion and Well Treatment Fluid Discharge
Events VII-56
VII-23 Composition of Acidizing Treatment Fluid During
Three-Facility Study VII-57
VII-24 Pollutant Concentrations in Untreated Deck Drainage VII-59
VII-25 Quality and Quantity of Deck Drainage From
Offshore Rigs (Gulf of Mexico); Data Summarized
From Two Years of DMRs VII-60
VII-26 Hazardous Compounds Discharged in Deck Drainage . VII-62
xiii
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LIST OF TABLES (Continued)
Table
VII-27 Typical Untreated-Combined Sanitary and Domestic
Wastes from Offshore Facilities
VII-28 Typical Offshore Sanitary and Domestic Waste
Characteristics
VII-29 Properties of Minor Offshore Production Wastes . .
VII-30 Hazardous Compounds in BOP Fluid, Boiler Slowdown,
Bilge, Fire Control System, Ballast, and
Waterflooding Discharges
VII-31 Hazardous Compounds Discharged in Cooling Water
and Desalinization Wastes
VIII-1 Percent of Samples Passing Both Cadmium and
Mercury Proposed Limitations on Barite
Vlii-2 Percent of Samples Passing Both Cadmium and
Mercury Proposed Limitations on Drilling
Fluids
VIII-3 Amount of Barite Meeting Cadmium and Mercury
Limitations - 1985 Data
VIII-4 Comparison of Projected Barite Needs and
Supplies s .
IX-1 Cuttings Washer Technology
IX-2 Characteristics of Platforms Sampled in the
Three-Facility Study
IX-3 Granular Media Filtration Effluent
IX-4 Membrane Separation Technology Performance . . .
IX-5 Membrane Separation Conventional Pollutant Removal
IX-6 Estimates of Membrane Filtration Performance . . .
X-l Summary of Promulgated Final BPT Requirements . .
XI-1 Summary of Drilling Fluids and Cuttings Options
XI-2 Regulatory Options for Produced Water
Page
VII-64
VII-64
VII-66
VII-68
VII-70
VIII-19
VIII-20
VIII-221
VIII-24
IX-18
IX-42
IX-48
IX-53
IX-54
IX-56
X-2
XI-2
XI-7
xiv
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LIST OF TABLES' (Continued)
Tcrole . Page
XII-1 Proposed BCT Effluent Limitations Guidelines . . . XII-2
XII-2 Summary of BCT Drilling Fluids and Cuttings
Option XII-4
XII-3 BCT Cost Test for Drilling Fluids XII-7
XII-4 BCT Cost Test for Drill Cuttings XII-9
XII-5 Summary of Produced Water Options XII-12
XIII-1 Model Well Characteristics XIII-7
XIII-2 Toxicity/Static Sheen Failure Rates XIII-8
XIII-3 Regulatory Options and Corresponding Analysis
Results . . . . XIII-11
XIII-4A Annual Pollutant Removals and Cost Drilling
Fluids - BPT Baseline XIII-13
XIII-4B Annual Pollutant Removals and Cost
"Least Cost" BAT with 5/3 Hg/Cd Limits XIII-14
XIII-4C Annual Pollutant Removals and Cost -
Drilling Fluids - Zero Discharge XIII-15
XIII-4D Annual Pollutant Removals and Cost -
Drilling Fluids; Shallow Wells - Zero Discharge;
Deep Wells - Least Cost BAT with 5/3 Hg/Cd Limits XIII-16
XIII-4E Annual Pollutant Removals and Cost -
Drilling Fluids; "Least Cost" BAT with 1/1 Hg/Cd
Limits . . XIII-17
XIII-4F Annual Pollutant Removals and Cost -
Drilling Fluids; Shallow Wells - Zero Discharge;
Deep Wells - "Least Cost" BAT with 1/1 Hg/Cd
Limits XIII-18
XIII-4G Annual Pollutant Removals and Cost -
Drilling Fluids; Wells < 4 Miles from Shore -
Zero Discharge; Wells > 4 Miles from Shore - "Least
Cost" BAT with 5/3 Hg/Cd Limits ' XIII-19
XIII-4H Annual Pollutant Removals and Cost -
Drilling Fluids; Wells < 4 Miles from Shore -
Zero Discharge; Wells > 4 Miles from Shore - "Least
Cost" BAT with 1/1 Hg/Cd Limits XIII-2 0
xv
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LIST OF TABLES (Continued)
Table Page
XIII-4I Annual Pollutant Removals and Cost -
Drilling Fluids - BPT Baseline XIII-21
XIII-5A Annual Pollutant Removals and Cost -
Drill Cuttings - BPT Baseline XIII-22
XIII-5B Annual Pollutant Removals and Cost -
Drill Cuttings; "Least Cost" BAT with 5/3 Hg/Cd
Limits XIII-23
XIII-5C Annual Pollutant Removals and Cost -
Drill Cuttings - Zero Discharge XIII-24
XIII-5D Annual Pollutant Removals and Cost -
. Drill Cuttings; Shallow Wells - Zero Discharge;
Deep Wells "Least Cost" BAT with 5/3 Hg/Cd
Limits XIII-25
XIII-EE Annual Pollutant Removals and Cost -
Drill Cuttings; "Least Cost" BAT with 1/1 Limits
on Hg/Cd XIII-26
XIII-5F Annual Pollutant Removals and Cost -
Drill Cuttings; Shallow Wells - Zero Discharge;
Deep Wells - "Least Cost" BAT with 1/1 Limits on
Hg/Cd XIII-27
XIII-5G Annual Pollutant Removals and Cost - Drill Cuttings;
Wells < 4 Mij.es from Shore - Zero Discharge;
Wells > 4 Miles from Shore - "Least Cost" BAT with
5/3 Hg/Cd Limits .... XIII-28
XIII-5H Annual Pol"', -tant Removals and Cost - Drill Cuttings;
Wells < 4 ies from Shore - Zero Discharge;
Wells > 4 Miles from Shore - "Least Cost" BAT with
1/1 Hg/Cd Limits XIII-29
XIII-6 Annual Compliance Cost/Pollutant Removals for
Regulatory Options - Drilling Fluids and Drill
Cuttings Combined XIII-31
XIII-7 "Model" Profile of Existing Production Wells/
Shallow and Deep Wells XIII-35
XIII-8 "MiHel" Profile of Existing Production Wells
Ac .-rding to Distance from Shore XIII-37
XIII-8A BAT - Produced Water Flowrates XIII-3
xvi
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LIST OF TABLES (Continued)
Taole Page
XIII-9 Wastewater Concentration after BPT Treatment and
BAT Options for Membrane Filtration . ... . . . . XIII-40
XIII-10 Cost Data for Membrane Filtration/Surface Water
Discharge System for Produced Water Treatment . . XIII-42
XIII-11 Cost Data for Membrane Filtration/Reinjection
System for Produced Water Treatment XIII-43
XIII-12 Summary of BAT Implementation Costs and Contaminant
Removal for Membrane Filtration Systems XIII-46
XIII-13 Summary of Implementation Costs for Membrane Filter
Systems and Contaminant Removal - BAT XIII-47
XIII-13A Summary of Implementation Costs for Membrane Filter
Systems and Contaminant Removal - NSPS XIII-47
XIII-14 "MODEL" Profile of New Source Production Wells:
Shallow and Deep XIII-48
XIII-15 "MODEL" Profile of New Source Productions Wells
According to Distance From Shore XIII-51
XIII-16 NSPS - Produced Water Flowrates XIII-52
XIII-17 Cost Factors for NSPS Membrane Filtration/Surface
Water Discharge Treatment Systems ........ XIII-54
XIII-18 Cost Data for NSPS Membrane Filtration/Reinjection
System for Produced Water Treatment XIII-56
XIII-19 Summary of NSPS Implementation Costs and Contaminant
Removal for Membrane Filtration Systems XIII-58
XIII-20 Summary of Implementation Costs for Membrane Filter
Systems and Contaminant Removal - NSPS XIII-59
XIV-1 Drilling Waste Fuel Requirements and Air Emissions
Associated With Regulatory Options XIV-3
XIV-2 BAT - Produced Water Flowrates XIV-6
XIV-3 NSPS - Produced Water Flowrates XIV-7
XIV-4 BAT - Natural Gas Energy Requirements for Produced
Water Treatment XIV-8
-5 NSPS - Natural Gas Requirements for Produced Water
Treatment XIV-9
xvii
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LIST OF TABLES (Continued)
Table ' " ..
XIV-6 Option A Air Emissions for Produced Water .... XIV-11
XIV-7 Option B Air Emissions for Produced Water .... XIV-12
XIV-8 Air Emissions for Produced Water Treatment for
Filtration/Discharge All Option XIV-13
•
XIV-9 Option D Air Emissions for Produced Water
Treatment .._... . XIV-14
XIV-10 Air Emissions for Produced Water Treatment for
Filtration/Reinjection All Option XIV-15
XIV-11 Air Emissions for Produced Water Treatment .... XIV-16
XIV-12 Non-Water Quality Environmental Impacts for
Produced Waters Regulatory Options XIV-17
XIV-13 Fuel Requirements and Air Emissions Associated With
the 4, 6, and 8, Mile Drilling Waste Options . . . XIV-20
XIV-14 Comparison of Fuel Requirements and Air Emissions for
the 4, 6, and 8 Mile Options for Produced Waters . XIV-21
XIV-15 Injuries and Illness Cases per 100 Full-Time
Workers XIV-28
XV-1 Proposed BAT Effluent Limitations Guidelines . . . XV-2
XVI-1 Proposed NSPS Effluent Limitations Guidelines . . XVI-2
xviii
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LIST OF FIGURES
. . Page
III-l Typical Rotary Drilling Rig . . ......... III-5
III-2 Typical Well Showing Shaleshaker and
Blowout Preventer ........ ........ III-6
III-3 Discharges From Drilling Operation . ....... III-9
III-4 Typical Completion Methods ..... ....... 111-16
III-5 Multiple Well Completion ..... . ....... 111-17
III-6 Central Treatment Facility in and
Estuarine Area .................. 111-23
III-7 Horizontal Gas Separator ............. 111-25
III-8 Typical Vertical Heater Treater ......... 111-26
III-9 History and Projection of Oil Production in
United States OCS Areas ............. 111-35
111-10 History and Projection of Gas Production in
United States OCS Areas ............. 111-36
Vi-i Mud Toxicity as Dependent on Diesel Content . . . VI-17
VI-2 Mean LC50 Values as a Function of Approximate
Diesel Content ............ ...... VI-18
VI-3 Range of LC50 values as a Function of Diesel
Concentration .................. VI-19
VI-4 Percentage of Mud Samples with LCsos Greater
Than a Given Value ............. . . . VI-21
VI-5 Success Rate Related to Pill and Mud Density . . . VI-22
VI-6 Sampling of Produced Water Treatment System:
Oil & Grease Results Versus Time Sampling
Point SI - Skim Oil Tank Effluent ........ VI-36
VI-7 Sampling of Produced Water Treatment System:
Oil & Grease Results Versus Time Sampling
Point S2 - Flotation Units Effluent . ...... VI-37
VI-8 Sampling of Produced Water Treatment System:
Oil & Grease Results versus Time Sampling
Point S3 - Filtration Effluent ... ....... VI-3 8
xix
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LIST OF FIGURES (Continued)
Figure • . Page
VII-1 Drilling Fluids and Drill Cuttings: Discharge
Sources VII-5
VII-2 Produced Water: Recycle and Discharge VII-10
IX-1 Flow Diagram for a Typical Solids Control System . IX-16
IX-2 Typical Skim Pile IX-23
IX-3 Flow Diagram of Gas Filtration Processes for
Treatment of Produced Water IX-2 6
IX-4 Granular Media Coalescer IX-43
IX-5 Produced Water Reinjection System for a Platform
in New Mexico IX-44
IX-6 Produced Water Reinjection System for a Platform
in Long Beach, California IX-45
IX-7 Cross Section of a Monolithic Multichannel
Membralox Ceramic Filter IX-49
IX-8 Module Assembly of Several Multichannel Elements . IX-50
xx
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SECTION I
EXECUTIVE SUMMARY
This developmentDocument presents a summary of the
technical data base developed by EPA to support the current
proposed effluent limitations guidelines and standards for the
Offshore Subcategory of the Oil and Gas Extraction Point Source
Category. The performance of certain treatment technologies and
their costs form the basis for the proposed effluent limitations.
These standards are defined as best available control technology
economically achievable (BAT) and/or best conventional pollutant
control technology (BCT) for existing sources, and new source
performance standards (NSPS) for new sources. Best practicable
control technology (BPT) effluent limitations guidelines for this
industry segment were promulgated on April 13, 1979 (44 FR 22039)
and are not being altered by this rulemaking. Pretreatment
standards for new and existing sources (PSNS and PSES) are not
being developed for this industry.
The effluent limitations developed and described in this
document pertain to the following wastewater sources: produced
water? drilling fluids; drill cuttings; well treatment,
completion, and workover fluids; produced sand; deck drainage;
and sanitary and domestic waste streams. Other waste streams
were reviewed also, but no limitations are being proposed because
of insufficient data or because no control is necessary*
On August 26, 1985, the Agency proposed BAT, NSPS, and BCT
for this industry in the Federal Register (50 FR 34592) and
published a development document for the proposal. Subsequently,
a Notice of Data Availability and Request for Comments was
published in the Federal Register on October 21, 1988 (53 FR
41356). This notice presented additional data received by the
Agency following the 1985 proposal related to the development of
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discharge limitations for drilling fluids and drill cuttings.
Since 1988, the Agency has completed several studies and acquired
new information pertaining to drilling fluids and drill cuttings,
as well as produced wetter and other waste streams associated with
offshore oil and gas extraction activities. These latest
efforts, which are the focus of this document, have been directed
toward the proposal of new options or variations of the
previously proposed options developed as a result of recent data
review and analysis.
The information in this document includes a presentation of
information which supported the 1985 rulemaking and new data
gathered since 1985, including: the treatment technology options
being considered, costs and non-water quality environmental
impacts related to these options, and the rationale for selection
of the technology levels on which these new proposed effluent
limitations and standards are based. The data gathering
conducted since 1985 has focused on three areas: 1) the
variability of the proposed toxicity limitation for drilling
fluids and dri3" cuttings, 2) the prohibition of diesel oil
discharges for llling fluids and drill cuttings, and 3) the
characteristics and treatment of produced waters. Results from
these and other studies, which are described in this document,
have led the Agency to develop additional regulatory options to
those proposed in 1985. These new options along with previously
proposed options, some of which are still being considered and
are contained in the current proposal, are highlighted below by
waste stream.
A summary of 14 options have been considered for regulatory
control of drilling fluids and cuttings as follows:
Option A - 5/3 All Structures: This option has three
conditions associated with it. The toxicity limitation is
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set at 30,000 ppm in the suspended particulate phase (SPP); -
there is a prohibition on the discharge of diesel oil; and
the limitations for cadmium and mercury in the stock barite
(not in the drilling fluids system) are 5 mg/kg and 3 mg/kg,
respectively. These conditions are to be met by all
offshore structures regardless of the depth of the water in
which they are located or their distance from shore.
Option B - 1/1 All Structures; This option also has three
conditions associated with it, two of which are the same as
Option A: the toxicity limitation of 30,000 ppm in the
suspended particulate phase and the prohibition on the
discharge of diesel oil. The third condition sets
limitations for cadmium and mercury in the drilling fluids
system (either drilling fluid or drill cuttings) at 1 mg/kg
each at the point of discharge. These conditions are to be
met by all offshore structures regardless of the depth of
the water in which they are located or their distance from
shore.
Option C - Zero Discharge Shallow; 5/3 Deep: This option
distinguishes between offshore structures located in shallow
water and those offshore structures located in deep water.
(Note: Shallow water is defined by geographic region and
water depth as described in Section IV of this document.)
For offshore structures located in shallow water, there is a
zero discharge requirement for all drilling fluids which
could be met either through recycle/reuse of the spent
drilling fluid system or through transport to shore for
treatment and land disposal. For offshore structures
located in deep water, there is the toxicity limitation
based on 30,000 ppm in the suspended particulate phase; a
prohibition on the discharge of diesel oil for lubricity or
spotting purposes (mineral oil substitution); and the
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limitation of cadmium and mercury in the barite to be 5
mg/kg of Imium and 3 mg/kg of mercury.
Option D - Zero Discharge Shallow; 1/1 Deep; This option
also makes a distinction between those offshore structures
located in shallow water and those offshore structures
located in deep water. For offshore structures located in
•
shallow water, th^re is a zero discharge requirement which
could be met eif ->r through recycle/reuse of the spent
drilling fluids system or through transport to shore for
treatment and land disposal. For offshore structures
located in deep water, there is the toxicity limitation
based on 30,000 ppm in the suspended particulate phase; a
prohibition on the discharge of diesel oil for lubricity or
spotting purposes (mineral oil substitution); and the
limitation of cadmium and mercury in the barite to be 1
mg/kg of cadmium and 1 mg/kg of mercury.
Option E - Zero Discharge All Structures; The requirements
of this option could be met either through the recycle and
reuse of the spent drilling fluid system or through
transport to shore for treatment and land disposal. This
zero discharge requirement would apply to all offshore
structures regardless of the dept. of water in which they
are located or their distance from shore.
Option F - Zero Discharge Within 4 Miles; 5/3 Beyond: - Zero
discharge is required f- r wells drilled at a distance of 4
miles or less from she . All structures drilled at a
distance greater than 4 miles would require the same
limitations as in Option A.
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Option G - Zero Discharge Within 6 Miles; 5/3 Beyond; -
Sane as Option F except the distance criterion is 6 miles
from shore.
Option H - Zero Discharge Within 8 Miles; 5/3 Beyond; - Same
as Option F except the distance criterion is 8 miles from
shore.
Option I - Zero Discharge Within 4 Miles; 1/1 Beyond; - Same
as Option F except the cadmium and mercury limits are 1
mg/kg each in the drilling wastes discharge for wells
drilled at a distance greater than 4 miles.
Option J - Zero Discharge Within 6 Miles - 1/1 Beyond; -
Same as Option I except the distance criterion is 6 miles
from shore.
Option K - Zero Discharge Within 8 Miles; 1/1 Beyond; - Same
as Option I except the distance criterion is 8 miles from
shore.
Option L - BPT All Structures; BPT effluent limitations
would apply to all facilities.
Option M - Zero Discharge Shallow; BPT Deep; Structures
located in shallow waters would be subject to zero discharge
requirements. Those located in deep waters would be subject
to BPT effluent limitations.
Option N - Zero Discharge Within 4 Miles; BPT Beyond; Those
structures located at or within 4 miles from shore would be
subject to a zero discharge requirement. Those located
outside of 4 miles would be required to meet BPT
limitations.
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BCT for drilling fluids and cuttings is being proposed as
Option N: 1) no discharge of free oil for wells located more
than 4 miles from shore (BPT), and 2) zero discharge for wells
located at or inside of 4 miles. However, for the Alaska region,
all new wells regardless of location would be covered by the same
discharge limitations as structures located outside of 4 miles
because the special climate and safety conditions that exist for
parts of the year make barging (necessary to meet zero discharge)
especially difficult and hazardous.
EPA has selected Option I as a basis for BAT and NSPS
effluent limitations for drilling fluids and drill cuttings.
This option is the same as the BCT selection for drilling
structures located within 4 miles of shore, thus requiring zero
discharge (based on transport (barging) to shore); BAT and NSPS
for structures located outside of 4 miles adds the additional
limitations which allow a discharge after meeting requirements
for toxicity, cadmium and mercury at 1 mg/kg each in the drilling
fluids, and no discharge of diesel oil and free oil. For the
Alaska region the discharge requirements for Option B would
apply, regardless of distance from shore.
There are nine options which have been considered for
regulatory control for the produced water waste stream. Each
option is discussed below:
Option A - Filter Shallow/BPT Deep; This option
differentiates between those offshore structures which are
located in shallow water and those offshore structures which
are located in deep water. The limitations for offshore
structures located in shallow water would be based on the
use of filtration (granular media or membrane separation)
technology as an add-on to the existing BPT technology.
Those offshore structures that are located in deep water
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would be subject only to the BPT limitations that are
currently in place.
Option B - Zero Discharge Shallow/BPT Deep: This option
also makes a distinction between those structures located in
shallow water and those structures located in deep water.
Under this option, the offshore structures located in
•
shallow water would be subject to a zero discharge
requirement based on reinjection of the produced water.
Those offshore structures located in deep water would be
subject to the existing BPT limitations that are currently
in place.
Option C - Filter and Discharge All Structures; Under this
option the limitations for all structures regardless of the
water depth (or distance from shore) in which they are
located would be based on filtration of the produced water
prior to discharge.
Option D ** Zero Discharge Shallow/Filter Deep; This option
would require those offshore structures located in shallow
water to meet a zero discharge requirement for the produced
water waste stream based on reinjection technology. Those
offshore structures located in deep water would be required
to meet limitations based on filtration.
Option E - Zero Discharge All Structures; This option would
require that all structures (regardless of the water depth
or distance from shore in which they are located) meet the
zero discharge requirement based on reinjection of the
produced waters.
Option F - Zero Discharge Within 4 Miles/BPT Beyond; All
wells at a distance or 4 miles or less from shore would be
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required to meet discharge limits based on filtration.
Producing wells at distances greater than 4 miles from shore
, f t
would be required to meet the existing BPT limitations only.
Option G - Zero Discharge Within 6 Miles/BPT Beyond; This
option is the same as Option F except that the distance
criterion is 6 miles instead of 4.
Option H - Zero Discharge Within 8 Miles/BPT Beyond; This
option is the same as Option H except that the distance
criterion is 8 miles instead of 4.
Option I - BPT All; This option would require that all
structures meet BPT effluent limitations.
BCT for produced waters is proposed as being equal to BPT.
For BAT and NSPS, EPA has selected for proposal Option F, based
on filtration for platforms located 4 miles or less from shore
and BPT for platforms beyond 4 miles. The limitations are 7 mg/L
monthly average and 13 mg/L daily maximum based on membrane
separation filtration technology.
BCT for deck drainage, treatment, completion and workover
fluids, and sanitary wastes is being proposed as equal to BPT.
BCT for produced sands is being proposed as no discharge of free
oil. BCT for domestic wastes is being proposed as no discharge
of floating solids.
BAT and NSPS for the miscellaneous waste steams are also
proposed. Zero discharge is proposed for produced sands. Zero
discharge of treatment, completion, and workover fluids is also
proposed when these fluids resurface from the well as a discrete
slug, along with a 100 barrel buffer on either side of the slug.
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If the treatment, completion, and workover fluids are not self.-
contained but diffused in the produced brine, then they will be
controlled along with produced waters. Effluent limitations
equal to those proposed for produced waters are proposed for deck
drainage during production and the BPT limitation of no free oil
is proposed for deck drainage during drilling. BAT is not being
proposed for domestic and sanitary wastes because there have been
no toxic or nonconventional pollutants of concern identified in
these waters; however, NSPS for sanitary wastes is equal to BPT
and NSPS for domestic wastes is equal to current practice (no
floating solids) plus no visible discharge of foam.
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SECTION II
INTRODUCTION
A. PURPOSE AND AUTHORITY
This development document presents a summary of the
technical data base developed by EPA to support the current
proposed effluent limitations guidelines and standards for the
Offshore Subcategory of the Oil and Gas Extraction Point Source
Category. Some of the technologies covered by this document are
used as a basis to propose the limitations and standards and,
thus, are defined as best available control technology
economically achievable (BAT) and/or best conventional pollutant
control technology (BCT) for existing sources, and as a basis for
new source performance standards (NSPS) for new sources.
Pretreatment standards for new and existing sources (PSNS and
PSES) are not being developed for this industry because the
discharges are not directed through POTWs. Best practicable
control technology (BPT) effluent limitations- guidelines for this
industry segment were promulgated on April 13, 1979 (44 FR 22069)
and are not being altered by this rulemaking.
On August 26, 1985 (50 FR 34592) the Agency proposed BAT,
NSPS, and BCT for portions of the various waste streams in this
industry. Subsequently, a Notice of Data Availability was
published in the Federal Register on October 21, 1988 (53 FR
41356). This Notice presented additional information related to
the development of discharge limitations for drilling fluids and
drill cuttings. The current proposal does not supercede the 1985
proposal but, rather, changes it in certain areas based on new
information. Some areas of the 1985 proposal remain the same.
This document describes pertinent pre-1985 proposal data,
outlines new data gathered since 1985, the technology options
considered, waste characteristics, technology performance, costs
II-l
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associated with the various options, and the rationale for
selection of the technology levels on which the proposed effluent
limitations and standards are based.
The Agency is proposing these effluent guidelines and
standards for the Offshore Oil and Gas Extraction Subcategory
under the authority of Sections 301, 304, 306, 307, and 501 of
the Clean Water Act (the Federal Water Pollution Control Act
Amendments of 1972, 33 U.S.C. 1251 et seq., as amended by the .
Clean Water Act of 1977, Pub. L. 95-217 and the Water Quality Act
of 1987, Pub. L. 100-4), also called the""Act." These effluent
guidelines and standards also are being"proposed/reproposed in
response to a settlement agreement entered in 1980 in Natural
Resources Defense Council. Inc. v. Costle. C.A. No. 79-3442
(D.D.C.). This Settlement Agreement was revised in April 1990.
B. LEGAL BACKGROUND
The Federal Water Pollution Control Act Amendments of 1972
established a comprehensive program to "restore and maintain the
chemical, physical, and biological integrity of the Nation's
waters," (Section 101(a))." To implement the Act, EPA was
required to issue effluent limitations guidelines, pretreatment
standards, and new source standards for industrial dischargers.
.hose which are issued to control discharges from direct
dischargers are summarized below. Pretreatment standards for
dischargers into municipal sewer systems (POTWs) are not
described since this industrial subcategory does not have these
types of discharge. In addition to these regulations for
designated industrial categories, EPA was required to promulgate
effluent limitations guidelines and standards applicable to all
discharges of toxic pollutants.
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1. Best Practicable Control Technology Currently Available
fBPTl
BPT effluent limitations guidelines generally are based on
the average of the best existing performance by plants of various
sizes, ages, and unit processes within the category or
subcategory for control of familiar ("e.g., conventional)
pollutants, such as oil and grease, 5-day biochemical oxygen
demand (BODS), total suspended solids (TSS), and pH.
In establishing BPT effluent limitations guidelines, EPA
considers the total cost in relation to the effluent reduction
benefits, age of equipment and facilities involved, processes
employed, process changes required, engineering aspects of the
control technologies, and non-water quality environmental impacts
(including energy requirements). The Agency balances the
category-wide or subcategory-wide cost of applying the technology
against the effluent reduction benefits, which are measured in
pounds of pollutants removed from the discharges.
2. Best Available Technology Economically Achievable (BAT)
BAT effluent limitations guidelines, in general, represent
the best existing performance in the category or subcategory.
The Act establishes BAT as the principal national means of
controlling the direct discharge of toxic and nonconventional
pollutants to waters of the United States.
In establishing BAT, the Agency considers the age of
equipment and facilities involved, processes employed,
engineering aspects of the control technologies, process changes,
cost of achieving such effluent reduction, and non-water quality
environmental impacts.
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3. Best Conventional Pollutant Control Technology YBCT)
The 1977 Amendments to the Clean Water Act added Section
301(b)(2)(E), establishing "best conventional pollutant control
technology" (BCT) for the discharge of conventional pollutants
from existing industrial point sources. Section 304(a)(4)
designated the following as conventional pollutants: BODS, TSS,
fecal coliform, pH, and any additional pollutants defined by the
Administrator as conventional. The Administrator designated oil
and grease a conventional pollutant on July 30, 1979 (44 FR
44501).
BCT is not an additional limitation, but replaced BAT for
the control of conventional pollutants. In addition to other
factors specified in Section 304(b)(4)(B), the Act requires that
the BCT effluent limitations guidelines be assessed in light of a
two-part "cost-reasonableness" test (American Paper Institute v.
EPA. 660 F.2d 954 (4th Cir. 1981)). The first test compares the
cost per pound of conventional pollutants removed for the
industry category or subcategory to reduce its discharge of
conventional pollutants with the similar costs per pound
experienced by POTWs. The second test examines the cost
reasonableness of additional treatment by the industry category
or subcategory beyond BPT for the conventional pollutants present
in the industry's wastewater. EPA must find that limitations are
11 reasonable11 under both tests before establishing them as BCT.
In no case may BCT be less stringent than BPT.
EPA has promulgated a methodology for establishing BCT
effluent limitations guidelines (51 FR 24974, July 8, 1986).
This methodology established the first test benchmark for the
POTW cost per pound of conventional pollutants removed at $0.29
per pound in 1976 dollars. This benchmark when indexed to 1986
II-4
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dollars is $0.46 per pound. For the second test, the methodology
established a ratio of 1.29.
4. New Source Performance Standards fNSPSl
•
NSPS are based on the performance of the best available
demonstrated technology. New plants have the opportunity to
install the best and most efficient production processes and
wastewater treatment technologies. As a result, NSPS should
represent the most stringent numerical values attainable through
the application of best available demonstrated control technology
for all pollutants (i.e., toxic, conventional, and
nonconventional).
5. Best Management Practices (BMPs)
To strengthen the toxics control program, in 1977 Congress
added a new Section 304(e) to the Act, authorizing the
Administrator to prescribe what have been termed "best management
practices" (BMPs) to prevent the release of toxic pollutants from
plant site runoff, spillage or leaks, sludge or waste disposal,
and drainage from raw material storage associated with, or
ancillary to, the manufacturing or treatment process.
C. PRIOR EPA RULEMAKINGS
1. Previous Ruleroakinq for the Offshore Subcateqory
On September 15, 1975, the Agency promulgated effluent
limitations guidelines for interim final BPT (40 FR 42543) and
proposed regulations for BAT and NSPS (40 FR 42572) for the
offshore subcategory. The Agency promulgated final BPT
regulations for the offshore subcategory on April 13, 1979 (44 FR
22069), but deferred action on the BAT and NSPS regulations.
II-5
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Table II-l presents a summary .of the 1979 promulgated final BPT
require ints. EPA published a development document containing
, i
the tfcunnical information used to develop these regulations (EPA
440/1-76/005-a). ^
The Natural Resources Defense Council (NRDC) filed suit on
December 29, 1979 seeking an order for the Agency to promulgate
final NSPS for the offshore subcategory. In a 1980 settlement
agreement, the Agency agreed to take steps to issue NSPS.
However, as a result of the amount of time that had passed since
the 1975 NSPS proposal, the Agency believed that examination of
additional information and a reproposal were necessary. The
Agency withdrew the proposed NSPS on August 22, 1980 (45 FR
56115), and followed with the withdrawal of the proposed BAT on
March 19, 1981 (46 £B 17567).
The Settlement Agreement was revised in April 1990. Under
the modified agreement, EPA was v propose or repropose BAT and
BCT effluent limitations guidelines and new source performance
standards for produced water, drilling fluids and drill cuttings,
well treatment fluids, and produced sand, as described at 50 FR
34595 (August 26, 1985), by November 16, 1990. The November 26,
1990 proposal (which was signed on November 16) was an initial
proposal that was i- sued in satisfaction of this provision of the
Settlement Agreemen.. EPA is to promulgate final guidelines and
standards covering these waste streams by June 19, 1992.
EPA also was to determine by November 16, 1990 whether to
propose effluent limitations guidelines and new source
performance standards covering deck drainage and domestic and
sanitary wastes and, if it determined to do so, to promulgate
final guidelines and standards covering those waste streams by
June 3C, 1993. EPA has determined that it is appropriate to
propos .iffluent limitations guidelines and new source
performance standards covering deck drainage and domestic and
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TABLE II-l
1979 OFFSHORE SUBCATEGORY BPT EFFLUENT LIMITATIONS*
Waste Stream
Parameter
BPT Effluent
Limitation
Produced Water
Drilling Muds
Drilling Fluids
Well Treatment
Deck Drainage
Sanitary-Mi 0
Sanitary-M9IM
•
Oil and Grease
Free Oil*
Free Oil •
Fluids Free Oil
Free Oil
Residual Chlorine
Floating Solids
72 mg/L Daily Maximum
48 mg/L 30-Day Avg.
No Discharge
No Discharge
No Discharge
No Discharge
1 mg/L (min.)
No Discharge
*The free oil "no discharge" limitation is implemented by
requiring no oil sheen to be present upon discharge.
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sanitary wastes. The Agency included such proposals in the
November 26 proposal and they are described in -is document.
The Agency is using its best efforts to comply with the
promulgation dates established in the modified Settlement
Agreement and currently expects to meet them.
Ocean discharge criteria applicable to this industry
subcategory were promulgated on October 3, 1980 (45 FR 65942)
under Section 403(c) of the Act. These guidelines are to be used
in making site-specific assessments of the impacts of discharges.
Section 403 limitations are imposed through Section 402 National
Pollutant Discharge Elimination System (NPDES) permits. Section
403 is intended to prevent unreasonable degradation of the marine
environment and to authorize imposition of effluent limitations,
including a prohibition of discharge, if necessary, to ensure
this goal.
On August 26, 1985 (50 FR 34592), following the gathering of
additional data, the Agency proposed BAT and NSPS for the
drilling fluids, drill cuttings, produced sand, well treatment
fluids, sanitary waste, deck drainage, and produced water waste
streams. In the same notice, BCT for the oil and grease
conventional pollutant parameter in the produced water waste
stream was proposed to be equal to the 1979 final BPT effluent
limitations guidelines. The Agency, however, reserved BCT
effluent limitations guidelines for additional conventional
pollutant parameters (such as total suspended solids) in deck
drainage, drilling fluids, drill cuttings, produced sand, and
well treatment fluids for future rulemakings. A description of
the technical information used to develop these rulemakings can
be found in Development Document for Proposed Effluent
Limitations Guidelines and New Source Performance Standards for
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the Offshore Subcateaory of the Oil and Gas Extraction Point
Source Category. July 1985 (EPA 440/1-85/0556).
Subsequently, a Notice of Data Availability and Request for
Comments was published on October 21, 1988 (53 FR 41356),
concerning the development of NSPS, BAT, and BCT regulations for
the drilling fluids and drill cuttings waste streams (the "1988
•
notice"). The 1988 notice presented substantial additional and
revised technical, cost, economic, and environmental effects
information which the Agency collected after publication of the
1985 proposal. New information was presented regarding the
diesel oil prohibition and the toxicity limitation. New
compliance costing and economic analysis results were presented
based on new profile data and treatment and control option
development. The new control technologies discussed were based
on thermal distillation, thermal oxidation, and solvent
extraction. Performance data for these technologies were also
included. In addition, alternative requirements for limitations
of 5 mg/kg cadmium and 3 mg/kg mercury in the stock barite based
on the use of existing barite supplies, or at 2.5 mg/kg cadmium
and 1.5 mg/kg mercury in the drilling fluids (whole fluid basis)
were noticed for comment.
On January 9, 1989, the Agency published a Correction to
Notice of Data Availability (54 FR 634) concerning the analytical
method for the measurement of oil content and diesel oil. The
1988 notice had inadvertently published an incomplete version of
that method.
As just previously described, on November 26, 1990 the
Agency published an initial proposal and reproposal (55 FR 49094)
that presented the major BCT, BAT, and NSPS regulatory options
under consideration for control of drilling fluids, drill
cuttings, produced water, deck drainage, produced sand, domestic
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and sanitary wastes, and well.treatment, completion, and workover
fluids.
In addition, EPA~"has issued a series of general permits that
set BAT and BCT limitations applicable to sources in the offshore
subcategory on a Best Professional Judgment (BPJ) basis under
402(a)(l) of the Clean Water Act. See e.g, 51 FR 24897 (July 9,
1988) (Gulf of Mexico General Permit); 49 FR 23734 (June 7,
1984), modified 52 FR 30481 (September 29, 1987) (Bering and
Beaufort Seas General Permit); 50 FR 23570 (June 4, 1985) (Norton
Sound General Permit); 51 FR 35400 (October 3, 1986) (Cook
Inlet/Gulf of Alaska General Permit); 53 FR 37840 (September 20,
1988), modified 54 FR 39574 (September 27, 1989) (Beaufort Sea
II/Chuki Sea General Permit.)
The Gulf of Mexico General Permit was challenged by industry
and an environmental group. Natural Resources Defense Coxincil
EPA. 863 F.2d 1420 (9th Cir. 1988). The Bering and Beaufort '
General Permit was the subject of industry challenge. America
Petroleum Institute v. EPA. 787 F.2d 965 (5th Cir. 1986); later
opinion following partial remand, 858 F.2d 261 (5th Cir. 1988);
clarified and rehearing denied, 864 F.2d 1156 (5th Cir. 1989).
Table II-2 presents a summary of the offshore oil and gas
subcategory Federal Register notices.
2. Summary of the 1985 Proposal bv Level of Control and
Waste Stream
The key provisions of the August 26, 1985 proposal were as
follows:
a) BAT
The proposed BAT effluent limitations guidelines would:
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TABLE II-2
SUMMARY OF OFFSHORE OIL AND GAS SUBCATEGORY
FEDERAL REGISTER NOTICES
Level of Control
Action
Date
BPT
BAT/NSPS
BPT/BAT/NSPS
NSPS
BAT
BAT/BCT/NSPS
BAT/BCT/NSPS
BAT/BCT/NSPS
BAT/BCT/NSPS
Interim Final
Proposal
Final (BPT)
Reserved (BAT/NSPS)
Withdraw Proposal
Withdraw Proposal
Proposal
Notice of Data
Availability
(Drilling Muds
& Cuttings)
Correction Notice to
Notice of Data
Availability
Proposal
Sept. 15, 1975
(40 FB 42543)
Sept. 15, 1975
(40 IE 42572)
April 14, 1979
(44 FR 22069)
Aug. 22, 1980
(45 FR 56115)
March 19, 1981
(46 FR 17567)
August 26, 1985
(50 FR 34592)
Oct. 21, 1988
(53 ZB 34592)
Jan. 9, 1989
(54 FR 634)
Nov. 26, 1990
(55 FR. 49094)
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Prohibit the discharge c .?e oil in drilling
fluids., deck drainage, d cuttings, produced
sand, and well treatment ,.ds using a static
sheen test instead of thi .sible sheen method
used for compliance with bPT;
Prohibit the discharge of diesel oil in detectable
amounts in drill cuttings and drilling fluids;
•
Limit the acute toxicity of drilling fluid
discharges to a minimum 96-hour LC50 of 3% (30,000
ppm) as measured in the diluted suspended
particulate phase (SPP); and
- Limit the discharge of cadmium and mercury in
drilling fluids to a maximum of 1 mg/kg each
(whole fluid basis).
Alternative requirements were noticed for comment in the
October 21, 1988 Federal Register with limitations of 5 and 3
mg/kg of cadmium and mercury, respectively in drilling fluids
based on the use of "clean'1 barite, and the possibility of
limitations of 2.5 and 1.5 mg/kg of cadmium and mercury,
respectively, in drilling fluids.
BAT effluent limitations guidelines for pollutants other
than free oil for the deck drainage, produced sand, and well
treatment fluids waste streams were reserved for future
rulemaking. Table II-3 presents the previously proposed BAT
effluent limitations guidelines for each waste stream.
b) NSPS
The proposed NSPS effluent limitations guidelines were the
same as those proposed for BAT/BCT effluent limitations
guidelines with one exception. EPA proposed a prohibition on the
discharge of produced water from all offshore oil production
structures that were located in, or would discharge to, shallow
water areas which were defined in the 1985 proposal. (See
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section IV for an explanation .of shallow and deep water
definitions.) Produced water from all other new source offshore
. i
structures engaged in exploration, development, and production
activities were proposed to be limited to a maximum oil and
grease concentration of 59 mg/L (no single sample to exceed).
This limitation was based on the best operation of the BPT
control technology (gas flotation) and was calculated using
performance data from eight of the facilities in the BPT data
base. Table II-4 presents the previously proposed NSPS effluent
limitations guidelines for those structures located in shallow
water, along with the description of "shallow water" for the
purposes of these limitations, and Table II-5 presents the
previously proposed NSPS effluent limitations guidelines for
those structures located in deep water.
c) BCT
The proposed BCT effluent limitations guidelines covered
only the conventional pollutant oil and grease and were equal to
the previously promulgated BPT effluent limitations guidelines.
The Agency, however, reserved BCT effluent limitations guidelines
for additional conventional pollutant parameters, in particular
total suspended solids (TSS) in deck drainage, drilling fluids,
drill cuttings, produced sand, and well treatment fluids, for
future rulemakings. Table II-6 presents the previously proposed
BCT effluent limitations for each waste stream.
11-13
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TABLE II-3
PREVIOUSLY PROPOSED BAT EFFLUENT LIMITATIONS
Waste Source
Produced Water
Deck Drainage
Drilling Fluids
Drill Cuttings
Sanitary M10
Sanitary M9IM
Domestic Waste
Produced Sand
Pollutant Parameter
[Reserved]
Free Oil
All Other Parameters
Free Oil
Oil Based Fluid
Diesel Oil
Toxicity
Cadmium
Mercury
Free Oil
Oil Based Fluid
Dies Oil
None
None
None
Free Oil
All Other Parameters
Free Oil
BAT Efflunt
Limitations
[Reserved]
No Discharge
[Reserved]
No Discharge
No Discharge
No Discharge in
Detectable Amounts
Minimum 96 Hour
LC50 of the SPP
shall be 3 percent
by volume
1 mg/kg dry weight
maximum in the whole
drilling fluid*
1 mg/kg dry weight
maximum in the whole
drilling fluid*
No Discharge
No Discharge
No Discharge in
Detectable Amounts
None
None
None
No Discharge
[Reserved]
No Discharge
Well Treatment
Fluids
-"Other options being considered are for limiting mercury and cadmium either at
1.5 and 2.5 mg/kg, respectively, in the whole drilling fluid or 3 and 5
mg/kg, respectively, in the stock barite prior to mixing into the drilling
fluid system.
11-14
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TABLE II-A
PREVIOUSLY PROPOSED NSPS EFFLUENT LIMITATIONS (Shallow Water)*
Waste Source
Pollutant Parameter
NSPS Effluent Limitations
Produced Water
Deck Drainage
Drilling Fluids
Drill Cuttings
Sanitary M10
Sanitary M9IM
Domestic Waste
Produced Sand
Well Treatment
Fluids
Free
All Other Parameters
Free Oil
Oil Based Fluid
Diesel Oil
Toxicity
Cadmium
Mercury
Free Oil
Oil Based Fluid
Diesel Oil
Residual Chlorine
Floating Solids
Floating Solids
Free Oil
All Other Parameters
Free Oil
All Other Parameters
*
Rsoton
Gulf of Mexico:
Aflanbc
Csfltomla:
SnHow Water Doplm
LsttTYvnaMstsn
IMS Than 20 MUMS
Lass Titan SO Mstsn
Lsss Ttan SO Msten (Soutfwn)
IMS Than 20 Mtten (Norton Sound]
Lso Than 10 Mstws (BcauM Sea)
No Discharge**
No Discharge
[Reserved]
No Discharge
No. Discharge
No Discharge in Detectable Amounts
Minimum 96 Hour LCX of the SPP
shall be 3 percent by volume
1
/kg dry weight maximum in the
whole drilling fluid***
1 mg/kg dry weight maximum in the
whole drilling fluid***
No Discharge
No Discharge
No Discharge in Detectable Amounts
Minimum of 1 mg/L and maintained as
to this concentration as possible
No Discharge
No Discharge
No Discharge
[Reserved]
No Discharge
[Reserved]
**Structures must be in compliance with the no discharge standard no later
than 300 days after commencement of development drilling operations. Prior
to that date, discharges shall comply with the oil and grease standard of 59
mg/1 maximum.
***0ther options being considered are for limiting mercury and cadmium either
at 1.5 and 2.5 mg/kg, respectively, in the whole drilling fluid or 3 and 5
mg/kg, respectively, in the stock barite prior to mixing into the drilling
fluid system.
11-15
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TABLE II-5
PREVIOUSLY PROPOSED NSPS EFFLUENT LIMITATIONS (Deep Water)
Waste Source
Pollutant Parameter
NSPS Effluent Limitations
Produced Water
Deck Drainage
Drilling Fluids
Drill Cuttings
Sanitary M10
Sanitary M9IM
Domestic Waste
Produced Sand
Well Treatment
Fluids
Oil and Grease
Free Oil
All Other Parameters
Free Oil
Oil Based Fluid
Diesel Oil
Toxicity
Cadmium
Mercury
Free Oil
Oil Based Fluid
Diesel Oil
Residual Chlorine
Floating Solids
Floating Solids
Free Oil
All Other Parameters
Free Oil
All Other Parameters
59 mg/L Maximum
Mo Discharge
[Reserved]
No Discharge
No Discharge
No Discharge in Detectable Amounts
Minimum 96 Hour LC,0 of the SPP
shall be 3 percent by volume
1 mg/kg dry weight maximum in the
whole drilling fluid*
1 mg/kg dry weight maximum in the
whole drilling fluid*
No Discharge
No Discharge
No Discharge in Detectable Amounts
Minimum of 1 mg/L and maintained as
to this concentration as possible
No Discharge
No Discharge
No Discharge
[Reserved]
No Discharge
[Reserved]
*0ther options being considered are for limiting mercury and cadmium either at
1.5 and 2.5 tag/kg* respectively, in the whole drilling fluid or 3 and 5
mg/kg> respectively, in the stock barite prior to mixing into the drilling
fluid system
11-16
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TABLE II-6
PREVIOUSLY PROPOSED BCT EFFLUENT LIMITATIONS
Waste Source
Pollutant Parameter
BCT Effluent Limitations
Daily Maximum 30 Day Avg.
Produced Water
Deck Drainage
Oil and Grease
Free Oil
All Other Parameters
Drilling Fluids Free Oil
All Other Parameters
Sanitary M10 Residual Chlorine*
Sanitary M9IM
Domestic Waste
Produced Sand
Well Treatment
Fluids
Floating Solids
Floating Solids
Free Oil
All Other Parameters
Free Oil
All Other Parameters
72. mg/L 48 mg/L
No Discharge
[Reserved] [Reserved]
No Discharge
[Reserved] [Reserved]
Minimum of 1 mg/L
and maintained as
close to this
cone, as possible
No Discharge
No Discharge
No Discharge
[Reserved] [Reserved]
No Discharge
[Reserved] [Reserved]
*For the control of fecal coliform
11-17
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3 . The 1988 Notice of Data Availability
In October, 1988 r^the Agency published a Notice of Data
Availability (53 FR 41356) which presented new technical,
economic and environmental information relating to the
development of BAT and NSPS effluent guidelines limitations for
the drilling fluid and drill cuttings waste streams. This new
information was submitted in part by industry and generated in
part by the Agency in the response to comments on the 1985
proposal. The notice was organized in two parts. Part 1 of the
notice discussed key issues of the drilling fluids toxicity
limitation, the proposed toxicity test method, the prohibition on
the discharge of drilling fluids containing diesel oil additives,
a re-evaluation of industry compliance costs, an economic
assessment of the revised cost estimates and environmental
impacts of the discharge of cadmium and mercury in drilling fluid
waste streams. It also presented two variations on the August
1985 proposed regulatory approach related to the mercury and
cadmium limitations in drilling fluids and the barite component
of drilling fluids (see notes on Tables II-3, 4, and 5).
Part 2 of the notice discussed information gathered on new
treatment technologies for controlling the oil content of
drilling wastes. Data on the performance and cost of thermal
distillation/oxidation and solvent extraction technologies for
treating drilling fluids and drill cuttings were presented for
public review and comment. This information was being considered
for the development of an oil content limitation on drilling
waste streams.
Section VI of this document describes these post-1985 data.
11-18
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D. SUMMARY OF METHODOLOGY
The steps implemented to develop a technology-based effluent
limitation guideline are as follows:
Data gathering
Industry profile and subcategorization
Wastewater characterization
Pollutant selection
Evaluation of wastewater treatment alternatives
Analysis of the costs of treatment
Analysis of the non-water-quality aspects of the
treatment alternatives
The data gathered for the development of the 1985 proposed
limitations is described in the 1985 development document (EPA
440/1-85/0056) and summarized in Section V of this document. .
As already discussed, new technical, economic, and
environmental assessment information relating to the development
of BAT and NSPS regulations concerning the discharge of drilling
fluids and drill cuttings has been obtained since 1985. In
addition, other information related to the toxicity test method
variability and the performance of filtration control technology
in treating produced water has been acquired. This new
information has led the Agency to develop new or additional
regulatory options to those proposed in 1985. All new
information developed by EPA since 1985 is discussed in Section
VI of this development document.
11-19
-------
The profile of the industry has been updated and changes to
the subcatego.- ization schemes have been made. These are
described in Sections III and IV, respectively.
Waste stream sources and characteristics are defined in
Section VII.
Based on this new information and extensive analyses
efforts, the Agency is examining different regulatory levels for
certain pollutants and considering additional regulatory options
based on the location (deep or shallow water, or distance from
shore) of the oil and gas structure. This is discussed further
in Sections VIII through XI.
The Agency also estimated capital and annual costs
associated with each control and treatment alternative. In
general, unit process costs were derived by using data on
production and waste characteristics for model facilities to
develop unit process costs for various control and treatment
steps. These unit process costs then were combined to yield a
total cost for various treatment levels based on the estimated
number of facilities. The results of the cost analysis and the
assumptions used are discussed in Sections XII through XIII.
Based on the cost figures, the Agency then was able to
perform a detailed economic impact analysis. This analysis
determines th... impacts of compliance for each regulatory option
considered. Considerations in the economic analysis include
price increases, profitability, industrial growth, facility
closures, production changes, employment effects, consolidation
trends, and balance of trade effects. Sensitivit" and cost-
effectiveness analyses also are included in the economics report.
The economic analysis is discussed in detail in a separate
report.
11-20
-------
Energy and non-water quality environmental impacts resulting
from treatment technologies necessary to meet the proposed
regulatory options have been estimated also; results of this
*
evaluation are included in Section XIV.
EPA's preferred regulatory options and their representative
effluent limitations are presented in Sections XV through XVI.
11-21
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SECTION III
INDUSTRY PROFILE
A. INTRODUCTION
The purpose of the industry profile section is to describe
the offshore oil and gas segment of the oil and gas extraction
industry according to its production processes, size, location,
permit status, and future potential. The profile is organized
according to the processes associated with each phase of the
industry—exploration, development, and production. This
information is essential for regulatory development in order to
define the industry's wastewater pollution character and
potential, and to perform economic analysis on the necessary
pollution reduction regulations.
The offshore subcategory (as defined at CFR 435.10) of the
oil and gas extraction point source category covers those
structures involved in exploration, development, and production
operations seaward of the inner boundary of the territorial seas.
This document covers offshore activities included in the Standard
Industrial Classifications (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.
Structures are considered to be classified as offshore if
they are located in waters that are seaward of the inner boundary
of the territorial seas. The inner boundary of the territorial
seas is defined in Section 502(8) of the Clean Water Act 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. . ."
III-l
-------
In some areas the inner boundary of the territorial seas is -
clearly established and is shown on naps. For example, the Texas
General Land Office (Survey Division) has available 7.5 minute
quadrangle maps for tRe entire coastline of Texas which clearly
show the inner boundary of the territorial seas. Additionally,
the Louisiana State Minerals Board (Civil and Engineering
Division) has available maps for the Louisiana coastline showing
the inner boundary of the territorial seas. In other areas, such
as Alaska, the baseline (or inner boundary) is not clearly
established. As part of the permitting process for discharges in
the territorial seas, the waters of the contiguous zone, and the
oceans, Section 403(c) of the Clean Water Act sets out criteria
requiring a determination of whether or not the discharge will
cause degradation of these waters. In 403(c) determinations
where it is questionable whether the discharge is beyond the
baseline or not, the State Department is consulted to make site-
specific determinations. In relation to the implementation of
the BPT limitations guidelines or general permit requirements,
there have been no problems associated with the definition of t:.*
inner boundary of the territorial seas.
Offshore development occurs in areas which are offered for
development by federal or state governments on a leased basis.
These areas are known as tracts. The standard offshore leased
tract is 5,760 acres or 9 square miles.1 Once an area is leased
by a company or group of companies, exploration wells are drilled
to determine whether hydrocarbons are present. If oil or gas is
found in sufficient quantities, development wells and production
facilities (platforms or structures) are put in place. From
these facilities, oil and gas are produced and conveyed to
markets by pipeline or tanker. Each of these phases
(e-rploration, development, production) is described below.
III-2
-------
B. EXPLORATION
The exploration process consists of those operations
involving the drilling^pf wells to discover the potential for
hydrocarbon reservoirs. Geological surveys are conducted to map
the surface of the earth and to determine the subsurface
structure. Measurements made by geophysical methods, such as
seismic, gravimetric, and magnetic, give indications of the depth
and nature of subsurface rock formations. These surveys can
suggest underground conditions favorable to accumulation of oil
and gas deposits, but they must be followed by exploratory
drilling to prove the actual existence of hydrocarbon deposits.
Although the majority of wells drilled by the petroleum
industry are to obtain access to reservoirs of oil or gas, a
significant number are drilled to gain knowledge of geologic
formations. This latter class of wells may be shallow, and
drilled in the initial exploratory phase of operations, or may be
deep exploration, seeking to discover the extent of oil or gas
bearing reservoirs. Exploratory drilling, whether shallow or
deep, generally uses the same rotary drilling methods as
development drilling. Exploration activities are usually of
short duration at a given site, involve a small number of wells,
and are generally conducted from mobile drilling units. EPA,
prior to the 1988 Notice of Availability, estimated the level of
drilling that has occurred in each offshore region up to 1986.1
An estimated 7,468 exploratory wells had been drilled as of that
time. Of these, 5,206 were drilled in federal waters. Of all
wells, oil was found in 376 cases (5.0%), gas was found in 641
cases (8.6%), and 6,451 (86.4%) were dry holes. Historically,
30% of exploratory drilling occurred in state waters and 70% in
federal waters.
III-3
-------
The most significant waste streams in terms of volume and
constituents, that are associate with exploration activities,
are the drilling fluids and dril juttings generated during the
drilling phase. Theses-are discussed in Section VII.
C. DEVELOPMENT (WELL DRILLING)
Development (or well drilling) activities involve the
drilling of prciuction wells once a hydrocarbon reserve has been
identified. This is the process of actually cutting through the
earth's crust to form a well and is accomplished by drill bit
rotation and hoisting operations. Basically, methods consist of
machinery to turn a drill bit, to add sections on the drill pipe
as the hole deepens, and to remove the pipe and bit from the
hole, and a system for circulating a fluid down through the drill
pipe and back up to the surface.
Drilling fluid removes the particles cut by the bit, cools
and lubricates the bit as it cuts, and, as the well deepens,
equalizes pressures that may be encountered in passage through
the various formations. The fluid also stabilizes the walls of
the well bore.
The drilling fluid system consists of tanks to formulate,
store, and treat the fluids; pumps to force them down the drill
pipe and back to the surface; and machinery to remove cuttings,
fines, and gas from fluids returning to the surface (see Figure
III-l). A system of valves controls the flow of drilling fluids
from the well when high pressures cannot be controlled by weight
of the fluid column. A blowout occurs when drilling fluids are
ejected from the well by subsurface pressures and the well flows
uncontrolled. A control valve system is located at the well head
and is call? i a blowout preventer (see Figure III-2).
III-4
-------
A KELLY
B STANDPIPE AND ROTARY HOSE
CSHALESHAKER
D OUTLET FOR DRILLING FLUID
E SUCTION TANK
FPUMP
—- FLOW OF DRILLING FLUID
Source: 2
FIGURE III-l. TYPICAL ROTARY DRILLING RIG
III-5
-------
( «-•» «L^J
} {, . 1
v »1 ;
jC 3T — I
f
i
r
/La
fc?=
i n ^ ^r"
^cr";
c= *> j •
vxxV^ 177-
4 ^
J 1
/ i
CASING^
X '
DRILL PIPE \
\
y^
*t"
i
DRILL BIT ^
JC
1
• f
1-^ A
i r^
f •_!
n ' , ?•
!?c! 1^
%
TJ ^^
^»~r »~ ^\mi n
Jj \>
' ^"-•^ G ' v f^^^r^ C
^L^T • — u. r^%^.
— T- ^ " | ^^^^^^
'""l i * 'I
' L- :
» b> i 11 .
' 1 ' (r/ '
-- i I/.
- _ > Y/
Tf Y-
[*\1 ,.,,,, ..."
*. fs//S/S///////',
IrjZ AKELLY
A V, C SHALESHAKER
'/. D OUTLET FOR DRILLING FLUID
K G HYDRAUUCALLY OPERATED BLOWOUT PREVENTER
r; H OUTLETS, PROVIDED WITH VALVES
6 AND CHOKES FOR DRILLING FLUID
J& ^ FLOW OF DRILLING FLUID
f *~~
i&
^1^"'
I • Source: 2
L
FIGURE III-2. TYPICAL WELL SHOWING SHALESHAKER
AND BLOWOUT PREVENTER
III-6
-------
For offshore operations, drilling rigs may be mobile or .
stationary and, contrary to exploration, usually involve a large
number of wells. Mobile rigs are used for both exploratory and
development drilling, "vhereas stationary rigs are mostly used for
development drilling in a proven field. Stationary rigs may also
be used for exploratory drilling at locations such as man-made
gravel islands constructed in near-shore waters of the Alaskan
•
Arctic where ice forces preclude the use of most mobile drilling
rigs.
Some mobile rigs, called submersibles, are mounted on
barges, towed to the drill site, and sunk on the bottom for
drilling in shallow waters. Jack-up rigs, also towed on barges,
are raised up above the sea level on extendable legs for drilling
in water up to 300 feet in depth.
Semisubmersible rigs on floating structures with submerged
ballast chambers that support rigs well above the water are used
for deeper operations. These units are anchored in place to
provide a relatively stable base even in severe sea and weather
conditions. Drill ships with normal hull shapes are self-
propelled vessels with sophisticated mooring equipment to
maintain a steady position over the bottom while drilling.
Although drill ships are very •mobile, they cannot operate in very
rough weather.
The major source of pollution generated by the drilling
operation is the drilling fluid or "mud" and the cuttings from
the bit. In early wells drilled by the rotary method, water was
used as the drilling fluid. The water mixed with the naturally
occurring soils and clays which made up the mud. The different
characteristics and superior performance of some of these natural
muds were evident to drillers, which led to development of
specially formulated muds. The composition of modern drilling
III-7
-------
muds is quite complex and can vary widely not only from one
geographical arc- •• to another, but also in different portions of
the same well.
The drilling of a well from top to bottom is not a
continuous process. A well is drilled in sections, and as each
section is completed it is lined with a section of pipe or casing
(see Figure III-2). The different sections may require different
types of mud. The mud from the previous section must either be
disposed of or converted for the next section.
As the drilling mud is circulated down the drill pipe, out
of the bit, and back up an annulus between the bore hole and the
drill pipe, it brings with it the material cut and loosened by
the bit (cuttings) plus fluids which may enter the hole from the
formation (water, oil, or gas). When the mud arrives at the
surface, cuttings, silt, and sand are removed by shaleshakers,
desilters, and desanders. Oil or gas from the formation is also
removed and the processed mud is cycled through the drilling
system again, with offshore wells, the cuttings, silt, and sand
are discharged overboard if they do not contain free oil. Some
drilling mud clings to the sand and cuttings, and when this
material reaches the water, the heavier particles (cuttings and
sand) sink to the bottom while the mud and fines are swept down-
current away from the platform (see Figure III-3).
The removal of fines and cuttings is one of a number of
steps in the continuing process of mud treatment and
conditioning. This processing may be performed to keep the mud
characteristics constant or to change them as required by the
drilling conditions. Some constituents of the drilling mud can
be salvaged when the drilling is completed. Salvage facilities
may exist at the rig or at another location such as the
III-8
-------
^£?=^s
v-^M U 0 M 0 8 E^
CUTTINGS
REMOVAL
SYSTEM
MUD DISCHARGE PIPE
• LOWOUT
PREVENTER
SEA SURFACED
• . -bCEAN PLOpR .'/• ••.'.*•* . • .
''' '' ' '
• r
r
\JD
DRILLCOLL-AR.
BOREHOLE*.
•rr
Sources 3
FIGURE III-3. DISCHARGES FROM DRILLING OPERATION
III-9
-------
industrial facility that supplies drilling fluids or their
components. Where drilling is more or less continuous, such as
on a multiple-well offshore platform, the disposal of mud should
not be a frequent occurrence since the mud can be conditioned and
recycled from one well to another.
Most drilling fluid systems still are water based although
oil-based systems are available. Oil-based fluids are used for a
variety of applications such as high temperature wells, deep
holes, and wells where sticking and hole stabilization is a
problem.4 In addition, water-based drilling fluids may have
diesel oil or mineral oil added to them. Drilling fluids also
may contain entrained formation hydrocarbons.
Oil can be used to improve the lubricating properties of a
water-based mud system and as an aid in freeing drill pipe that
has become stuck downhole during the drilling operation.
Although diesel oil often is the most readily available oil at a
drilling site mineral oils have had a great deal of use recently
for these purposes. When oil 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. After use, the pill may be
removed from tha bulk mud system and disposed of separately.
Even if the pill is recovered, residual oil from the pill can mix
with the remainder of the mud system.
The principal concern with effluent discharges from
development operations are the hydrocarbons in the muds and also,
as a result, in the cuttings. Oil-based muds and water-based
muds that have oil added to them are considered to be toxic to
the environment.
111-10
-------
Approximately 98% of all exploratory and development wells
are contracted out to independent drilling contractors. Only
about 1% of all drilling rigs are owned by operating companies.
The annual level of activity of drilling contractors is shown in
Table III-l.
D. WELL TREATMENT
Included in the production phase is a process known as well
treatment or stimulation treatment, the purpose of which is to
restore or improve the recovery from a reservoir. Well
stimulation treatments include fracturing, acidizing, and other
chemical treatments.5 Waste streams are also produced as a
result of these operations.
When the producing zone of a well has such a low
permeability that hydrocarbons cannot readily flow into the well,
stimulation may be necessary. Stimulation increases the
permeability of the oil-bearing stratum to increase the
production rate of crude oil. "Well stimulation" encompasses
three basic methods: explosives, hydraulic fracturing, and acid
treatment (also called etching). Choice of method for well
stimulation depends on the characteristics of the bearing
formation with respect to the type of rock, characteristics of
the crude, the relative amounts of water and natural gas, and
other geological factors.
Use of explosives to stimulate well flow began in the 1800s;
however, development of hydraulic fracturing and acid treatment
in the 1940s practically eliminated the use of explosive
stimulation. Recently, it has been found that some formations do
not respond well to the fracture and acid technologies and that
many older, explosively stimulated wells are still in commercial
production after the fractured and acidized wells have been shut
III-ll
-------
TABLE III-l
OFFSHORE DRILLING ACTIVITY
YEAR
1973
1974
1975
1976
1977
1978
1979
1980.
1981
1982
1983
1984
1985
1986
NUMBER
OF WELLS
DRILLED
888
830
1,028
1,028
1,217
1,197
1,260
1,272
1,476
1,464
1,270
1,421
1,247
898
FOOTAGE
DRILLED8
8,354,069
7,402,256
9,783,176
9,817,244
11,519,851
11,756,744
12,392,501
.,2,503,275
14,422,470
14,52 ,052
12,831,906
14,259,153
12,815,948
9,40^,734
AVERAGE
DEPTH
PER WELL
(FT.)
9,408
8,918
9,517
9,550
9,466
9,821
9,835
9,829
9,771
9,930
10,104
10,035
10,277
10,476
alncludes exploration, delineation, and development
drilling.
Source: 1
111-12
-------
down. These findings, coupled with improved, safer explosives
and application techniques, have renewed interest in stimulation
of wells by explosives.6
There are two basic methods of using explosives in well
stimulation. The first method is to detonate at the producing
zone level in the bore hole, thereby effectively increasing the
well hole size. The second method involves injection of the
explosive into fissures and voids away from the bore hole,
thereby increasing the areas of influence of the explosive
fracture. In either case, the resultant broken rock prevents the
fractures from closing.
Hydraulic fracturing is achieved by pumping fluids at high
pressure, frequently exceeding 10,000 psi, into the bore hole,
literally splitting the rock. Proper fracturing accomplishes the
following:
It creates reservoir fractures, thereby improving the
flow of oil to the well
It improves the ultimate oil recovery by extending the
flow paths
It aids in the enhanced oil recovery operation
Since, over a period of time, the fractures tend to close
up, it is necessary to introduce materials into the fissures to
keep them open. Typical materials used include sand, ground
walnut shells, aluminum spheres, glass beads, and similar inert
particles. These materials, known as "propping agents," are
carried into the fractures by the fracturing fluid.
Acid stimulation of a well is achieved by pumping an acid
solution down the well and forcing the solution into the
producing formation. The primary purpose of acid treatment is to
111-13
-------
dissolve the rock, thereby enlarging the openings allowing
increased oil flow. The formations most often acidized are
composed of sandstone, limestone, or dolomite.
The acid medium employed must have some specific
characteristics such as:
The reaction products must be water soluble
The acid must be safe to handle
Since large volumes are used, it must be fairly
inexpensive.
One type of acid treatment also results in the fracture of
the stratum, with the acid acting as both the .fracturing and
dissolving medium. Another type of acidizing, known as "matrix
acidizing," consists of pumping the acid at a pressure low enough
to avoid fracturing the formation. Matrix acidizing is used
extensively in offshore operations in the Gulf of Mexico.
Specialized chemicals have been developed for well
stimulation. For example, fracture fluids must have viscosity
properties to permit proper placement of the proppant. Acid
treatment fluids must be inhibited to minimize acid attack on the
well casing and piping. Also, solvents, surfactants,
sequestering agents, gelling agents, and suspending agents may be
required. The choice of material is determined by field
conditions. Typical chemicals used in well stimulation are
polymers, acid salts, acetic acid, and acid/oil emulsions.
The potential for release to the environment of the well
stimulating chemicals is, by nature of the procedure, very
limited. Most of the materials, in the case of acidizing, react
with the rock and are destroyed. Those that are not destroyed
111-14
-------
either remain in the formation or are flushed out and diluted
with the produced fluids.
E. COMPLETION/WORKOVER
After drilling is finished, well logging data are evaluated
to determine the productivity of the well. If the well is not
capable of producing commercial quantities of oil or gas (dry
hole), the well is plugged. If commercial quantities of oil or
gas are found, then the well is "completed."
The term "completion" refers to the physical process of
installing downhole equipment to allow production of oil or gas
from the hydrocarbon formation.7 Completion of a well involves
setting and cementing the casing, perforating the casing and
surrounding cement to provide a passage for oil and gas from the
formation into the well bore, installing production tubing and
packers, and gravel-packing the well. The methods of completion
of a well are governed by the nature of the reservoir. Various
methods of completion are illustrated in Figure III-4. Sometimes
a well penetrates more than one producing stratum requiring an
additional completion method illustrated in Figure III-5. The
function of completion fluids is to seal off or temporarily plug
the face of the producing formation in the bore hole so that,
during completion operations, fluids and solids are not lost into
the producing formation, thereby reducing its productivity.
Ideally, sealing is accomplished by depositing a thin film
of solids over the surface of the producing formation without
forcing solids into the formation. The solids which are
deposited on the formation surface are called "bridging agents"
and temporarily close the formation pores. Various types of oil-
soluble or acid-soluble bridging agents are available. The
bridging agent is dissolved (by oil, acid, or brine) when the
111-15
-------
IUI SUO FMUTIII
-mm
III
•It !
— —«Ml-Mt«-«i»ttt !!••=- ~
fit HUE SIM FMMTIH
IIMI tlHHIII
MM Niriuii*
(c) ni FIIE uiii
^ UISE SUM
(D) m INK rm ui CIIISE UHI sins
Source: €
FIGURE III-4. TYPICAL COMPLETION METHODS
111-16
-------
PRODUCTION TUBING
SURFACE CASING
CEMENT
PRODUCTION CASING
TRIPLE PACKER
PRODUCING ZONE NO. 1
DOUBLE PACKER
PRODUCING ZONE NO. 2
SINGLE PACKER
PRODUCING ZONE NO. 3
Source: 6
FIGURE III-5. MULTIPLE WELL COMPLETION
111-17
-------
completion operation is finished so that oil or gas may be
produced.
It is important that maximum permeability of the producing
formation be retained. A non-damaging completion fluid is one
that causes a minimum of permanent plugging of the formation
pores. Composition of completion fluids varies greatly and is
site specific depending on the nature of the producing
formations.
The production zone is a porous rock formation containing
the hydrocarbons, either oil or gas, and can be damaged by mud
solids and water contained in drilling fluids. To avoid this,
and to maximize production rate, a special low-solids completion
fluid may be used to drill through the production zone.
In order to isolate the various formations penetrated
during drilling operations, it is necessary to install casing in
the bore hole. Casing usually is installed in stages as the
drilling progresses, each stage being a successively smaller
diameter. The cae_ ig strings are cemented in place after each
installation.
The first string of casing and the largest diameter is
called the surface string and may vary in length from about 60
meters (200 feet) to about 450 meters (1,500 feet) depending on
local conditions. After placing and cementing the surface
string, drilling is resumed with a smaller drill bit than the
original.
The second string of casing, called the intermediate or
"salt" string, is run generally to a depth sufficient to seal off
the salt and anhydride formations, and may reach a depth of 1,500
meters (5,000 feet) or more. After cementing in, drilling is
111-18
-------
resumed. The final string of .casing, the production casing or
oil string, usually extends through the surface and salt strings
to the producing zone(s). Various devices are attached to the
outside of the casing"to keep it centered in the bore hole and to
remove caked drilling mud from the hole walls.
Another string of pipe placed in the well is called the
tubing and is through which the production oil flows. This
tubing size is much smaller than the casing (typically 1.5 inch
to 4.5 inch diameter). The tubing is suspended from the well
head and reaches to the producing zone or almost the bottom of
the well. Where multiple producing zones are penetrated,
separate tubes, isolated by packers, may be installed for each
zone in the same casing (see Figure III-5).
The cementing operation normally is performed by a cementing
service company with the assistance of the drilling crew. Cement
slurry is mixed on site and is pumped, through a special valve at
the well head, through the casing to the bottom and up the
annular space between the bore hole wall and the outside of the
casing to the surface. A top plug is pushed through the casing
and annular space by the cement which, in turn, is moved out of
the casing with a displacement fluid. The cement is allowed to
harden and drilling is resumed.
Most wells are cemented with an ordinary Portland cement
slurry. The amount of cement per well will depend on well depth
and the volume of the annular space to be filled. Additives may
be used to compensate for temperature and salt water conditions
specific to the site. Loss of cement to the environment during
this operation is relatively small.
Packers are installed to seal the annular space between the
casing and the production tubing and prevent formation fluids
111-19
-------
from reaching the surface by way of the tubing/casing annulus.
Packer fluids are typically mixtures of a polymer viscosifier, a
corrosion inhibitor, and a high concentration salt solution.
This mixture remains between the well casing and the flow tubing,
just above the production zone (hydrocarbon reservoir) during
well completion and production.8 These fluids are returned to
the surface during well workover.
•
Sometimes a well, once considered nonproductive, is
unplugged and completed if economic shifts in the industry change
the profitability of the oil or gas yield. The "reopening" of a
well is known as a "workover." The term also applies to remedial
work on a producing well to increase productivity. Workover
fluids are used to allow safe maintenance and repair procedures
so that recovery of hydrocarbons from the producing reservoir can
be accomplished. Workover.operations can also include "killing
operations."
During workover operations, a well may require "killing" to
control formation pressure. This occurs when a column of
drilling mud, oil, water, or other liquid of sufficient weight is
introduced into the well to control the down hole pressures.
When the work is completed, the liquid used to kill the well must
be removed so that the well will flow again. If mud is used, the
initial flow of oil from the well may be contaminated with the
mud. If oil is used, it is recovered because of its value,
either by collecting it directly or by moving it through the
production system. If water is used, it will be moved through
the oil production and treatment systems and disposed of.
Special additives may be necessary in low solids fluids.
Salts are used to obtain the necessary fluid density. Organic
polymers are used for viscosity and to aid in filtration control.
Corrosion inhibitors, biocides, and buffers may also be used.
111-20
-------
High solids fluids used for completion and workover may
contain the same materials as those used for drilling except that
they may be freshly formulated to avoid fine drilled cuttings
that accumulate in the used drilling fluid.
F. PRODUCTION
Production operations begin with completion and include all
post completion work necessary to bring the hydrocarbon reserves
from the producing formation.
Crude oil, natural gas, and gas liquids normally are
produced from geological reservoirs through a deep well bored
into the surface of the earth. The fluid produced from oil
reservoirs normally consists of oil, natural gas, and salt water
or brine containing both dissolved and suspended solids. Gas
wells may produce dry gas but, usually, also produce varying
quantities of light hydrocarbon liquids (known as gas liquids or
condensate) and salt water (brine). The water contains dissolved
and suspended solids and hydrocarbon contaminants, metals, and
radionuclides. Suspended solids normally are composed 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 based on its specific
gravity. The oil can range from very light gasoline-like
materials (called natural gasolines) to heavy, viscous asphalt-
like materials.
The fluids normally are moved to the surface through tubing
contained within the larger cased bore hole. For oil wells, the
111-21
-------
energy required t.r lift the fluids up the well can be supplied by.
the natural pres as in the formation or it can be provided or
assiste by various man-made operations at the surface. The most
common methods of supplying man-made energy to extract the oil
are: 1) waterflooding, which is the injection of fluids into the
reservoir to maintain pressure that otherwise could drop during
withdrawal; 2) the injection of gas into the well stream in order
to lighten the column of fluid in the bore and assist in lifting
the fluid as the gas expands as it rises to the surface; and 3)
the 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 which make up the well
head.
Once at the surface, the various constituents in the fluids
produced by oil and gas wells are separated: gas from the
liquids, oil from water, and solids from liquids. Figure III-6
is a schematic representation of the processes used to separate
oil, gas, water, and solids. This diagram shows the facilities
in different locations with the final separation steps located
onshore. In many cases, all or most of the facilities can be
located entirely on a platform. The marketable constituents,
normally the gas and oil, are then removed from the production
areas and the wastes, normally the brine and solids, are disposed
of after further treatment. At this stage, the gas may still
contain significant amounts of hydrocarbon liquids and may
require further separation processes.
The gas, oil, and water may be separated in a single vessel
or, more commonly, in several stages. Some gas is dissolved in
the oil and is released from solution as the pressure on the
fluid drops. Fluids from high-pressure reservoirs may have to be
passed through a number of separating stages at successively
lower pressures before the oil is free of gas. The oil and brine
111-22
-------
to
10
STHIAM
OAS. OIL. WATER. SANO1
- XL JL
»mst I SICONO
ntCOVIMlf STAOt I STAOt •T?'
CLf AN WATER TO DISPOSAL
MATf m TUfATMtNT POLLUTION CONTROL
-^TO cnupt on
—^—^^^—^^— — s , — ^— -
. _ . •;/ . ^'_; z. *1" ?
NATURAL GAS COMPfltSSORS ^Jof>«VOP»ATION> -f .-_-».-
Source: 8
FIGURE III-6. CENTRAL TREATMENT FACILITY IN AN ESTUARINE AREA
-------
do not separate as readily as .the gas does. Usually, a quantity-
of oil and water is present as an emulsion. This emulsion can
occur naturally in the reservoir or can be caused by various
processes which tend to mix the oil and water vigorously, causing
t
the emulsion to form. Passage of the fluids into and up the
well, through well head 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 tend to cause the emulsified
liquids to separate or coalesce.
Fluids produced by oil and gas wells usually are introduced
into a series of vessels for a multi-stage separation process.
Figure III-7 shows a gas separator for separating gas from the
well stream. Liquids (oil, or oil and water) along with
particulate matter leave the separator through the dump valve and
f]ow to the next stage: oil-water separation. Because gas comes
o. t. of solution as pressure drops, gas-oil separators often are
arranged in series (see Figure III-6). High-, intermediate-, and
low-pressure separators are the most common arrangement, with the
high-pressure liquids passing through each stage in series and
gas being taken off at each stage. Fluids from lower-pressure
wells would go directly to the most appropriate separator. The
liquids are then piped to vessels for separating the oil from the
produced water. Fluids which do not contain emulsified oils and
separate easily may be treated for water removal in a simple
separation vessel called a free water knockout.
Remaining oil-water mixtures continue to another vessel for
more elaborate treatment (see Figure III-8). In this vessel
(which may be called a heater-treater, electric dehydrator, gun
barrel, or wash tank, depending on configuration and the
separation method employed), there is a relatively pure layer of
111-24
-------
RELIEF.
VALVE
PRESSURE fc/f^
GAUGE *^\)
MIST
\~EXTRACTOR
JIL-WATER \
INTERFACE \
H
I
10
U1
GAS OUTLET^
SECONDARY \ \-,,
SEPARATION1. "//,".'.
SECTION !
BAFFLE—**
GAS OUTLET]>
LIQUID
LEVEL
CONTROL
PRIMARY
SEPARATE
SECTION
INSTRUMENT
GAS SUPPLY
JQILOUTLEf>
CONTROL VALVE
WATER OUTLET^
CONTROL VALVE'
Sources 8
FIGURE II1-7. HORIZONTAL GAS SEPARATOR
-------
•At OUTLET
IMULftlON
WUT
Hf*T
CXCMANUN
OIL OUT
EMULSION IN
GAS OUT
WATER OUT
Sourcei 8
FIGURE III-8. TYPICAL VERTICAL HEATER TREATER
111-26
-------
oil on the top, relatively pure brine on the bottom, and a layer.
of emulsified oil and brine in the middle. There is usually a
sensing unit to detect the oil-water interface in the vessel and
regulate the discharge-of the fluids. Emulsion breaking
chemicals often are added before the liquid enters this vessel.
The vessel itself often is heated to facilitate breaking the
emulsion, and some units employ an electric grid to charge the
liquid to aid in breaking the emulsion. A combination of
treatment methods often is employed in a single vessel. In
three-phase separation, gas, oil, and water are all separated in
one unit. The gas-oil and oil-water interfaces are detected and
used to control rates of influent and discharge. Oil from the
oil-water separators usually is sufficiently free of water and
sediment (less than 2%) to be marketable.
The major waste stream associated with production
activities, therefore, is the produced water waste stream.
Produced sand is a minor waste stream. Both waste streams
originate with the gas and/or oil product stream and are
separated from the oil product in the initial processing of the
production stream. The produced sand is a small volume and at
most locations is separated from the oil and water in the initial
separating units. These small volumes of sand are removed
periodically for disposal.
The produced water or produced water/solids mixtures contain
too much oil to be disposed of into a water body. The object of
processing up to this point is to produce marketable products
(clean oil and dry gas). In contrast, the next stages of
treatment are necessary to remove sufficient oil from the
produced water so that it may be discharged. These treatment
operations do not significantly increase the quality or quantity
of the salable product, but they do decrease the impact of these
waters on the environment.
111-27
-------
Produced wo .ers from the last stage of processing typically
contain several hundred to perhaps a thousand or more parts per
million of oil. Two methods of disposal are treatment and
discharge to surface (salt) waters or injection (with or without
prior treatment) into a suitable subsurface formation in the
earth. Some of the same operations used to facilitate separation
for processing (chemical addition and retention) are used to
treat produced water. Other methods of treatment include
separation by gas flotation and/or filtration.
G. EXISTING SOURCES
At present, the majority of offshore oil and gas production
occurs in the Gulf of Mexico (primarily Louisiana and Texas), and
off the coast of California. Exploration and development have
been underway in other offshore areas (e.g., Atlantic coast,
other Gulf states, Gulf of Alaska, Norton Sound, Bering Sea, and
Beaufort Sea), but as yet no significant production is occurring
at these sites.
Existing offshore production platforms are located within
either federal or state lease tracts. Federal lease tracts
encompass all waters that are not under state jurisdiction. Host
states' jurisdictions over the leasing of offshore tracts extend
3 miles from their mainland coasts, with the following
exceptions: Texas and Florida have jurisdiction over areas up to
3 leagues (9 nautical miles, or 10.4 statute miles) away from
their shores. California's 3-mile limit is extended from all
offshore islands, as well as its mainland coast.
An estimated 2,260 structures currently are producing oil
and/or gas in the offshore waters of the United States. This
estimation is based upon information from two sources: "Minerals
111-28
-------
Management Service Platform Inspection, Complex/Structure Data
Base," March, 1988 and "Oil and Gas Activities Affecting
California's Coastal Zone: A Summary Report," California Coastal
Commission, December,"1988. This estimate includes all tracts
leased offshore in the Gulf of Mexico, California and Alaska.
There are no structures in the Atlantic Ocean.
The Agency's estimate of existing structures includes only
those platforms that currently are producing known volumes of a
specific product (i.e., oil, gas or both). The only platforms
producing oil in Alaska (Endicott Bay region) are on gravel
islands, and they reinject the produced water to meet state
regulations.
Table III-2 presents the number of existing producing
structures by geographic region and production type, and shows
that 99% of the existing offshore structures are in the Gulf of
Mexico. The number of existing wells on the 2,260 structures is
approximately 13,000 (anywhere from 1 to 80 wells may exist per
platform).
The Alaska offshore production activity is not reflected in
the summary in Table III-2 because these wells are on gravel
islands and are considered to be onshore subcategory structures
by the State of Alaska. These wells have all of their produced
waters collected and reinjected at one location.
In addition, structures located in state waters in the Gulf
of Mexico are not included in this summary. The Agency has
attempted to profile the structures in state waters in the Gulf
of Mexico but has not been successful in doing so. The state
offshore records have permitted structures under three
subcategories instead of only offshore: onshore (for those
structures with the well head on land but the bottom hole is
111-29
-------
Region
TABLE III-2
NUMBER OF EXISTING PRODUCTION FACILITIES
BY GEOGRAPHIC REGION AND PRODUCTION TYPE
Oil Only
Gas Only
Oil and Gas
Total
Gulf
Pacific
Alaska
Atlantic
161
0 __
0
0
1,104 '
1
0
0
968
26
0
0
2,233
27
0
0
Totals
161
1,105
994
2,260
Source: 9
111-30
-------
offshore), coastal, and offshore. In the maps available from
NOAA and other sources, there is no indication of how many wells
there are per structure, if any of the wells are producing, or
what product may be produced.
However, although the number of wells is not included in
this summary, the overall estimate of wastewater and drilling
fluids and cuttings volumes is used in a manner in which the
produced water cost of treatment is accounted for. The Agency
believes that the capital costs and the operating and maintenance
costs are valid even though the profiling effort does not include
those structures located in State waters. Peak water production
volumes from offshore Federal waters only were used by the Agency
in the development of capital costs while average annual water
production volumes from offshore Federal waters only were used to
calculate operating and maintenance costs. The Mineral
Management Service (MMS) reported the water production volumes
for offshore Federal waters in the year 1987 and state waters
records reported water production volumes for state offshore
waters for the year 1986. The Agency's estimate of average water
production volumes in offshore .Federal water areas only exceeded
the summation of the MMS and state records volumes reported by
60%. Since the Agency's water production volume did exceed
actual volumes, the capital costs and the operating and
maintenance costs that were developed accounted for those
structures in state waters that the Agency was unable to profile.
However, because these costs are distributed over fewer
structures, the impacts may be somewhat over-estimated.
In terms of development operations, offshore drilling varies
from year to year depending on such factors as the hydrocarbon
economic market conditions, state and federal leasing programs,
and reservoir discoveries. In 1981, there were almost 1,500
wells drilled offshore culminating the upward trend of the 1970s.
111-31
-------
The average number of wells drilled during the 1972-1982 time
period was 1,100 wells/year.
Tables III-3 ancPlII-4 show the quantity and market value of
the oil and gas produced from offshore platforms in recent years
and throughout the history of the federal outer continental shelf
leasing program.
H. NEW SOURCES
The Minerals Management Service (MMS) projected production
figures for the Outer Continental Shelf (DCS) at 5-year
increments until the year 2015.10 The projections are shown
below:
Year 1985 1990 1995 2000 2005 2010 2015
Oil (MMBBLS) 410 430 532 610 575 421 275
Gas (BCF) 4745 3499 3839 3955 3707 2986 2068
Figures III-9 and 111-10 show historical production and
projections of oil and gas production from the U.S. outer
continental shelf. These figures were projected from developed
and undeveloped reserve estimates and conditional mean
undiscovered, economically recoverable resource estimates. The
resource and reserve estimates were obtained from data used in
the 5-year (1987-91) Environmental Impact Statement
infrastructure analysis.
1. Drilling Activity
The Agency has developed two new source projection estimates
for the years 1986-2000. Both are based on an average price of
$2I/barrel. The first >. . timate is based on "unconstrained
development." The second is based on a "constrained"
111-32
-------
TABLE III-3
PRODUCTION AND VALUE OF U.S. CRUDE OIL AND CONDENSATE
ONSHORE - OFFSHORE
PRODUCTION
(THOUSANDS OF BARRELS)
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
ONSHORE
2,560,242
2,508,356
2,546,187
2,761,891
2,722,715
2,766,716
2,743,203
2,744,432
2,744,080
2,780,219
2,818,450
2,710,628
OFFSHORE
496,537
467,824
439,173
416,325
398,595
376,649
385,421
412,283
426,919
469,477
456,103
457,624
TOTAL
3,056,779
2,976,180
2,985,360
3,178,216
3,121,310
3,146,365
3,128,624
3,156,715
3,170,999
3,249,696
3,274,553
3,168,252
OFF-
SHORE
AS A
% OF
TOTAL
16.2
15.7
14.7
13.1
12.8
12.1
12.3
13.1
13.5
14.4
13.9
14.4
DOLLAR VALUE AT WELLHEAD
(THOUSANDS OF DOLLARS)*
ONSHOREa
19,361,086
20,420,899
21,996,649
24,747,514
34,064,477
57,791,998
87,151,743
78,270,757
71,867,673
71,991,425
67,868,276
34,316,550
OFFSHOREa
3,754,973
3,808,641
3,794,073
3,730,310
4,986,855
7,930,018
12,244,641
11,758,641
11,180,818
12,110,707
10,982,960
5,793,520
TOTAL
23,116,059
24,229,540
25,790,722
28,477,824
39,051,332
65,722,016
99,396,384
90,029,512
83,048,491
84,102,132
78,851,236
40,110,070
WELLHEAD
PR ICE, PER
BARREL
(DOLLARS)
7.56
8.14
8.57
8.96
12.51
20.89
31.77
28.52
26.19
25*. 88
24.08
12.66
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
•Current dollars.
aTotal dollar value distributed in proportion to percentages of production onshore and offshore.
Source: 1
-------
TABLE II1-4
PRODUCTION AND VALUE OF U.S. NATURAL GAS
ONSHORE - OFFSHORE
PRODUCTION
(MILLIONS OF CUBIC
YEAR
1975
1976
H 1977
£ 1978
1 1979
*" 1980
1981
1982
1983
1984
1985
1986
ONSHORE
15.943,934
15.637,042
15,528,536
14,839,994
15,026,356
14,996.551
14.631.239
13.151.448
12,170.095
12,888.354
12.566.758
12.202.345
OFFSHORE
4,164,727
4,315,396
4,496,927
5,134.039
5,444,904
5.382,236
5,546.462
5,368,227
4,486.905
5.341,284
4,798,242
4,588,565b
FEET)
TOTAL
20,108.661
19.952.438
20.025,463
19,974,033
20,471.260
20,378,787
20,177,701
18.519,675
16,657,000
18,229.638
17,198,000
16,790,910
OFF-
SHORE
AS A
Z OF
TOTAL
20.7
21.6
22.5
25.7
26.6
26.4
27.5
29.0
26.9
29.3
27.9
27.3
DOLLAR VALUE AT WELLHEAD
(THOUSANDS OF DOLLARS)*
ONSHOREa
7,092,450
9.069.032
12.272.078
13.430.116
17,699,890
23.586.880
28.969,884
32.308,618
31.865.966
33.896.371
31.123,393
23,672,549
OFFSHOREa
1,852,612
2,502,744
3,553.876
4,616,384
6,413.744
8,465.302
10,981,964
13,188,147
11,748.403
14,047.577
12,043,587
8,901,816
TOTAL
8,945,062
11,571,776
15,825,954
18,076,500
24,113.634
32,052.182
39.95J.848
45,496.765
43,614.369
47,943.948
43.166.980
32,574.365
WELLHEAD
PRICE
(t/Mcf)
0.45
0. 58
0. 79
0.91
1.18
1.59
1.98
2.46
2.59
2.66
. 2-51
1.94
YEAR
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
*Current dollars.
"Total dollar value distributed in proportion to percentages of production onshore and offshore.
Across natural gas withdrawals offshore, from Natural Gas Annual 1986
^Source: 1
-------
01
«
a
o
o
M
O
YEARS
06WLFPRW. H PACIFIC PROI. |3 GULF HISTORY 0 PACIFIC HISTORY HATUHTIC PRW.
FIGURE III-9. HISTORY AND PROJECTION OF OIL PRODUCTION IN UNITED STATES OCS AREAS
-------
We
u>
21
i
i
I
I
1971
1975
I9B0
1985
1999
1995
2905
2010
TEMS
00JLFPPOJ. 0 PACIFIC PWM.^eUlfmSTORT O WCIFIC HISTORY HflTUWIC PRW. 0 AflSKft PRW.
FIGURE 111-10. HISTORY AND PROJECTION OF GAS PRODUCTION IN UNITED STATES OCS AREAS
-------
projection, which accounts for the recent moratorium and
restricted leasing in the Pacific and off California. Both
scenarios are shown in Table III-5. The unconstrained estimate
shows that between 198% and the year 2000 there would be an
average of 980 wells/year drilled. This estimate is based on the
above mentioned MMS projections. Of these 980 wells/year, 590
wells/year would become producing wells drilled on new structures
and the remaining 390 wells/year would be dry holes. At the
present time, in addition to the Gulf and Pacific areas, there
are exploration activities occurring in areas within the Chukchi
and Beaufort Seas of Alaska as well as in the Atlantic Ocean
which may ultimately lead to new source development and
production activities.
Recent actions have led the Agency to reevaluate this
profile, and a more restricted estimate has been developed which
reflects: 1) the ban on state water activity in California, and
2) the Presidential moratorium on oil and gas leasing and
development off California and in the North Atlantic. The
constrained estimate projects that a total of 759 new wells will
be drilled annually between the years 1986 and 2000 (with 455 of
these going into production).
2. Production
Estimates for production are also based on the MMS
forecasts, including both constrained and unconstrained
scenarios. Table III-6 shows the new source projections for
production platforms. Note: platforms may include anywhere from
1 to 40 wells, according to EPA's model characteristics (see
Section VIII).
111-37
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TABLE III-5
ANNUAL DRILLING .ACTIVITY FOR NEW SOURCES
(For 1986 to 2000, based on $2I/barrel)
Annual Number of New Wells Drilled
Region Unconstrained Constrained
•
Gulf of Mexico 715 715
Pacific 237 32
Alaska 12 12
Atlantic 16 0
TOTALS 980 759
Source: 9
TABLE III-6
NEW SOURCE PRODUCTION PLATFORMS
(For 1986 to 2000, based on $2I/barrel)
Number of New Platforms
Region Unconstra ined Constrained
Gulf of Mexico 755 755
Pacific 84 7
Alaska 8 0
Atlantic i 4
TOTALS 851 766
Source: 9
111-38
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I. CURRENT PERMIT STATUS
Offshore oil and gas structures in the Gulf of Mexico,
California, and Alaska^ are regulated by general and individual
permits using Best Professional Judgment (BPJ) at the BAT and
NSPS levels of control. The general permits and some of the
individual permits are based upon the effluent limitations and
*
guidelines that were proposed in 1985 and are more stringent than
the BPT regulations that were promulgated in 1979.
1. Gulf of Mexico
In the Gulf of Mexico there are three general permits
covering exploration, development, and production activities.
Two of these general permits cover state waters: one for
Louisiana state waters and one for Texas state waters. Both of
these general permits expired on July 15, 1988; however, they
have been administratively extended to cover those structures
originally covered under these permits. If there are any new
structures in state waters not previously covered by either of
the original general permits, they are individually permitted.
The third general permit for the Gulf of Mexico covers structures
in those waters that are seaward of the inner boundary of the
territorial seas, and involved in exploration, development, and
production activities.
2. Alaska
In Alaska, there are four general permits covering four
different regions of oil and gas activities:
Cook Inlet; These structures are classified as coastal
structures and are covered under a coastal general permit.
111-39
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Chukchi Sea; There is one exploration structure in this
area and to date there have been three exploratory wells
drilled from this structure. The general permit for this
structure only covers exploration activities and is known as
the Beaufort II general permit.
Beaufort Sea; There are two exploratory structures in this
area, each being operated by a different company. The
general permit for these two structures covers only
exploration activities and is known as the Beaufort II
general permit.
Endicott Island; There are production structures in this
area but all are on gravel islands. All of the produced
waters (from approximately 100 wells) are collected and are
reinjected at one location in order to meet state
requirements.
3. California
In California, there are three general permits for federal
waters off Southern California. Two of these general permits
have not been issued as final yet. One of these draft general
permits covers development and production activities while the
other covers exploration activities. Any new structures are
covered by individual permits that are very similar to the 1985
proposed guidelines requirements. The third general permit is
one that expired June 30, 1984 but has been administratively
extended for those structures that were covered by the permit as
of June 30, 1984. This general permit had been issued as final
for those structures involved in exploration and development
activities.
111-40
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Table III-7 identifies the four general permits associated .
with offshore subcategory structures that were used as a basis to
, t i
develop "current" baseline costs and loadings (discussed in
Section X) for the new- proposed requirements. The general
permits are identified by their status, region, coverage, and
expiration date. Requirements in these general permits vary from
region to region; however, produced water BPT level limitations
are consistently required while the major differences are the
requirements covering drilling fluids and cuttings, and, to some
extent, miscellaneous waste streams such as deck drainage and
produced sand. Table III-8 presents a summary of the different
requirements for drilling fluids and cuttings contained in the
various offshore permits.
111-41
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TABLE III-7
GENERAL PERMITS. USED TO DEVELOP "CURRENT"
BASELINE COSTS AND LOADI- 5
REGION
PERMIT
COVERAGE
EXP. DATE
VI
GMG28000-Final NPDES
General Permit for the
OCS of the Gulf of Mexico
(51 PR 24897);
July 9, 1986
Structures in the
Gulf of Mexico
seaward of the
outer boundary of
the territorial seas
July 1, 1991
IX
CAG280605-Draft General
NPDES Permit for Offshore
Oil and Gas Exploration
Activities off Southern
California (50 FR 34052);
August 22, 1985
CAG280622-Draft General
NPDES Permit for Offshore
Oil and Gas Development and
Production Activities off
Southern California
(50 m 34052); Aug. 22, 1985
Federal waters off
Southern California
Not issued as
final yet
Federal Waters off
Southern California
Not issued as
final yet
AKG284100-Final NPDES
General Permit for Oil and
Gas Operations on the OCS
of Alaska Beaufort Sea II
State and Federal
Vaters Exploration
Drilling Only
Sept. 27, 1993
111-42
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TABLE III-8
SUMMARY OF CURRENT REQUIREMENTS FOR
DRILLING FLUIDS AND CUTTINGS FOR THE OFFSHORE PERMITS
REQUIREMENT
GULF OF MEXICO
PACIFIC
ALASKA
No Discharge of Oil Based
Drilling Fluids and Cuttings
(BPT Requirement)
Mandatory Barging Based on
Water Depth
Metals Limitation
Mercury (ing/kg)
Cadmium (mg/kg)
No Discharge of Oil in
Detectable Amounts
For Lubricity
(Diesel)
As a Pill
(Mineral***
Toxicity Limitation
Limit (Drilling Fluids)
No Discharge of "Free Oil"
Static Sheen Test
(Cuttings From Use of Water
Based Drilling Fluids)
Yes
No
No
Yes
No
Yes
No
Yes (Diesel)
No*
Yes
30,000 ppm
spp*
No
Yes Yes
(Barite) (Barite)
1 1
2 3
Yes (Diesel) Yes
No*
Yes
30,000 ppm
spp*
Yes
Yes
Diesel not
Allowed)
Yes****
Yes
* Suspended Particulate Phase
** Diesel pill plus a 50 bbl buffer of drilling fluid on either side of the
pill cannot be discharged; mineral oil can be discharged without a
buffer
*** Mineral oil pill plus a 50 bbl buffer of drilling fluid on either side
of the pill cannot be discharged
**** With a pre-approved drilling fluid system
111-43
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J. REFERENCES
1. "Economic Impact Analysis of Effluent Limitations Guidelines
and Standards ofperformance for the Offshore oil and Gas
Industry," prepared by Eastern Research.Group, Inc. for U.S.
EPA, Washington, D.C., March 1988.
2. Imco Service, Houston, TX, "Applied Mud Technology."
3. Technical Resources, Inc. Amendment of Original by Dalton-
Dalton-Newport, "Assessment of Environmental Fate and
Effects of Dischargers from Offshore Oil and Gas
Operations." Prepared for U.S. Environmental Protection
Agency, Monitoring and Data Support Division, EPA 440/4-85-
002.
4. "World Oil's Guide to Drilling, Completion and Workover
Fluids," World Oil. June 1987, p. 37.
5. American Petroleum Company, Introduction to Oil and Gas
Production. Book 1 of the Vocational Training Series,
Dallas, TX, 1983.
6. Walk Haydel & Associates, Inc., Industrial Process Profiles
to Support PNIN Review: oil Field Chemicals, prepared for
U.S. Environmental Protection Agency, Economics and
Technology Division, Office of Toxic Substances.
7. Parker, Michael E., "Completion, Workover, and Well
Treatment Fluids," June 29, 1989.
8. Gray, George R., H. C. H. Darley, and Walter F. Rogers,
Composition and Properties of oil Well Drilling Fluids.
January 1980.
9. Memo from ERC, Inc. to EPA, "Proposed Revisions to Offshore
Oil and Gas Platform Projections for the 1986 to 2000 Time
Period," October 8, 1990.
10. Memo from Chief, Offshore Resource Evaluation Division to
Associate Director for Offshore Minerals Management,
Minerals Management Service, U.S. Department of the
Interior, "30-year Projections of oil and Gas Production for
the U.S. Outer Continental Shelf Areas," December 2, 1985.
111-44
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SECTION IV
INDUSTRY SUBCATEGORIZATION AND DEFINITIONS
A. INTRODUCTION ^
Because the oil and gas industry is quite large and
diversified, EPA found it necessary to segment the industry into
five subcategories. Subcategorization allows the Agency to
tailor the requirements of technology-based limitations more
precisely to specific characteristics within the industry.
Subcategorization may take into account raw materials used,
product, processes employed, waste streams produced, geographical
location, size and age of equipment, non-water-quality aspects of
waste disposal and treatment, treatment technology, and treatment
costs.
The oil and gas extraction point source category currently
includes five subcategories: offshore, onshore, coastal,
agricultural and wildlife water use, and stripper (40 CFR Part
435). This document covers only the offshore subcategory. This
subcategory is applicable to those facilities engaged in field
exploration, drilling, well production, and well treatment in the
oil and gas extraction industry which are located in waters that
are seaward of the inner boundary of the territorial seas as
defined in Section 502 of the Act.
The studies in support of previously proposed NSPS and BAT
and final BPT regulations for the oil and gas extraction industry
concluded that three major factors—geographic location, type of
facility, and wastewater production—are the basis for
Subcategorization of this industry (41 FR 44945, 44 FR 22069).
In developing proposed NSPS, BAT, and BCT regulations for
the offshore segment of this industry, EPA evaluated
IV-1
-------
characteristics of wells, platform waste effluents, available
treatment technologies, and platform operations to determine if
it was appropriate to modify the BPT subcategorization scheme.
EPA found no basis upon which to change the existing subcate-
•
gorization for the offshore subcategory. The Agency concluded
that the existing single subcategory for the offshore segment was
also appropriate for proposed NSPS, BAT, and BCT regulations.
•
However, consideration of feasibility, costs and non-water
quality environmental impacts of various treatment technologies
have led EPA to develop certain segments within the offshore
subcategory. These segments, based on depth or distance, are
discussed below. Furthermore, in an effort to clarify the
meaning of certain terms, EPA has developed definitions that are
also discussed in this section.
B. SHALLOW/DEEP WATERS
Some of the regulatory options that EPA has developed for
the offshore subcategory are based on a structure's location in
shallow or deep waters. In the 1985 proposal, the Agency
proposed variable depth limits for different offshore areas in
order to allow for an option of onshore reinjection of produced
water from those structures located in shallow water since they
can pipe the produced water to shore due to their proximity to
it. Through the compilation of data from industry the following
water depths were proposed to be shallow water:
Gulf of Mexico; Industry data indicated that 52% of all the
projected new sources in 15 meters or less of offshore
waters would pipe produced water to shore. The Agency
believed the same percentage of platforms in water depths of
20 meters or less could pipe to shore and reinject.
IV-2
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Atlantic: The water depth of 20 meters was selected for
this region since there was no historic trend for
production.
California; It was determined that 60% of the active
production platforms located in water depths of 50 meters or
less piped to shore for treatment while only 8% of the
structures in depths greater than 50 meters piped to shore
for treatment. Based on this data, a depth of 50 meters or
less was selected as shallow water in California.
Alaska; It was assumed that southern Alaska bathymetry
(ocean depth) was similar to California's bathymetry, so a
water depth of 50 meters or less was proposed to be shallow.
The southern Alaska region includes the Bristol Bay/Aleutian
Island Chain, Cook Inlet, and the Gulf of Alaska. For other
parts of Alaska the Agency proposed shallow water to be of a
depth of 20 meters or less in the Norton Basin and 10 meters
or less in the Beaufort Sea. The water depths in the North
were proposed to be less than the 50 meters selected for
southern Alaska because the harsher climates in the more
northern region made the probability of piping to shore for
treatment less probable.
For determination of water depth, the 1985 proposal
referenced recent nautical charts or bathymetric maps available
from the National Oceanic and Atmospheric Administration. The
water depth of the structure was defined to be based on the
proposed location of the structure's well slot structure or
produced water discharge point.
IV-3
-------
Table IV-1 presents the number of existing producing
structures by geographic region, production type, and water
depth. Table IV-2 presents the number of new wells drilled
annually by region an
-------
TABLE TV-1
NUMBER OF EXISTING PRODUCING STRUCTURES
BV PRODUCTION TYPE AND HATER DEPTH
SHALLOW WATER
DEEP WATER
Ration Oil
Only
Gulf 126
Pacific 0
Alaska 0
Atlantic 0
Total* 126
Ration
Gulf of Mexico
Pacific
Alaska
Atlantic
TOTALS
Ration
Gulf of Mexico
Pacific
Alaska
Atlantic
TOTALS
Oil and Gas Total " Oil Oil and Gas Total
Gas Only Shallow Only Gas Only Deep
497 676 1299 35 471 428 934
10 0 10 0 16 1 17
0 0000* 00
0 00 00 00
307 676 1309 33 487 429 951
TABLE IV-i
NUMBER OF NEW WELLS DRILLED ANNUALLY
ACCORDING TO WATER DEPTH
(UNCONSTRAINED GROWTH)
Shallow Water Deep Water
265 450
10 227
9 3
0 16
284 696
TABLE IV-3
NUMBER OF NEW WELLS DRILLED ANNUALLY
ACCORDING TO WATER DEPTH
(CONSTRAINED GROWTH)
Shallow Water D««p Water
72 643
0 32
9 3
0 0
81 678
Total
All
2233
27
0
0
2260
Total
715
237
12
16
980
Total
715
32
12
0
759
IV-5
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TABLE IV-*
HEW STRUCTURES DURING 1986-2000
ACCORDING TO HATER DEPTH
(UNCONSTRAINED GROWTH)
Region Shallow Hater D««p Hater Total
Gulf of Muleo
Pacific
Atlantic
Alaaka
TOTALS
388
3
0
2
393
367
81
8
2
458
735
84
8
4
851
TABLE XV-5
NEW STRUCTURES DURING 1986-2000
ACCORDING TO HATER DEPTH
(CONSTRAINED GROWTH)
Region Shallow Hater Deep Water Total
Gulf of Mexico 388 367 755
Pacific 0 77
Atlantic 0 00
Alaska 2 2 ' 4
TOTALS 390 376 766
IV-6
-------
requirements and resulting air emissions, expended for the
necessary transportation, were unexpectedly high. In addition,
the volume of solids (residuals) required to be land disposed
raised concerns over the adequacy of proper disposal sites. In an
effort to mitigate potential non-water quality impacts, EPA
looked at several distance to shore senarios for further
segmenting of this subcategory (see Section XI). EPA evaluated a
breakdown of structure locations based on distances (in miles)
from shore of 4, 6 and 8 miles for produced waters as well as
drilling fluids and drill cuttings.
EPA determined in its analysis of regulatory options that
the use of a 4 mile category is preferable to the other options
(6 and 8 miles), because the 8-mile distance from shore does not
sufficiently reduce non-water quality environmental impacts (See
section XIV) or the differences between the pollutant removals at
6 miles from those at 4 miles are not significant1.
Table IV-6 presents the number of existing producing
structures by geographic region and production type according to
the 4-mile cutoff. As shown, approximately 208 existing
structures are at the 4-mile distance or closer, which is
approximately 9% of the total. This same percentage of
structures, although not necessarily the same structures, are
located in approximately 6.3 meters of water.
Table IV-7 presents the estimated number of new wells
drilled annually by geographic region according to the 4-mile
cutoff for the unconstrained profile. As can be seen by the
table, approximately 10% of new wells will be in waters 4 miles
or less from shore. The estimated percentage of wells at 6 miles
or less is 11%, and at 8 miles or less is 19%. Table IV-8 shows
the number of new wells drilled annually according to distance
from shore for the constrained profile. Table IV-9 and IV-10
IV-7
-------
TABLE IV-6
EXISTING STRUCTURES ACCORDING TO DISTANCE FROM SHORE
< 4 MILES
> 4 MILES
REGION OIL ONLY OIL & GAS GAS OIL ONLY OIL & GAS
Gulf 50 63 84 111 905
Pacific 0 11 0 0 15
Atlantic 0 00-0 0
Alaska 0000 0
TABLE IV -7
NEW WELLS DRILLED ANNUALLY
ACCORDING TO DISTANCE FROM SHORE
(UNCONSTRAINED GROWTH)
REGION < 4 MILES > 4 MILES
Gulf of Mexico- 72 643
Pacific 71 166
Atlantic 0 16
Alaska 9 3
GAS TOTAL
1,020 2,233
1 27
0 0
0 0
2,260
TOTAL
715
237
16
980
IV-8
-------
Ration
TABLE IV-8
HEW HELLS DRILLED ANNUALLY
ACCORDING TO DISTANCE FROM SHORE
(CONSTRAINED GROWTH)
< 4 Mi
Miles
> 4 Miles
Total
Gulf of Mexico
Pacific
Atlantic
Alaska
TOTALS
Region
Gulf of Mexico
Pacific
Atlantic
Alaska
TOTALS
Region
Gulf of Mexico
Pacific
Atlantic
Alaaka
TOTALS
265 450
0 32
0 0
9 3
274 485
TABLE XV-9
NEW PRODUCING STRUCTURES
ACCORDING TO DISTANCE PROM SHORE
(UNCONSTRAINED GROWTH)
< 4 Miles . > 4 Miles
140 615
20 64
0 8
2 2
162 689
TABLE IV-10
NEW PRODUCING STRUCTURES
ACCORDING TO DISTANCE PROM SHORE
(CONSTRAINED GROWTH)
< 4 Miles > 4 Miles
140 615
0 7
0 0
2 2
142 624
715
32
0
12
759
Total
755
84
8
4
851
Total
755
7
0
4
766
IV-9
-------
present the distribution of new producing structures according .te
distance from shore for the unconstrained and constrained
profiles, respectively.
D. REGULATORY DEFINITIONS
1. Jnner Boundaries of the Territorial Seas
The offshore subcategory (as defined at CFR 435.10) of the
Oil and Gas Extraction Point Source Category covers those
structures involved in exploration, development and production
operations seaward of the inner boundary of the territorial seas.
The inner boundary of the territorial seas is defined in
Section 502(8) of the Clean Water Act as:
"the line of ordinary low water along that portion of the
c st which is in direct contact with the open sea and the
line marking the seaward limit of inland waters. . ."
In some areas the inner boundary of the territorial seas is
clearly established and is shown on maps. For example, the Texas
General Land Office (Survey Division) has available 7.5 minute
quadrangle maps for the entire coastline of Texas which clearly
show the inner boundary of the territorial seas. Additionally,
the Louisiana State Minerals Board (Civil and Engineering
Division) has available maps for the Louisiana coastline showing
the inner boundary of the territorial seas. In other areas, such
as Alaska, the baseline is not clearly established. As part of
the permitting process for discharges in the territorial seas,
the waters of the contiguous zone, and the oceans, Section 403(c)
of the Clean Water Act sets out criteria requiring a
determination of whether or not the discharge will cause
degradation of these waters. In questionable 403(c)
IV-10
-------
determinations of whether the discharge is beyond the baseline .or
not, the State Department is consulted to make site specific
determinations. In relation to the implementation of the BPT
limitations guideline's*, no problems have been associated with the
definition of the inner boundary of the territorial seas.
2. Domestic Waste
The 1985 proposed regulation (40 CFR Part 435, dated August
26, 1985) defines domestic waste as wastewater resulting from
laundries, galleys, showers, etc. In this rulemaking, other
examples of domestic wastes are added for the purpose of clarity.
These include wastes from safety shower and eye wash stations,
hand wash stations, and fish cleaning stations. This
clarification of the definition does not change the regulation or
its economic impact.
3. Minor Wastes
In addition to those specific wastes for which effluent
limitations are proposed, offshore exploration and production
facilities discharge other wastewaters. These wastes were
investigated yet were assumed to be minor, and no control is
being proposed2. These sources are categorized into 15 "minor
wastes11 categories and are listed as follows:
1) Desalinization unit discharge - wastewater associated
with the process of creating fresh water from seawater
2) Blow out preventer fluid - fluid used to actuate the
hydraulic equipment on the blowout preventer
3) Laboratory wastes from drains
4) Uncontaminated ballast/bilge water (with oil and grease
less than 30 mg/L) - seawater added or removed to
maintain proper draft
IV-11
-------
5) Mud, cuttings, and cement at the seafloor that result -
from marine riser disconnect and well abandonment and
plugging . .
6) Uncontaminated sea water including fire control and
utility lift pumps excess water, excess sea water from
pressure maintenance, water used in training and
testing of fire protection personnel, pressure test
water, and non-contact cooling water
7) Boiler blowdown - discharge from boilers necessary to
minimize solids build-up in the boilers
8) Excess cement slurry the results from equipment
washdown after a cementing operation
9) Diatomaceous earth filter media that are used to filter
seawater or other authorized completion fluids
10) Waste from painting operations such as sandblast sand,
paint chips, and paint spray
11) Uncontaminated fresh water such as air conditioning
condensate and potable water
12) Material that may accidentally discharge during bulk
transfer, such as cement materials, and drilling
materials such as barite
13) Waterflooding discharges - discharges associated with
the treatment of seawater prior to its injection into a
hydrocarbon-bearing formation to improve the flow of
hydrocarbons from production wells. These discharges
include strainer and filter backwash water, and treated
water in excess of that required for injection.
14) Test fluids - the discharge that would occur should
hydrocarbons be located during exploratory drilling and
tested for formation pressure and content.
15) Source Water - Formation water used for water flooding
(excess may be discharged).
4. Well Treatment. Completion, and Workover Fluids
The 1985 proposal defines well treatment fluids as "those
fluids used in stimulating a hydrocarbon bearing formation or in
IV-12
-------
completing a well for oil and gas production, and drilling fluids-
used in re-working a well to increase or restore productivity."
EPA is proposing^tp change this definition of well treatment
fluids similar to the definition being proposed by one of the
EPA Regions. This definition makes a distinction between well
treatment fluids, completion fluids, and workover fluids. The
following definitions are being proposed in this rulemaking:
Well Treatment Fluids; "Any fluid used to restore or
improve productivity by chemically or physically altering
hydrocarbon-bearing strata after a well has been drilled."
These fluids move into the formation and return to the
surface as a slug with the produced water. Stimulation
fluids include substances such as acids, solvents and
propping agents.
Well Completion Fluids: "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." These fluids move into the
formation and return to the surface as a slug with the
produced water.
Workover Fluids: "Salt solutions, weighted brines,
polymers, or other specialty additives used in a producing
well to allow safe repair and maintenance or abandonment
procedures." High solids drilling fluids used during
workover operations are not considered workover fluids by
definition. Packer fluids—low solids fluids between the
packer, production string, and well casing—are considered
to be workover fluids.
IV-13
-------
The above distinctions were made in order to more correctly -
describe the fluids and their functions and also to clearly
identify these fluids as those other than drilling fluids.
Drilling muds remaining in the wellbore during logging, casing,
t
and cementing operations or during temporary abandonment of the
well are not considered completion fluids but rather are drilling
fluids.
High solids drilling fluids used during workover operations
are not considered workover fluids but rather are drilling
fluids.
Because production is defined as "operations including work
necessary to bring hydrocarbon reserves from the producing
formation beginning with the completion of each well in the
development phase," treatment, completion, and workover fluids,
as defined above, are considered part of the production phase.
If these fluids do not come back up as a discrete slug, they will
either remain in the hole, or diffuse within the well's formation
fluids and resurface as part of the produced water.
5. Produced Sand
Sand is obtained with the fluids from the formation during
the production process. This sand, termed produced sand, is
defined as "slurried particles used in hydraulic fracturing and
the accumulated formation sands and scale particles generated
during production." The sand is separated out from the produced
water, washed with either water or solvent, and is either
discharged overboard with the produced water waste stream or is
stored in 55 gallon drums and transported to shore for disposal.
In the 1979 BPT effluent limitations that were promulgated,
there wert. no limitations established for the produced sand waste
IV-14
-------
stream. The effluent limitations proposed in 1985 for the NSPS, -
BAT, and BCT levels of control all prohibited the discharge of
free oil. In the four general permits that were considered in
the development of this proposed rulemaking, the produced sand
waste stream is covered as follows:
Alaska; The general permit only covered exploratory
operations and therefore the produced sand waste stream was
not included in the permit.
California; The produced sand waste stream is covered at
the BCT level of control with a "no discharge of free oil"
requirement.
Gulf; The permit has a "no discharge of free oil"
requirement for the produced sand waste stream. Region VI
would like to expand the current definition of produced sand
to be more specific as follows:
"... sand and other solids removed from the produced
waters. Produced sand also includes desander discharge
from the produced water waste stream and blowdown of
the water phase from the produced water treating
system."
For the options considered for this proposal, the definition
of produced sand needs to be modified to include the following
sentence (as to be contained in the Gulf of Mexico coastal
general permit):
"Produced sand also includes desander discharge from the
produced water waste stream and blowdown of the water phase
from the produced water treating system."
IV-15
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6. Development Facility and Production Facility
EPA is proposing to change the definitions of deve.-opment
facility and production facility to more accurately reflect the
waste streams that occur during these phases of the industry.
Development facility is being changed to cover only the drilling
portion of the operation. Thus, the major waste streams
associated with this phase are drilling fluids and cuttings.
Production facility is being changed to include the
completion phase of the operation as well as actual hydrocarbon
extraction. The major waste stream associated with this phase is
produced waters. Miscellaneous waste streams are produced sands,
and well workover, treatment and completion fluids. Since well
workover, treatment and completion fluids resurface (if they
surface at all) along with the produced waters, EPA believes it
appropriate to associate well workover, treatment and completion
with the production phase.
These changes do not affect the regulation, or the ability
to comply with it.
7. New Sources
The exploration, development, and production of oil and gas
in offshore waters involves operations sometimes unique from
industrial operations performed on land. The definition section
of this regulation includes a definition of "new source"
appropriate for this subcategory of the oil and gas industry.
While the provision in the NPDES regulations that define new
source (40 CFR 122.2) and establish criteria for a new source
determination (40 CFR 122.29(b)) are applicable to this
subcategory, two terms, "water area" and "significant site
preparation work," are defined in this subcategory-specific new
IV-16
-------
sources definition in order to give the terms meanings relevant -
to offshore oil and gas operations. The special definitions were
proposed in 1985 and are included here also. These definitions
in this proposed rulemaking are consistent with s 122.29(b)(l)
which provides that § 122.2 and 122.29(b) shall apply "except as
otherwise provided in an applicable new source performance
standard." See 49 FR 38048 (September 26, 1984).
Before discussing the two special definitions, a brief
discussion follows on the scope of the term "new source" for the
offshore oil and gas industry. The term "new source" is
applicable to all activities covered by the offshore subcategory.
This includes mobile and/or fixed exploratory and development
drilling operations as well as production operations. Coverage
of all such offshore oil and gas operations is required by
Section 306 of the Act.
Section 306(a)(2) defines a "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 Act defines "source" to mean any "facility
. . . from which there is or may be the 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 term "source" clearly
would include all drilling rigs and platforms as well as
production platforms. The breadth of the term "construction,"
which encompasses the concept of "placement" of "equipment" at
the "premises," would include the location and commencement of
drilling or production operations at an offshore site to be
"construction" of a new source. This is a critical distinction.
Drilling rigs obviously are moved from site to site for several
years. Production platforms are built on shore and transported
to an offshore site. The appropriate reading of Section
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306(a)(5) would not make the date of building the rig or platform
determinative of whether the rig or platform was a new source,
but rather when the rig or platform was placed at the offshore
site where the drilling and production activity and discharge
*
would occur. Therefore, drilling operations that commence after
the NSPS are effective, even if performed by an existing mobile
rig, would be new sources, coming within the definition of
"constructed" by "placement" of "equipment" at the "premises."
Similarly, a mobile drilling rig which carries the drilling
equipment would be considered "placed" at the location it anchors
for drilling, which would be the "premises." The Agency
considers the drilling rig to be the "facility . . . from which
there is or may be the discharge of pollutants" within the
meaning of Section 306(a)(3). The same reasoning applies to
development drilling rigs and structures and production
structures, platforms, or equipment. The critical determination
of whether a source is a "new source" is the date of placement
and commenceirrmt of operations, not the date the source
originally was built.
The first special term that is defined in these proposed
regulations is "water area" as used in the term "site" in
s 122.29(b). The term "site" is defined in § 122.2 to include
the "water area" where a facility is "physically located" or an
activity is "conducted." For the purposes of determining the
"site" of new source offshore oil and gas operations, the Agency
is proposing to define "water area" to mean the specific
geographical location where the exploration, development, or
production activity is conducted, including the water column and
ocean floor beneath such activities. Therefore, 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
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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.
EPA considered defining "water area" as a larger body of
water, such as a lease block area. This alternative was rejected
because such an artificial distinction would allow the
commencement of many additional oil and gas activities (not
considered to be "new sources") in an area merely by virtue of
the fact that an existing activity was currently operating in the
lease block. This result is inconsistent with the definitions
and purpose of Section 306 of the Act. Under Section 306, a "new
source" means "any source" the construction of which begins after
the Agency publishes a NSPS.
The second special term for which EPA is proposing a special
definition is "significant site preparation work." As explained
above, the date of "placement" of a rig or platform is
determinative of when a source is considered to be "constructed."
The date of "placement" (i.e., "construction") may be earlier
under the provision of 40 CFR § 122.29(b)(4) which defines
construction as being commenced when "significant site
preparation work" has been done at a site. The effect of the
proposed definition for "significant site preparation work" is
important in determining what individual sources would be
considered to have "commenced construction" or commenced
"placement" prior to the publication of the NSPS and therefore
would not be considered a new source. EPA is proposing to define
this term to mean the processes 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.
Therefore, if clearing or preparation 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
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at that site would not be considered a new source. The
significance of this definition is that exploration activities at
a site prior to the effective date of the NSPS are not considered
significant site preparation work. Therefore, if only
exploratory drilling had been performed at a site, subsequent
development and production activities would not be "grandfathered
in" as existing sources at the site but rather would be
considered "new sources." The Agency does not consider
exploratory activities tr be "significant site preparation work"
because such activities are not necessarily followed by
development or production activities at a site. Even when
exploratory drilling ultimately leads to drilling and production
activities, the latter may not be commenced for months or years
after the exploratory drilling is completed. The purpose of this
provision is to allow a future source to be considered an
existing source if "significant site preparation work," thereby
evidencing an intent to establish full-scale operations at a
site, had been performed prior to NSPS becoming effective. While
a development or production platform would not be built unless an
exploratory well had been drilled, exploration wells are drilled
at vastly more sites and can precede development by months or
years.
Another provision of s, 122.29(b)(4), regarding when
construction of a new source has commenced, provides that
construction has commenced if the owner or operator has "entered
into a binding contractual obligation for the purchase of
fa \lities or equipment which are intended to be used in its
operation within a reasonable time." The Agency is not proposing
a special definition of this provision, believing it should
appropriately be a decision for the permit writer. However, the
Agency carefully has considered this provision and is providing
the following general guidance concerning th proper application
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of the provision for the special circumstances of offshore oil
and gas activities.
A common practice^ in the industry is for oil companies to
enter into long-term contracts with independent drilling
companies. These contracts may require that the drilling company
will provide its services for a specified number of wells over a
period of months or years. The exact site for the exploratory
drilling services may not be specified. The Agency believes such
contracts would appropriately fall within the provision of
s. 122.29 (b) (4) (ii) , thereby making the drilling activities under
those contracts existing sources, not new sources. Such
contracts generally do not or cannot specify the exact site for
future exploratory drilling.
The situation generally is not the same for development
drilling or production activities. Contracts for these
activities usually specify the site where activities are to be
conducted or facilities placed. Therefore, a contract that meets
the conditions of § 122.29(b)(4)(ii) for an exact site probably
would not be considered a new source. However, a general
contract for construction or use of a development or production
platform with no indication of the location where it would be
placed or used would not qualify to make a future selected site
for its use as an existing source. An opposite result would
allow companies to move an existing platform or use old platforms
at new sites in shallow water areas, thereby avoiding the NSPS
requirements. Such a result would be contrary to the purpose of
establishing NSPS.
An issue of continuing concern under the Clean Water Act has
been whether NSPS must be applied after their proposal or only
after their promulgation. Section 306(a)(1) of the Act provides
that a "new source" is a source, the construction of which
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commences after proposal of NSPS if such NSPS are promulgated in -
accordance with Section 306. Section 306(b)(l)(B) requires
promulgation within 120 days of proposal. EPA's implementing
regulations for direct^dischargers provide that a new source
means a source, the construction of which commenced either after
promulgation of standards of performance which are applicable to
such source or after proposal, but only if the standards are
promulgated within 120 days of their proposal. (Section 122.2.)
EPA does not intend that the NSPS for this subcategory shall
be effective until they are promulgated unless they are
promulgated within 120 days of proposal, in which case the
effective date would be the date of proposal.
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E. REFERENCES
1. Letter from Pete Crampton, Environmental and Energy Services
Co., to M. Kaplan^ Eastern Research Group, Inc., "Tables for
Produced Water Pollutant Removals - BAT, and Produced Water
Pollutant Removals - NSPS", August 1, 1990.
2. SAIC, Summary of Data Relating to Miscellaneous and Minor
Discharges. Revised February 1991.
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SECTION V
PRE-1985 MAJOR DATA ACQUISITION EFFORTS
A. INTRODUCTION
Several areas were identified that required further study to
support the reproposal of effluent limitations guidelines and
standards in 1985. These included an evaluation of priority
pollutant levels in produced water discharges, an evaluation of
alternative control and treatment technologies for reducing the
discharge of priority pollutants, a characterization of drilling
fluids and additives then in use, an investigation of alternative
disposal practices for drilling fluids and drill cuttings, an
assessment of the impacts of discharging drilling and production
wastes to the marine environment in general, and updated
projections on the location, size, and configuration of new
sources.
The sampling and analysis programs conducted for the 1985
rulemaking focused on toxic pollutant effluents from produced
water and drilling fluids and cuttings. However, EPA sampled and
analyzed wastes in the offshore subcategory for certain
conventional and nonconventional pollutants as well as inorganic
and organic toxic pollutants. All data gathering efforts, and
their influence on the 1985 proposal, are further described in
the EPA development document supporting that proposal (EPA 440/1-
85/0556) but are briefly described below.
B. PRODUCED WATER
The Agency's initial effort to investigate priority
pollutants in produced water consisted of a preliminary screening
survey conducted at six production platforms in the Gulf of
Mexico during 1980. Results obtained by using the standard
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procedures being proposed by EPA at that time indicated the
presence of toxic organics and metals. The results were
questioned by industry, because the analytical methods used had
not been validated for^water with high dissolved salt content—
t
common for produced waters.
Representatives of the Offshore Operators Committee (OOC),
the American Petroleum Institute, and EPA cooperated in a joint
effort in 1981 to develop analytical protocols to measure toxic
pollutants in produced water.
During the first phase of a two-phase analytical program,
produced water samples were collected at two production platforms
in the Gulf of Mexico and sent to ten Agency and industry
laboratories for comparative testing. Final analytical protocols
were established employing standards purged from 10% sodium
chloride brines, isotope dilution gas chromatography/mass
spectrometry (GCMS) for analysis of volatile organic pollutants,
continuous and/or acid/neutral extraction and fused silica
capillary column isotope dilution GCMS for analysis of
semivolatile organic pollutants, and standard addition flame
atomic absorption for metals analysis.
The second phase of the analytical program was conducted
with the use of established protocols to confirm the presence and
quantify the concentrations of toxic pollutants in produced water
discharges at 30 production facilities in the Gulf of Mexico.
Selected conventional and nonconventional parameters were also
investigated. Samples were taken of influents to and effluents
from produced water treatment systems during visits that ranged
from 1 to 3 days at. individual sites. Strict adherence to
specified collection and quality assurance procedures was
maintained throughout the program. Additional samples were
collected for independent analyses sponsored by the OOC.
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Priority pollutant sampling efforts also had been conducted
at Alaska and California sites. Produced water samples were
collected from both offshore and onshore treatment facilities at
Cook Inlet and Prudhoe Bay in Alaska and from three offshore
production platforms in California's Santa Barbara Channel. Data
obtained from this study are presented in the 1985 development
document.
C. DRILLING FLUIDS
Another program was initiated by the Agency for the 1985
rulemaking to evaluate the characteristics of water-based
drilling fluids. One objective of this program was to examine
the test procedures that were being proposed as analytical
methods applicable to this industrial subcategory for measuring
acute toxicity and for detecting the presence of diesel oil in
mud discharges. A second objective was to evaluate test results
derived from these and other Agency-approved analytical
procedures in the development of effluent limitations guidelines
and standards.
The first phase of this program involved the selection and
specification of test muds. The Agency's intent was to select a
group of the more commonly used water-based mud formulations for
testing purposes. In doing so, the Agency relied on information
gathered during the development of NPDES permits issued in 1978
to operators drilling on leases in the Atlantic Ocean. During
that effort, eight basic mud types were defined by the OOC.
These eight generic mud types were selected to encompass
virtually all water-based muds, exclusive of specialty additives,
used on the Outer Continental Shelf. The eight mud types are
listed later in this document in Section VII.
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Laboratory-prepared muds, based on these eight generic fluid.
formulations, were sent to EPA laboratories for chemical,
physical, and biological testing. Toxicity tests were conducted
at EPA's Environmental^Research Laboratories using the standard
bioassay procedure being proposed with this rulemaking. Analyses
for oil content, biochemical oxygen demand, chemical oxygen
demand, total organic carbon, and priority pollutants (excluding
pesticides) also were performed at EPA contract laboratories.
D. DRILL CUTTINGS
The discharge of oil and other mud constituents that adhere
to or are mixed with waste cuttings is the primary concern in the
drill cuttings waste stream. The data gathered on the quality of
mud compositions were used to assess the expected effects of the
discharge of contaminated drill cuttings to the ocean. In
addition, information was obtained from suppliers of various
types of cuttings washer systems on projected washer performance
and treatment costs. Selected samples of oil -contaminated drill
cuttings before and after washing were obtained for screening
purposes and tested for the same conventional, nonconventional,
and some priority pollutant parameters that were investigated
during the drilling fluids program.
E. OTHER WASTE STREAMS
The Agency did not perform any new sampling or analytical
programs for deck drainage, sanitary, domestic, produced sand,
and well treatment fluids waste streams for the 1985 proposal.
The proposed NSPS, BAT, and BCT regulations for these waste
streams were based upon information collected during the
development of the existing BPT regulations. Effluent
limitations and standards for certain toxic, conventional, and
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nonconventional pollutants were reserved from these waste streams-
pending additional data collection by the Agency.
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SECTION VI
DATA/INFORMATION GATHERING - POST 1985
A. INTRODUCTION
Subsequent to the 1985 proposal of the offshore oil and gas
effluent limitations, EPA acquired additional information on oil
and gas effluents and their treatment technologies. Such
information has been obtained by way of public comments,
industrial data, and EPA-sponsored studies. Much of this
information was discussed in a Federal Register Notice of
Availability of Additional Information (53 FR 41356) in October
1988. Additional information also has been obtained since the
notice was published. All studies that were performed for the
purpose of investigating offshore oil and gas effluents and
treatment technologies, and which have bearing on the standards
being proposed and reproposed in this document, are summarized
below.
B. PRODUCED WATER
1. Performance of Granular Media and Membrane Filtration
Technologies on Produced Waters
A treatment technology under consideration for the produced
water waste stream for BAT, NSPS, and BCT effluent limitations
guidelines is filtration. To assess the levels of pollutants in
produced water filtration effluents and the efficiency of
granular media filtration for reducing pollutants in produced
water, a "three facility study" was conducted by the Agency in
the summer of 1989.1>2'3 In addition, data were received on the
performance of membrane filtration from an equipment vendor.4
Three facilities were sampled in the granular media
filtration study. One was located onshore in New Mexico, one was
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a gravel island off the California coast, and one was in the bay -
of Long Beach, California. Even though one of these three
structures was located onshore, the efficiency of granular media
filters is not dependent upon the structure's location. While
all of the structures reinject the produced water after
filtering, each company is unique in its handling of produced
waters prior to filtration. For example, "fresh" makeup water
was combined with the produced water along with a polymer prior
to the filtration unit at the New Mexico facility. After
oil/water separation, produced waters from the three structures
at the Long Beach facility were combined before entering the
multimedia granular filtration unit. At the gravel island
facility, an "ultrahigh" rate filtration unit was utilized and a
polymer was added to the produced water prior to entering the
filtration unit.
Influent and effluent produced waters into each company's
filtration unit were analyzed. At the two California facilities,
the filtration influent waters were the effluent waters from gas
flotation units (BPT technology basis). The New Mexico facility
did not use gas flotation. Statistical analyses of data from the
"three facility study" were conducted to assess detection rates
of organic and metallic pollutants and to estimate platform
specific variability factor? for pollutants detected in both gas
flotation and filtration ef.. aent produced waters. A summary of
these results is included in Section IX. This technology
demonstrates a 40-60% removal of oil and grease, from levels
approximately at the BPT level of 25 mg/L, to 11.3 mg/L for the
two facilities using polymer addition.
EPA attempted to collect samples of miscellaneous wastes
durinr this study also. One produced sand sample was collected.
Two OL. che facilities did not generate sands during the study;
the third facility generated only enough sand for analysis of one
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parameter—oil content. These data are presented in Section VII~
Deck drainage was sampled at two of the facilities and these data
are presented in Section VII. Treatment fluids were sampled at
one facility and these"data also are presented in Section VII.
The three facility study also included a comparison of oil
and grease analytical methods (see Section VI.H).
In addition to the three facility study, EPA has acquired
information on a new filtration technology called membrane (or
ceramic) filtration. A vendor of membrane filtration equipment
has supplied the Agency with data from a full scale membrane
separation unit that is operating in the Gulf of Mexico and
several pilot scale evaluations at facilities in offshore,
coastal, and onshore locations. Test results from the full-scale
operation indicate that regardless of the values of TSS and oil
and grease in the influent, effluent values of less than 5 mg/L
of oil and grease readily can be attained. In addition, this
technology shows potential for more efficient removals of soluble
oil and grease (organics) than the BPT technology and granular
media filtration technology. Data are presented in Section IX.
2. An Evaluation of Technical Exceptions for Brine
Rein-iection for the Offshore Oil and Gas Industry5
The purpose of this report was to make an assessment of
conditions along the U.S. coast to determine if there are any
technical factors which would preclude injection of brine
produced by offshore oil and gas operations as a form of
pollution control. Data on the geology of the Atlantic, Gulf and
Pacific Coasts were collected from published sources and direct
communications with U.S. Geological Survey personnel actively
investigating those areas. Those areas were evaluated for their
sedimentological and tectonic history to determine if suitable
formations and conditions are available for disposal operations.
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Information was also collected from onshore brine disposal
operations, disposal regulations in oil producing coastal states,
and reinjection operational procedures. All data and information
were evaluated to determine what effect, if any, they may have on
a zero discharge requirement for offshore oil and gas operations.
All data used in this report were obtained from publicly
•
available published sources and state and federal agencies.
State and federal regulatory agencies in the oil producing states
were contacted to obtain information on disposal operations
practiced in their respective areas of responsibility.
The report included the following findings:
In general, brine reinjection as a form of pollution
control is technically feasible in all coastal and
offshore areas of the United States. The geology of
those areas indicates the presence of formations with
properties that make them suitable for disposal
reservoirs. However, some areas along the Pacific
coast are under stress and geologically active. Those
areas will be rather site specific and reinjection will
require careful evaluation before making a final
decision.
Most decisions to reinject or not reinject formation
fluids are based more on economic considerations than
on technical reasons. California oil and gas operators
actively re.inject because the oil is very viscous and
waterflooding is necessary to obtain maximum recovery*
The capital investment in equipment thus has a definite
financial return. In other coastal areas, oil
viscosity is not a major problem and reinjection into
producing formations may cause loss of production.
Reinjection in those areas would be specifically for
disposal in non-producing formations.
Technical exceptions from reinjection may be necessary
for some limited and special situations. Potential
reasons for considering a technical exception are:
possible contamination of underground sources of
drinking water, potential seismic activity in areas of
known active faults, solution of in situ salt
formations, and areas where the geology is not detailed
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enough to make a reasonable determination as to where ,
injected water may eventually migrate.
3. Radioactivity of Produced Water
• <
There has been much concern over the presence and
levels of Radium-226 (Ra226) and Radium-228 (Ra228) in the produced
water waste stream from oil and gas facilities. Both Ra226 and
Ra228 are naturally occurring radioactive isotopes with half-lives
of 1620 years and 5.7 years, respectively. Uranium and thorium
(present in deep geologic formations) undergo a decay series
whereby radium is the first element in the decay series that is
water soluble. The level of radium present in the formation water
- which ultimately becomes the produced water - has been found to
be directly proportional to the salinity of the formation water.
There has been some evidence to indicate that the radium-salinity
relationship may vary depending on the source of the produced
water, e.g., wells producing oil only or wells producing gas
only.
There have been studies performed which have given
preliminary information on the levels of radium in produced
water. The results of such studies indicate that radium levels
in the saline produced waters from the Gulf Coast region exceed
proposed and existing radium discharge limits for other
industries. For example, drinking water standards have set a
limit of 5 pCi/L while discharges from nuclear power plants are
limited by the Nuclear Regulatory Commission to 30 pCi/L of Ra226
into unrestricted waters. Average open ocean surface waters
contain 0.05 pCi/L of Ra226 while coastal waters generally do not
contain natural levels of Ra226 much higher than 1 pCi/L.
In late 1986, the American Petroleum Institute initiated a
nationwide program to gather information on naturally occurring
radioactive materials.6 This program involved voluntary sampling
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and analysis by oil and gas companies throughout the country.
Specific sampling and analytical protocols were distributed to
all the interested companies to ensure consistency of
methodology. Companies-were requested to perform radioactivity
measurement for service equipment. Companies'from twenty of the
major oil and gas production states participated, and a large
volume of data were accumulated. The data were summarized in a
final reported from API entitled, "A National Survey on Naturally
Occurring Radioactive Materials (NORM) in Petroleum Producing and
Gas processing Facilities" dated July 1, 1989. The report
indicates that NORM activity levels showed wide variability, both
geographically and among items of equipment in the same
geographic area. Although the data were not developed from a
statistical plan, some trend can be derived because of the large
number of participants and observations received (over 36,000).
The geographic areas with the highest equipment readings for
radioactivity are the entire Gulf Coast crescent (Florida
panhandle to Brownsville, Texas), the northeast Texas crescent,
southeast Illinois, and a few counties in southern Kansas. Gas
processing facilities having the highest levels are reflux pumps,
propane pumps and tanks, other pumps, and product lines. Water
handling equipment in the production facilities category exhibits
the greatest NORM activity levels.
Some findings of various other studies are reported below:
Battelle completed a study for the American Petroleum
Institute in August, 1988 on the fate and effects of
produced water discharges from four facilities in Louisiana
coastal waters (three of which are covered by the offshore
subcategory) .7 The levels of Ra226 and Ra228 combined were
found to range anywhere from 605 to 1,215 pCi/L.
Kramer and Reid in a 1984 document, "The Occurrence and
Behavior of Radium in Saline Formation Water of the U.S.
Gulf Coast Region," reported measured amounts of total
radium which ranged from less than 0.2 pCi/L in a produced
water sample from a gas well in McAllen, TX to 13,808 pCi/L
in a produced water sample in Vermillion Parish, LA.8
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In the Leeville oil field in LaFourche Parish, LA, the
produced waters were sampled and analyzed for Ra levels
over a five year period. The levels of Ra226 varied from 16
pCi/L to 397 pCi/L. Assuming that the average level in the
produced water was about 280 pCi/L, over the five year
sampling period, up to 1.76 curies of Ra226 were discharged
into surface waters with the produced water. (One picocurie
- 1 x 10"12 curies.)'
When elevated levels of up to 2800 pCi/L were discovered in
the produced water discharges in Louisiana, the Louisiana
Department of Environmental Quality (DEQ) issued an emergency
rule which went into effect on February 20, 1989. This rule
required a radioactivity measurement, acute toxicity test and
chronic toxicity test to be performed on all existing produced
water discharges that flow into the surface waters of the state
(this includes offshore structures located in state waters). The
results of the radioactivity analysis with the average daily
discharge rates were due back to DEQ by August 20, 1989 while the
results of the toxicity analyses were due back by February
20,1990.
The Louisiana DEQ has completed a preliminary analysis of
the data received as a part of the sampling under the emergency
rule. There were submissions of data from 450 sites discharging
produced water into the surface waters of the state. The
analyses for Ra226 and Ra228 were performed using the EPA Standard
Method for drinking water. The results indicate that Ra226 and
Ra228 are primarily found in the soluble phase and that one-third
to one-half of the sites had levels of over 300 pCi/L. The
maximum values were 930 pCi/L of Ra226 and 928 pCi/L of Ra228 while
the overall average values were 158 pCi/L of Ra226 and 164 pCi/L
of Ra228. The long term plan of the Louisiana DEQ is to use this
data to prohibit discharges of produced water into saline surface
waters (discharges into fresh water are already prohibited). The
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Louisiana DEQ will be providing this data to the Agency for a
separate analysis.
As a part of the^three facility filtration study" conducted
by the Agency in the summer of 1989, samples'of the produced
water waste stream were analyzed at different locations in the
treatment system for Ra226 and Ra228. Assessment of the raw data
•
show effluent values after filtration of the produced water
ranging from 10.6 to 213 pCi/L Ra226 and 0 to -~8 pCi/L Ra228.
C. DRILLING FLUIDS AND DRILL CUTTINGS OPERATIONS
1. American Petroleum Institute Drilling Fluids Survey10
In 1984 the American Petroleum Institute (API) conducted a
survey among sixteen offshore oil operators in the Gulf of Mexico
to obtain information on the use of diesel and mineral oils in
water-based drilling fluids for the year 1983. Because the
number of mineral oil applications in 1983 was small, API
conducted a limited additional survey to obtain more data on
experience with mineral oil pills in 1984.
These survey data presented by API indicate that mineral oil
is more commonly used as a lubricant, while diesel oil is more
commonly used for spotting purposes. Hydrocarbons (diesel or
mineral oil) v -e added for lubricity in 12% of the wells
included in t survey (548). Mineral oil and diesel oil were
used in 8% and 4% of the wells, respectively. For those drilling
muds to which lubricity hydrocarbon was added, typically 3% (by
volume) jf the mud formulation was composed of hyd? carbon
additive.
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2. Offshore Operators Committee Spotting Fluid Survey11
Most industry representatives consider mineral oil to be
adequate for use as a^lubricity agent but believe diesel oil to
be a superior material for freeing stuck pipe. In support of
this position, industry provided the Agency with the results of a
retrospective survey comparing the success rates of diesel oil
and mineral oil in freeing stuck pipe. This project was
conducted in 1986 by the Offshore Operator's Committee (OOC) and
covered the years 1983 to 1986.
The study examined information from 2,287 wells drilled in
the Gulf of Mexico during that time period. Survey forms were
distributed to operators who were asked to specify the number of
wells drilled with water-based mud for each year covered by the
survey and to supply certain information on each stuck pipe event
where an oil-based spotting fluid was used. The API survey form
asked for the date the event took place, the time interval
between sticking and spotting activities, the depth at which the
stuck pipe incident occurred, the based oil used in the spotting
fluid, whether the hole was straight or directional, and whether
the pill was successful in freeing the pipe.
Participants included twelve major oil companies and
accounted for more than half of the offshore wells drilled during
this period. Since some of these companies have more than one
operating division, a total of sixteen survey responses were
received.
Of 2,287 wells surveyed that were drilled with water-based
mud, 506 stuck pipe incidents were identified in which the
operator chose to use an oil additive to attempt to free stuck
pipe. Diesel oil pills were reportedly successful 52.7% of the
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time and mineral oil pills were successful 32.7% of the time in
freeing stuck pipe, as shown in the following table:
DOC SPOTTING FLUID SURVEY RESULTS
Number of Number of Success
Incidents Incidents Rate
Spotting Fluid Fluid Used pipe Freed (percent)
Diesel 298 157 52.7
Mineral 208 68 32.7
Numerous other factors could impact the success of a pill in
addition to the base oil. For example, Love (1983) determined
that the chance of freeing SA ck pipe in 113 documented cases and
the potential success of sue. operations were related to specific
conditions at each well. Success decreased with increasing well
angle, mud weight, amount of open hole, API fluid loss of the
mud, and bottom-hole-assembly length. The chances of success
dropped off substantially when a numeric index calculated from
the above factors exceeded a certain level.
In addition to the above factors, Love found that pill
additive packages (e.g., surfactants, emulsifiers, etc.),
rheological properties of the mud, time until spotting, site-
specific geological characteristics, and operator experience were
likely to affect the success of a spotting operation.
The OOC examined four of these factors in their study: base
oil, time until spotting, depth of spot, and type of well
(straight or deviated). Results indicated that reducing the
length of time until the spot was applied improved the chance of
success dramatically for diesel pills. A similar but apparently
less dramatic trend was observed for mineral oil pills. The
diesel oil success rate was 61% if the pill was spotted in less
than 5 hours. The rate dropped to 41% if the time until spot
exceeded 10 hours. The mineral oil success rate was 35% if the
Vl-10
-------
pill was spotted in less than 5 hours; the rate dropped to 31% if.
the tine until the spot exceeded 10 hours.
• . '
Other factors examined by OOC appeared to have less impact
on success for freeing stuck drill pipe. Both diesel and mineral
oil showed higher success rates in straight rather than in
directional or deviated wells, with diesel oil maintaining its
reported edge over mineral oil by about the same percentage in
each type of well. No trend was observed between depth of spot
and success rates for diesel or mineral oil pills.
The OOC survey data showed that success rate with mineral
oil pills varied considerably among operators. The data seemed
to indicate that greater experience with mineral oil usage leads
to considerably higher success rates than the reported average.
The five operators that reported using mineral oil pills for more
than 90% of their stuck pipe incidents experienced an average 42%
success rate with such pills.
Some of the operators with greater mineral pill usage rates
achieved extremely high success rates, which were comparable to
the highest diesel pill success rates. The three highest success
rates among operators using mineral pills were 50%, 60%, and 75%.
The three highest success rates among operators using diesel
pills were 60%, 60%, and 64%.
Despite the industry's claim that diesel pills are more
effective than mineral pills, the study did show that mineral oil
was used by operators in 41% of the stuck pipe incidents. Of the
506 incidents in the OOC study, 298 (or 59%) were treated with a
diesel pill, while 208 (41%) were treated with a mineral pill.
For some operators, mineral oil was the material of choice.
Three operators (out of 16) used mineral pills exclusively. The
Agency concludes that during the period of this study: 1)
VI-11
-------
mineral oil was in common use by operators in the Gulf of Mexico;.
2) mineral oil is an available alternative to the use of diesel
oil; and 3) success rates comparable to those with diesel oil can
be achieved with mineral oil.
*
3. The EPA/API Diesel Pill Monitoring Program12
The objective of the Diesel Pill Monitoring Program (DPMP)
was twofold: 1) to evaluate the efficiency of diesel recovery
practices after a diesel pill had been spotted to free stuck
pipe, and 2) to determine the effectiveness of the recovery
practice by measuring the toxicity and diesel content of the mud
system before and after pill recovery.
Differential pressure sticking is a major drilling problem.
If the pipe cannot be mechanically jarred free, the most common
remedy is to spot a pill. This entails pumping a certain volume
or "pill" of oil-based mud down the drill string and up the
annulus to the point where the pipe is stuck so that the oil mud
remains in contact with the filter cake. The oil weakens the
bond between the pipe and filter cake, and after a few hours the
pipe may be pulled free. After the pipe is free, the oil mud
pill and some of the oil contaminated mud surrounding it can be
removed from the mud system and set aside for disposal.
With current pill recovery techniques, some residual oil
will remain in the mud system and, under the 1985 proposed
regulation, discharges of diesel oil are not allowed. Industry
requested that the discharge of diesel oil be allowed when using
the diesel pill technique. Since neither the industry nor the
Agency had sufficient information on the effectiveness of pill
recovery, the Agency decided to participate with industry in a
test program to determine whether diesel oil can be effectively
removed from a mud system after use of diesel-based pills.
VI-12
-------
The DPMP was a joint effort among EPA's Industrial
Technology Division, EPA Regions IV and VI, EPA's Environmental
Research Laboratory iri^Gulf Breeze, FL, and the American
Petroleum Institute (API).
The program was implemented as part of EPA Region IV and
VI's General NPDES Permit for Oil and Gas Operations in the Gulf
of Mexico (U.S. EPA Permit No. GMG 280000, 1986) that became
effective on July 2, 1986. The permit required an operator, who
used a diesel pill and intended to discharge the drilling muds,
to recover the diesel pill plus at least 50 barrels of mud that
surfaced from downhole both before and after the pill, or as much
as necessary until no visible oil was detected. The recovered
pill and buffer material could not be discharged and had to be
transported to shore for either disposal or reuse. The federal
waters of the Gulf of Mexico were chosen for this study because
of the large number and diversity of drilling operations.
The participating drilling operators were required to
conduct sampling activities with prepackaged sampling kits
whenever a diesel pill was used to free stuck pipe. Samples were
taken of the pill, the diesel oil used to formulate the pill, and
the active mud systems before spotting and after the pill was
recovered. Compliance with the permit's end-of-well toxicity
limitation was demonstrated by analyzing the mud samples taken
just prior to the introduction of the pill.
The mud and pill samples were tested by standard API RP 13B
procedures for rheology, pH, and oil and water content by 10 ml
retort. Diesel was determined by gas chromatography (GC) using a
method described in the DPMP Program Manual. (The diesel method
currently is under review by EPA and industry. It has been
proposed by the Agency as part of the effluent limitations
VI-13
-------
guidelines for U.S. offshore oil and gas operations.) The
drilling fluid ioassay tests were conducted according to EPA*s
proposed Drill, j Fluids Toxicity Test (50 FR 34592, August 26,
1985). In this test,"acute toxicity is determined on the
suspended particulate phase by exposure of Mysidopsis bahia to
the phase for 96 hours.
EPA collected additional data on the levels of priority
pollutant organics, metals, and conventional pollutants in some
sampled muds.
During the period that the DPMP was in effect, 105 sampling
kits were submitted to the program, representing 105 pills
spotted in 56 wells. Three sets of dat,. evolved from this
program. Dataset 1 was used for examining relationships between
diesel concentration and toxicity and between methods used to
measure total oil content and diesel ntent. Dataset 2 was used
in calculating success rates for free-rig stuck pipe. Dataset 3
was used in correlations with diesel recovery levels.
Diesel oil recovery was determined from the difference
between the amount of diesel oil added to the mud system and the
amount of diesel oil remaining in the active system after two
complete circulations of the mud system following pill recovery.
As shown in Table VI-1, diesel recovery varies with extra buffer
(volume mud hauled (bbl) - pill volume (bbl) - 100). For the
overall program (based on Dataset 3), diesel recovery ranged from
4.2% to 100%. The mean recovery level was 76.5% while the median
recovery level was 83%. Increasing buffer size had little or no
effect on the mean, median, or maximum recoveries. On the other
hand, increasing the buffer volume appeared to increase the
minimum recovery level (from 32.1% to 72.9% over the entire extra
buffer interval).
VI-14
-------
TABLE VI-1
PERCENT DIESEL RECOVERED VS QUANTITY OF
EXTRA BUFFER* HAULED ASHORE FOR DISPOSAL: DATASET 3
% Percent Diesel Recovered
Extra Buffer
(BBLS)
0
03 00
Number of
Incidents
11
18
10
13
6
58
Mean
73.4
75.0
78.0
77.3
82.8
76.5
Median
77.1
87.8
83.9
82.3
79.5
83.0
Minimum
32.1
4.2
44.1
24.0**
72.9
4.2
Maximum
96.0
100.0
96.2
97.9
98.0
100.0
* Volume of extra buffer hauled ashore is equal to:
VOLUME HAULED - VOLUME SPOTTED _ 100
**Next lowest value is 61.4.
VI-15
-------
Figure VI-1 shows how mud toxicity depends on diesel
content. At low diesel concentrations, mud LC50 values decrease
rapidly with increasing diesel content. At higher diesel
concentrations, mud LC^0 values decrease less rapidly. Note that
while most of the LC50s of the muds sampled before spotting are
higher than those sampled after spotting (the median LC50 values
of the mud before and mud after samples were 52,000 ppm and 6,000
ppm respectively), some are not. The mud before samples with low
LCSO values represent muds which already contained diesel (or
mineral oil). In most cases, these mud samples were obtained
before spotting a second or third pill, after one or two pills
had already been spotted. Thus, mud toxicity is observed to be a
strong function of diesel content, especially at low diesel
concentrations.
The correlation exhibited between diesel and total oil
content was relatively tight (R2=0.89). More variation existed
at low diesel levels.
Water-based muds may be broadly classified as either clay
muds (those that depend on clay for viscosity) or polymer muds
(those that depend on a polymer for viscosity). To examine the
effect of diesel on the toxicity of different mud types, the DPMP
muds were classified as such. Figure IV-2 shows the mean LCsos
of the two basic mud types as a function of approximate diesel
content. Note that at very low diesel concentrations the mean
LC50 values for both basic mud types are greater than 400,000
ppm. Mean LC50s for both mud types decrease in essentially the
same way with increasing diesel content. Figure IV-3 presents
the range of LC30 values obtained for each basic mud type as a
function of diesel concentration. Note that at each diesel
concentration interval, the range of LC30 values for each mud
type greatly exceeds the difference in the mean values. Thus, it
VI-16
-------
1000000
100000 -*
-------
1000000
00
100000
96 HOUR
LC50
(ppmSPP) 1000Q
1000
-E
I
••••*•
I
*
!
i
M
W///////////M
i
i
\
I I I I II
i
•
mmmt
k i
«.OS .05-.15 .15-.35 .35-.7S .75-1.251.25-1.751.75-3.5 >3.5
DIESEL OIL CONCENTRATION (WEIGHTS)
MUD TYPE
D CLAY MUD H POLYMER MUD
FIGURE VI-2
-------
1000000
100000 -
96 HOUR
3 LC50 10000
i (ppmSPP)
1000 H
100
—
II
••
tm
I
1
-
I
-
1
-
I
-
I
/
••
••
I I I III I I
<.05 .05-.15 .15-.35 .3 5 -.7 5 .75-1.251.25*1.751.75-3.5 >3.5
DIESEL OIL CONCENTRATION (WEIGHT*)
Q CLAY MUD El POLYMER MUD
FIGURE VI-3
-------
appears that diesel content is much more important than mud type .
in determining mud toxicity.
Figure IV-4 shows^the percentage of mud samples, taken after
recovering the first pill, with LC50s greater than a given value
(Dataset 3 was used in this analysis). For example, based on
this dataset, about 39% of the samples had LC50s greater than
•
10,000 ppm, and 87% of the samples had LC50s greater than 1,000
ppm.
The overall rate of success for freeing stuck pipe was 40.0%
using Dataset 2 (first pill per sticking incident). This
determination is based on 28 successes in 70 incidents, six of
the incidents involved stuck casing rather than stuck drill pipe.
The casing was not successfully freed in any of these incidents.
The success rate for freeing stuck drill pipe was 43.8% (28
successes in 64 incidents).
Good practice involves spotting a pill equal in density to
the mud density for well control and to prevent gravity migration
of the pill away from the interval where the drill pipe is stuck.
Generally, the pill density was closely matched to the mud
density for each of the sticking incidents in this program.
To examine the effect of density on success rate, the
incidents in Data set 2 was divided into two groups based on pill
density. Approximately half of the incidents were in the group
with pill densities less than 12.0 ppg and the other half were in
the greater than 12.0 ppg group. Figure IV-5 shows that success
rate is related to pill (and therefore mud) density. The success
rate for those cases where the pill density was less than 12 ppg
was 62.5%, while the success rate for those cases where the pill
density exceeded 12 ppg was only 21%.
VI-20
-------
100
80-
PERCENT 60
< OF MUD
iSAMPLES 40
20-
100
1000 10000 100000
96 HOUR LC50 (ppm SPP)
1000000
FIGURE VI-4
-------
80-
70-
60 -
50-
SUGCESS ._
<3 • -.,.. All —
^ (y\ "**
" 30-
20-
10-
n _
^
>
62.5%
^^^^jr^
7
n=32
/
21.05%
z /
n=38 / /
6.9 < ppg g 12 ppg > 12
PILL DENSITY (Ibs/gal)
FIGURE VI-5
-------
Based on analyses to date of information generated during
the DPMP, the Agency believes that use of the pill recovery
techniques implemented during this program does not result in
recovery of sufficient"-amounts of the diesel pill and reduction
of mud toxicity to acceptable levels for discharge of bulk mud
systems. Mud systems for approximately one-half of all wells in
the DPMP contained residual diesel levels between 1% and 5% by
weight after introduction of a diesel pill and subsequent pill
recovery efforts. In addition, mud systems for approximately 80%
of the DPMP wells failed the proposed 30,000 ppm LC50 limitation
after pill recovery. Almost half of that number (40% of the
total) of the DPMP wells had water-based mud systems that
contained residual diesel following pill recovery and showed LC50
values of less than (more toxic than) 5,000 ppm.
4. API-USEPA Database"
In 1990 a data collection effort was completed which
contains data pertaining to the metals content in barite,
drilling muds, drill cuttings, and in the surrounding sediments.
This data base is termed the "API-USEPA Metals Database". EPA
used this data base to investigate the appropriateness of the
mercury and cadmium limitations as discussed in later sections of
this development document.
A total of 24 data sets were compiled and compared where
appropriate. Data from EPA-sponsored studies, industry-sponsored
studies, and EPA regional sampling programs are all a part of
this data base.
D. MISCELLANEOUS AND MINOR DISCHARGES
Previous data collections relating to miscellaneous and
minor waste streams have been sporadic in the numerous studies of
VI-23
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offshore oil and gas discharges. EPA therefore conducted a study-
to review the available information relating to minor wastes and
summarize the characteristics, handling practices, treatment
technologies and costs^for each type of waste.14 Minor waste
streams investigated include all point sources originating from
offshore oil and/or gas drilling rigs or production platforms
other than produced water, drill cuttings, or drilling fluids.
Information was compiled from the following sources:
- The offshore, coastal, and onshore rulemaking record
- The 1985 Proposed Development Document for the offshore
segment of the oil and gas extraction point source
category
- Telephone conversations with Region VI, IX, and X
personnel
- Various discharge monitoring reports submitted to Region X
on behalf of dischargers in Cook Inlet, Alaska
- DMR reports for Regions VI, IX, and X
- Various EPA and API reports/publications
The information for the miscellaneous and minor discharges is
sporadic in most cases. Data obtained from this report are
discussed in Section VII.
E. TREATMENT/DISPOSAL TECHNOLOGIES FOR DRILLING FLUIDS AND
DRILL CUTTINGS
1. Offshore and Coastal Oil and Gas Extraction Industry
Study of Onshore Disposal Facilities for Drilling
Fluids and Drill Cuttings Located in the Proximity of
the Gulf of Mexico"
EPA's contractor conducted a survey of onshore waste
disposal facilities for disposal of drilling fluids and drill
VI-24
-------
cuttings generated at offshore oil drilling operations. The
survey covers disposal facilities located in California,
Louisiana, and Texas. The focus of the survey was to:
Investigate waste treatment methods available for
treating drilling fluids and drill cuttings to render
them acceptable for disposal
Investigate waste disposal'facilities used for drilling
fluids and drill cuttings such a landfill, land
treatment, deep well injection, etc.
Determine the available capacity of the waste disposal
facilities surveyed and estimate the total required
capacity for the disposal of drilling fluids and drill
cuttings from offshore drilling operations
Estimate waste treatment and disposal costs
Information regarding the form of waste treatment used and
the method of waste disposal was obtained from 16 operating
companies with disposal facilities in California, Louisiana, and
Texas.
A variety of treatment/disposal systems were employed by the
companies ranging from disposal of contaminated drilling fluids
without treatment and treatment of fluids prior to disposal, to
treatment of the fluids and transferral of the treated material
to another facility for final disposal. Companies providing
waste disposal facilities utilize various methods of disposal
including landfill, land treatment, deep well injection, and mud
reclamation. The number of companies utilizing each of the
various methods is summarized as follows:
VI-25
-------
Number of Waste Treatment or
Companies Disposal Method
7 Landfill
2 Land treatment (landfarm)
1 Mud reclamation
1 Deep well injection only (landfill
permit applied for
5 Waste treatment
- Gravity settlers, electroflotation
- Evaporation using hot oil system
- Drying/incineration
- Thermal oxidation
- Incineration
The typical waste handling method employed for land disposal
of drilling muds and cuttings is stabilization (i.e.,
solidification and fixation) of the mud with kiln dust or fly ash
and then landfilling. Solidification techniques consist of
adding chemicals to the mud which react to form a solid material
which can be disposed of. The equipment consists of a specially
designed blender to mix the drilling fluid and chemicals and to
pump the slurry into the proposed areas for solidification. Six
of the facilities considered use this method of disposal. The
advantage of treatment prior to disposal is that the treated
product can be transported and disposed of more readily and at a
lower cost.
One facility disposes of the waste in lined impoundments.
When the spent drilling waste arrives at this facility, it is
classified either as solid or liquid, and disposed of
accordingly. Solid and liquid wastes are placed in different
lined impoundments.
One facility handles only bulk or drum solids. The waste
must have under 5% hydrocarbons present. All solids are placed
in lined pits.
VI-26
-------
Two of the facilities dispose of drilling muds and cuttings *
by land farming. At one of these facilities, rainwater is
collected with leachate and injected in a saltwater disposal
well. "~*
One company included in the survey is a supplier of muds to
the industry, and they reclaim muds for reuse using the same
method and equipment as is used on platforms and rigs. Credit is
given to the companies supplying the spent mud against future
purchases.
Although the companies with waste disposal facilities
included in this survey predominantly use stabilization of muds
followed by landfill, another waste handling method available for
drilling muds and cuttings is the use of deep well injection for
the liquid phase of drilling muds and landfill or land treatment
for the solid phase of muds and cuttings. Due to the solid
contents of the drilling muds, a centrifuge must be used to
separate the solids from the fluids prior to injection.
The usual methods of transportation from the drilling site
to the licensed disposal facilities are as follows: Supply boats
or barges are used for oil and mud slurries and liquids; dump
trucks are used to provide land transport of drill cuttings or
wastes which can be classified as being in a dry condition.
This study also sought to determine the feasibility of
onshore disposal of drilling fluids and cuttings from the
perspective of land availability. Several steps were performed
to make this estimate. Industry activities were estimated to the
year 1995. The total volume of material to be disposed of was
estimated. The total acreage necessary to support disposal of
this material was estimated. This amount (total required
acreage) was compared with an assessment of actual land
VI-27
-------
availability for this purpose. The study concluded that there
will be sufficient disposal volume through 1995 should use of
this method increase.
The companies were also asked to supply information on the
costs of disposal. Reported costs for landfilling after
solidification of the drilling muds range from $33 per barrel to
$110 per barrel.
At the waste disposal facility, where solids and liquids
were disposed of by placing them in separate impoundments, the
costs of disposal were quoted as $35 per ton for non-hazardous
liquids and $65 per ton for non-hazardous solids, and $60 per ton
for hazardous liquids and $80 per ton for hazardous solids.
Costs for waste treatment were quoted by two of the five
companies providing processes for treating waste drill fluids.
The cost of rendering these wastes acceptable for disposal using
centrifuging, gravity settling, and electroflotation was reported
as being $7.50 per barrel for waste containing up to 10% oil and
$9.75 per barrel for wastes containing over 10% oil. The cost of
rendering drilling waste fluids acceptable for disposal using the
combined drying and incineration process was reported to be in
the range of $15 to $18 per barrel.
Costs were not available for the treatment of drilling
wastes by the other three waste treatment processes covered in
the survey.
The companies contacted in the survey provided only very
limited information on transportation costs for drilling wastes.
Costs were either not available or were on a case-by-case basis,
dependent on location and distance to be moved. Disposal costs
were usually quoted on received-at-site basis.
VI-28
-------
2. Onshore Disposal of Offshore Drilling Waste - Capacity
and Cost of Onshore Disposal Facilities16
The purpose of this study was to evaluate the capacity and
cost incurred by onshore disposal facilities to dispose of
offshore drilling wastes and whether these facilities had
adequate capacity to dispose of proje'cted waste volumes. The
evaluation focused on the three major geographic areas where
onshore disposal of offshore drilling waste would be encountered:
Gulf of Mexico, California, and Alaska. In each area, the
capacity to accept and properly dispose of the drilling waste was
evaluated based on assumptions regarding the level of drilling
activity, volumes of drilling waste per well-site, and different
formulas for predicting the percentage of drilling waste that
might require onshore disposal.
The study estimated the amount of offshore drill waste
requiring onshore disposal and determined whether disposal
facilities in each region had adequate capacity. Data on well
drilling activity, waste volumes associated with drilling, and
amounts of offshore waste requiring onshore disposal were
provided by EPA or were extracted from data contained in the
rulemaking record associated with this regulatory action.
Options for offshore waste disposal in each region were evaluated
based on telephone contacts with knowledgeable individuals
associated with state/local regulatory agencies or with disposal
facilities. Estimates of regional capacity were derived from
telephone contacts with facility operators, recently completed
state hazardous waste Capacity Assurance Plans, state data on
nonhazardous waste facilities, and literature sources. Finally,
regional capacities were compared to waste volumes requiring
onshore disposal under two regulatory options: 1) zero discharge
of shallow water well drill waste and BAT control of deepwater
VI-29
-------
wells based on toxicit; sheen, etc., and 2) zero discharge of
all drilling w: ;te.
The results of tfris report's investigation show that
sufficient land capacity would be available should a zero
discharge requirement be imposed. However the required amount of
land in the coastal regions would be a substantial amount of this
capacity. See Section XIV for the details.
3. Offshore Drilling Safety17
EPA evaluated available safety information by comparing
published accident and fatality rates between offshore oil and gas
extraction activities and other industries. 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.
The technology involved in implementing the zero discharge
option for drilling fluids and cuttings will be either to bulk
load the material onto barges or to load individual containers
onto supply ve. ;>els. Generally, supply boats are used for
facilities far offshore (barges are primarily used in very shallow
waters). Containers or bins are used to hold the excess/used muds
and cuttings and have an approximate capacity of 25 barrels.
Cranes load these containers into and off of supply boats. The
implementation of a zero discharge standard will ultimately
increase crane-related and transport activity because of the need
to deliver all drilling fluids and cuttings wastes to shore for
land disposal.
Safety data indicate that the use of cranes is prone to
higher accident rates than the average of the rest of the
operation. However, accurate estimates of the possible increase
VI-30
-------
in accidents due specifically to drilling fluids and cuttings
transport are difficult to make due to the lack of data.
One of several estimates based on these data reports crane-
*
related accident incidents to increase 6% per year. In comparison
to other industries such as oil and gas field services, construc-
tion, and water transportation in general, this 6% increase would
still keep the amount of incidents for oil and gas extraction
operations lower than these other industries. See Section XIV for
a comparison of safety statistics.
F. ANALYTICAL METHODS
1. Review of Static Sheen Testing Procedures18
Since the 1985 proposal of a new analytical procedure to
measure free oil, known as the "static sheen test," other
variations to this method have been suggested. EPA has reviewed
three other methods: one developed by Region IX, one by Region
X, and an additional version known as the "minimal volume"
method. A comparison of the differences between the 1985
proposal and Region IX's suggested method is presented below:
Receiving water - The "original" procedures require
ambient seawater to be utilized as the receiving water
in the test whereas Region IX procedures call for
tap/drinking water.
Mixing/stirring - The "original" procedures call for
thorough mixing of both the test material samples and
the mixture of test material and receiving water.
Region IX procedures delete all references to mixing
test material samples and require efforts to "minimize
any mixing of the test material in the test water." In
their procedures, Region IX expresses concerns over
test interferences due to bubbling/foaming and
particulate surface deposits. This appears to be the
reason Region IX discourages mixing or stirring
activities.
VI-31
-------
Sample volumes/weights - The "original" procedures
specify drilling fluid, deck drainage, or well
treatment fluid samples of 0.15 mL and 15 mL and drill
cuttings or produced sand samples of 1.5 g and 15 g on
a wet weight^basis. Region IX procedures call for 15
mL samples for drilling fluid, deck drainage, or well
treatment fluid samples and 15 g (wet weight) samples
of drill cuttings or produced sand. Region IX's
requirements simplify the test by requiring only the
largest sample of the waste stream.
•
Observations - The "original" procedures require
observations to "be made no later than one hour after
the test material is transferred to the test
container." Region IX requirements dictate that
observations occur "immediately, and at 15, 30, and 60
minutes after the test material is transferred to the
test container."
Sheen designation - "Detection of a silvery or metallic
sheen, gloss, or increased reflectivity; visual color;
or iridescence on the water surface" is considered to
be an indication of "free oil" under the "original"
guidelines. Under Region IX guidelines, the
discoloration must cover "more than one-half of the
surface of the test water" and "the appearance of a
sheen must persist for at least 30 seconds" to be
classified as indicating the presence of "free oil."
The method employed by Region X is similar to the 1985
proposed method except that a free oil determination is based on
the appearance of a sheen on more than one-half of the water
surface (as per the Region IX method). Region VI does not use a
static sheen test.
The "minimal volume" test procedure requires a sample volume
of 5 ml or weights of 15 g. The receiving water is tap water.
Stirring should be minimized (although not specified).
Observations are made within 5 minutes. The presence of free oil
is determined by criteria similar to the 1985 proposal. This
procedure was developed in an attempt to produce better results
with less variability under laboratory conditions.
VI-32
-------
A study was performed by industry which compared these
static sheen methods.19 This study, among other aspects of the
test, investigated the tendency of false positive readings for
each method. False positive results are those that show a free
*
oil detection for non-oil-containing samples. A percentage of
false positive results gives an indication of the reliability of
the test. The 1985 proposed method, also the same method used by
Region IX at the time of the study, showed 16.76% false positives
(63 samples out of 376). The Region X method showed 2.5% and the
minimal volume method, 21.86%.
EPA conducted an additional study solely on the minimal
volume test.20 Twenty-six individuals made observations on 56
mud samples at EPA's Gulf Breeze Laboratory. The results of this
evaluation were that for muds without oil, 33/546 or 6.0% false
positives were recorded. Furthermore, false positives were more
likely to occur if mineral oil was being tested (as opposed to
diesel oil).
EPA is not now formally proposing a variation on the 1985
static sheen test proposal as the preferred method. The Agency
is soliciting comments on this and the other three procedures as
to the appropriateness of each method.
2. Analytical Method for Diesel Oil Detection and
Total Oil Content - Proposed Method 1651
The August 26, 1985 Federal Register notice proposed a
method for detecting the presence of diesel oil in drilling
fluids and drill cuttings waste streams. The method, based on
retort distillation and gas chromatography, has subsequently been
modified based on experience gained during the conduct of the
Diesel Pill Monitoring Program (described in Section VI of this
document). The revised version of Proposed Method 1651, "Oil
Content and Diesel Oil in Drilling Muds and Drill Cuttings by
VI-33
-------
Retort Gravimetry and GCFID" appeared in Appendix A of the Notice
of Availability. However, this version was incomplete and later
correctly published in the Federal Register (54 FR 634).
The modified version of the diesel analytical method also
includes a proposed method for determining the oil content of
drilling wastes using retort distillation and gravimetry. The
Agency has determined that exist.ng approved analytical methods
for measuring oil are not appropriate for drilling wastes and
that the oil content method appearing in -2 Federal Register is
the appropriate test procedure.
The retort distillation method has been widely used by the
industry for testing drilling muds and is simple to perform on
offshore facilities in remote conditions. This version of the
method has an estimated detection limit of 200 mg/kg of oil
content and 100 mg/kg of diesel oil. Documentation on precision
and accuracy measurements of the test method is included in the
1988 Notice of Availability.
A recent multi-laboratory sfcidy, performed as a joint effort
by EPA and industry/ has been completed which investigated the
test method variability. Results are not available as of the
date of this publication; however, indications are that the
conclusions will support the method.
Oil and Grease
Two analytical methods for oil and grease have been
investigated by EPA. Standard Method 503A, also known as EPA
Method 413.1 or the gravimetric method, and Standard Method 503E,
commonly referred to as the silica gel method, can be used to
determine oil and grease content of produced water samples.
Standard Method 503A is designed to extract dissolved or
VI-34
-------
emulsified oil and grease from water using trichlorotri-
fluoroethane. This method measures total (soluble and insoluble)
oil and grease. Special precautions regarding temperature and
solvent vapor displacement are included in the procedures to
minimize the oxidation of certain extractables. Standard Method
503E utilizes silica gel to remove polar materials such as fatty
acids. This method measures the insoluble portion of oil and
grease. The materials not removed by the silica gel are
designated as soluble hydrocarbons. Standard Method 503E may be
performed immediately after Standard Method 503A by re-
solubilizing the weighed residue of Standard Method 503A in freon
and treating with silica gel.
In the three facility study, analytical results from both
methods were compared. Each produced water sample taken was
analyzed using Standard Method 503A while Standard Method 503E
was utilized on alternating samples. This allowed direct
comparison of both methods on half of the samples collected at
each facility. Results of this comparative analysis showed
values reported by the silica gel method to be consistently lower
than the gravimetric method, as expected. Figures VI-6, VI-7,
and VI-8 show effluent values for both methods at various sample
points at the Long Beach bay facility.
4. Drilling Fluids Toxicitv Test"
The 1985 offshore oil and gas proposal included a limitation
on the toxicity of discharged drilling fluids. The toxicity
limit is expressed as the concentration of the suspended
particulate phase (SPP) from a sample of drilling fluid that
would be lethal to 50% of a particular species exposed to that
concentration of the SPP, i.e., the LCSO of the discharge. The
species used in the toxicity test is mysidopsis bahia, otherwise
called mysid shrimp. The Agency proposed a toxicity limitation
VI-35
-------
400-
379-
390-
329 *
300 -
O279-
0290-
*•* 2J9 .
Ul
H o 179 •
U ^ 150-
J
O 1x9.
100-
79-
90.
29-
0_
. SAMPLING OF PRODUCtU WATER TREATMENT SYSTEM
OIL & GREASE RESULTS VERSUS TIME
SAMPLING POINT S1 - SKIM OIL TANK r«— "1ENT
* METHOD 903A y
0 METHOD S03E
K
M « * 0 n * : •
' ^ ° M ^
MM ** ^ ° 0
MM M°
•M * „ M 0 M MM ° M«" M- M*0 ' ' * '
•n 0K 0 • M* 0 0 0 °
0 o * 0 00 ' •
0
8 10 12 2 4 8 8 10 12 2 4 8 8 10 12 2 4 8 8 10 12 2 4 8 a 10 12 2 4 8 a 10 12 2 4 8 8 10 12 2 4 8 8 10 12 2 4 8
SAMPLE DAY 1
JUNE 18-19. 1989
SAMPLE DAY 2
JUNE 19-20. 1980
SAMPLE DAY 3
JUNE 20-21. 1989
SAMPLE DAY 4
JUNE 21-22. 1989
TIME (HRS)
FIGURE VI-6
Source:
-------
l- ** M>f M " ° 0
o o o D o
.0 o 0 0 ° 0
8 10 12 2 4 8 8 10 12 2 4 8 8 10 12 2 4 0 8 10 12 2 4 8 8 10 12 2 4 8 8 10 12 2 4 8 8 10 12 2 4 8 8 10 12 2 4 8
SAMPLE DAY 1
JUNE 18-19. 1980
SAMPLE DAY 2
JUNE 19-20. 1989
SAMPLE DAY 3
JUNE 20-21. 1989
SAMPLE DAY 4
JUNE 21-22. 1989
TIME (MRS)
FIGURE VI-7
Source: 2
-------
SAMPLING OP PRODUCED WATER TREATMENT SYSTEM
OIL & GREASE RESULTS VERSUS TIME
H
1
U)
00
200 -
«o-
180-
170-
190-
190-
140-
^130-
£ 120-
^ 11*-
VI
Q£ MI
o •"*
4) 90>
si 70.
O
00 >
90.
40.
90.
20.
10.
a.
M METHOD 503A
0 METHOD 503E
•
K
M M
* * M M M *
* ^* *« M *^f FT M ^tf M
AC ^% ^^ ^" ^T 1^ ^£ ^* __
• * *. »f
M *
M .. N * M
* M ft M 0 .0
* 0 o
.11 i-i Q, i-Q-4. Q 1.1-4. 0.i Q i 0 i 0 L i i 1-i.fD i 0 i9iiiiiTiiiOi9iOiiiiiii
8 10 12 2 4 0 8 10 12 2 4 0 8 10 12 2 4 0 8 10 12 2 4 0 8 10 12 2 4 0 8 10 12 2 4 0 8 10 12 2 4 0 8 10 12 2 4 0
SAMPLE DAY 1
JUNE 18-10. 1989
SAMPLE DAY 2
JUNE 19-20. 1989
SAMPLE DAY 3
JUNE 20-21. 1989
SAMPLE DAY 4
JUNE 21-22. 1989
Source: 2
TIME (MRS)
FIGURE VI-8
-------
of 30,000 ppm based on the toxicity of the most toxic of eight
faeneric drilling fluids that were in general use at the time of .
proposal. In addition, permit writers have set this limit as
their best professional judgment of BAT, and it is currently
included in the general permit for oil and gas activities in the
outer continental shelf of the Gulf of Mexico and the offshore
oil and gas permits for California.
As part of the evaluation of methods under Section 304(h) of
the Clean Water Act and as a response to comments from the 1985
offshore oil and gas proposal, the Agency has recently conducted
a study of the variation in results from the toxicity test for
drilling fluids. The study was conducted in two phases.
In Phase I, each lab was required to conduct one toxicity
test on a sub-sample of generic drilling fluid #3 (lime mud).
The participating labs included 2 Agency labs and 28 contract
labs. The contract labs included all commercial, academic, and
industry labs known to the Agency that claimed to have experience
with some form of toxicity testing and were willing to
participate. The Agency knows of over 100 commercial, academic,
and industry labs that are potentially capable of conducting the
required test.
In Phase II, each lab was required to conduct two toxicity
tests on sub-samples of generic drilling fluid #8 (lignosulfonate
freshwater mud) and two toxicity tests on sub-samples of generic
drilling fluid #8 with 3% mineral oil. The contract labs were
selected at random from those contract labs that demonstrated the
ability to conduct the toxicity test at a competitive price.
However, three of the labs selected for Phase II failed to
complete the study.
VI-39
-------
TABLE VI-2
PRELIMINARY RESULTS OF ROUND ROBIN TOXICITY TESTING
^abined Within and Between Lab Variation
Drilling Fluid
Generic Fluid # 3
Generic Fluid #8
Generic Fluid #8
with 3% Oil
Drilling Fluid
Generic Fluid #8
Generic Fluid #8
with 3% Oil
k
Responses
All
Selected
Phase II
Phase n
Phase II
Number of
Labs
28
16
9
9
9
Average '
LC50
25.6% spp
22.6% spp
215% spp
50.9% spp
0.27% spp
Standard
Deviation
12.0% spp
5.96% spp
5.75% spp
19.4% spp
0.36% spp
Coefficient
. of
Variation
47.1%
26.4%
25.5% '
38.1%
133.9%
Within Lab Variation
#Labs
9
9
Average
LC50
59.9%
spp
027%
spp
Standard
Deviation
10.4%
spp
020%
spp
Coefficient
of
Variation
20.5%
72.0%
95% Prediction
Interval
Lower Upper
26.6% 75.2%
spp spp
-1-0.0% 0.73%
spp spp
Notes:
LCSOs for #3 calculated using Probit Analysis by Maximum Likelihood and
with optimization for control mortality.
Average LC50 is the average of the average LC50 for each lab.
SD for combined within and between lab variation is the square root of
the sum of mean squares for within lab variation plus the sum of mean
squares for between lab variation. SD for within lab variation is the
square root of the sum of squares for within lab variation *
CV is SD/Average LC50.
Predictio. Interval is for within process variation from the 16 labs
that have demonstrated the ability to conduct EPA's toxicity test.
Source: 22
VI-40
-------
A summary of the preliminary results for the contract labs -
is presented in Table VI-2. The "selected" labs in the summary
for generic fluid #3 were included because a review of the raw
lab reports indicated that they correctly followed the test
protocol they received as part of the study. The primary summary
statistics included in the table are the average toxicity (LC50),
standard deviation (SD), prediction intervals, and the
coefficient of variation (CV).
The average LC50 was slightly higher (less toxic) than
expected for the sample of generic drilling fluid #3 and for the
sample of drilling fluid #8. However, the average LCSO reported
for drilling fluid #8 with 3% mineral oil was lower (more toxic)
than expected. It is important to note that each of these
average lab results is based on each lab testing a sub-sample
from a single well-mixed sample of drilling fluid. Hence, the
variation found in this study is related only to within and
between lab variation and any average result applies only to that
one sample of drilling fluids. Generalizations to average levels
for other batches of the same generic drilling fluid or the same
generic drilling fluid with mineral oil are not supported by
these data.
The standard deviations (SD) reported in Table VI-2 indicate
the magnitude of variation found in lab results for a particular
drilling fluid system. Because only one test per lab was
conducted on the sample of generic drilling fluid #3 it is not
possible to estimate within lab variation for that sample. In
order to provide comparable statistics, combined within and
between lab standard deviations are presented for all samples
tested in the study. However, the Agency is primarily interested
in estimates of within lab variation so these estimates are
presented for generic drilling fluid #8 and generic drilling
fluid #8 with 3% mineral oil. Estimates of within lab variation
VI-41
-------
from competent labs quantifies the natural variability inherent -
in the measurement process while between lab estimates of
variability quantifies lab bias. Lab bias describes the
situation when all results of a particular lab are consistently
•
above or below the multi-lab average result. The Agency believes
that between lab variation is caused by consistent lab practices
that can be modified through learning from experience.
Additionally, an hypothesis that Ir.-ver LC50s are linked to lower
s
-------
industry's ability to use product substitution with drilling
fluids so that, based on within lab variation, industry would be
able to comply with proposed limitations.
Preliminary analysis of the multi-lab results for toxicity
tests and reference toxicant -tests from the recent study continue
to support the conclusions that the testing protocol is adequate
for use in a regulatory framework. 'Industry will be able to use
either product substitutipn in order to comply with a 30,000 ppm
limitation on toxicity or available technology to avoid
discharging drilling wastes.
VI-43
-------
G. REFERENCES
1. ERCE, "The Results of the Sampling of Produced Water
Treatment System and Miscellaneous Wastes at the Shell
Western E & P, Inc. - Beta Complex," Draft, March 1990.
2. 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,
March 1990.
3. ERCE, "The Results of the Sampling of Produced Water
Treatment System and Miscellaneous Wastes at the Conoco,
Inc. - Maljamar Oil Field," Revised, January 1990.
4. a) Letter from Kenneth M. Thomas, Alcoa Separation
Technology, Inc. to Ron Jordan, EPA, October 10, 1990.
b) G Hot, J., et al, "New Ceramic Filter Media for Cross-
Flow Microfiltration and Ultrafiltration," France,
April 1986.
c) Goodboy, Kenneth P., et al, "Operational Results of
Cross-Flow Microfiltration for Produc .d and Sea Water
Injection," Scotland, November 1, 1985.
d) Chen, Abraham S. C., et al, "Re sval of Oil, Grease,
and Suspended Solids from Produced Water Using Ceramic
Crossflow Microfiltration, no date.
5. ERCE, "An Evaluation of Technical Exceptions for Brine
Reinjection for the Offshore Oil and Gas Industry," March
1991.
6. API, "A National Survey on Naturally Occurring Radioactive
Materials (NORM) in Petroleum Producing and Gas Processing
Facilities," July 1989.
7. Battelle (for API), "Fate and Effects of Produced Water
Discharges in Nearshore Mrrine Waters," August 22, 1988.
8. Kraemer, T. F. and D. F. Reid, "The Occurrence and Behavior
of Radium in Saline Formation Water of the U.S. Gulf Coast
Region," (1984), Isotope Geosci. 2:153-174.
9. U.S. EPA, "Natural Radioactivity Contamination Problems. A
Report of the Task Force," prepared by Conference of
Radiation Control Directors, U.S. Nuclear Regulatory
Commission, U.S. Dept. of Health, Education and Welfare and
U.S. EPA.
VI-44
-------
10. Survey Results on "Use of Hydrocarbons for Fishing
Operations" and "Use of Hydrocarbons as Lubricity Agents,"
attachments to letter from Shell Offshore, Inc. to EPA,
October 30, 1985.
11. Offshore Operators Committee, "Gulf of Mexico Spotting Fluid
Survey," prepared by Exxon Production Research Company and
Chevron, USA, Inc., April 4, 1987.
12. The EPA/API Diesel Pill Monitoring Program, presented at the
1988 International Conference on Drilling Wastes, Calgary,
Alberta, Canada, April 5-8, 1988.
13. "API-USEPA Metals Data Base for Metals Content in Drilling
Muds - Drill Cuttings/Formations - Barites - Sediments,"
April 1990.
14. SAIC for U.S. EPA, Summary of Data Relating to Miscellaneous
and Minor Discharges, revised February 1991.
15. KRE, P.C. for EPA-ITD, "Offshore and Coastal Oil and Gas
Extraction Industry Study of Onshore Disposal Facilities for
Drilling Fluids and Drill Cuttings Located in the Proximity
of the Gulf of Mexico," March 25, 1987.
16. ERCE for U.S. EPA, "Onshore Disposal of Offshore Drilling
Waste - Capacity and Cost of Onshore Disposal Facilities,"
March 1990.
17. ERCE, "Comparison of Safety Information Offshore Oil and Gas
Versus Other Industries," March 1990.
18. ERCE for U.S. EPA, "Review of Static Sheen Testing
Procedures," January 1990.
19. Jones E., and G. Otto, "Draft Final Report: An Evaluation
of the Proposed EPA Laboratory Static Sheen Test
Procedures", February 14, 1986.
20. Letter from Dennis Ruddy, EPA, to James Ray, Shell Oil
Corporation, May 30, 1989, describing minimal volum Static
Sheen test results.
21. Technical Resources, Inc. and Avanti Corporation, A.
Variability Study of the NPDES Drilling Fluids Toxicitv
Text. January 31, 1991.
22. Memorandum from Charles White, EPA to Marvin Rubin, EPA,
"Offshore Oil and Gas Extraction, Adequacy of the Toxicity
Test for Drilling Fluids for Permit Compliance Monitoring"
Attachment, March 4, 1991.
VI-45
-------
SECTION VII
WASTE STREAM SOURCES AND CHARACTERISTICS
A. INTRODUCTION
This section examines wastewater sources and characteristics
associated with the offshore oil and gas industry. Sixteen
groups of potential waste sources have been identified with
drilling and production activities, some of which occur in both
stages. The following are the major sources of wastewater:
Drilling fluids
Drill cuttings
Produced water
The following are referred to as miscellaneous wastes. They
are less in volume and pollutant loading than the major sources
but still are significant enough to warrant regulation:
Well treatment, completion, and workover fluids
Produced sand
Deck drainage
Sanitary wastes
Domestic wastes
There are also various minor waste streams associated with
offshore oil and gas that are discussed in this section, although
no regulations are being proposed for them.
This section describes the sources of wastewater effluents
(Section VII.B), then describes their volumes and pollutant
loadings (Section VII.C).
VII-1
-------
B. WASTEWATER SOURCES
1. Drilling Fluids
Drilling fluids, or muds, are suspensions of solids and
c .solved mat; rials in a base of water or oil that are used in
rotary drilling operations to lubricate and cool the drill bit,
carry cuttings from the hole to the 'surface, and maintain
hydrostatic pressure downhole. In the early days of oil
drilling, only water was used to remove cuttings. However,
drilling procedures are far more sophisticated today. Well
depths have increased, and complex drilling fluids are necessary
for efficient, economical, and safe completion of the well
drilling operation.
Drilling fluids can be water based or oil based. Oil-based
drilling fluids are those in which oil—typically diesel—serves
as the continuous phase with water as the dispersed phase. Such
fluids contain blown asphalt and usually 1% to 5% water
emulsified into the system with caustic soda or quicklime and an
organic acid. Silicate, salt, and phosphate may be present also.
Oil-based muds are more costly and more toxic than water-
based muds and normally are used only for particularly demanding
drilling conditions. However, the use of oil-based drilling
f,?.uids, or invert emulsion mud systems, has increased
significantly over the past several years as a result of their
advantages over water-based fluids in difficult drilling
situations. These advantages include excellent thermal stability
when drilling deep, high-temperature wells; lubricating
characteristics which aid in drilling deviated wells offshore;
and the ability to dr thick, water-sensitive shales with few
s* k pipe or hole wash-out problems. A primary concern when
u
-------
potential for adverse environmental impact. Mineral oil-based
mud systems have been developed recently as less toxic
alternatives. Oil-based muds and their associated cuttings must
be disposed of onshore in order to comply with the BPT limitation
of "no discharge" of free oil.
In water-based muds, water is the suspending medium for
solids and is the continuous phase, whether or not oil is
present. Water-based muds are more commonly used offshore.
Water-based drilling fluids are composed of approximately 70-90%
water by volume, with a variety of mud additives constituting the
remaining portion.
Drilling fluids are formulated specifically to meet the
physical and chemical requirements of a particular well. Mud
composition is affected by geographic location, well depth, and
rock type, and is altered as well depth, geologic formations, and
other conditions change. The number and nature of mud components
vary by well, and several products may be used at any given time
to control the properties of a mud system. Basic functions of a
drilling fluid include:1
Transporting drill cuttings to the surface
Suspending drill cuttings in the annulus when
circulation is stopped
- Controlling subsurface pressure
- Cooling and lubricating the bit and drill string
Supporting the walls of the wellbore
Helping suspend the weight of the drill string and
casing
Delivering hydraulic energy upon the formation beneath
the bit
Providing a suitable medium for running wireline logs
VII-3
-------
Figure VII-1 is a simplified schematic of the recycle
systems and discharge sources for drilling fluids and drill
cuttings.
2. Drill Cuttings
Drilling fluids circulate in the bore hole and move up the
annular space between the drill string and the borehole to the
surface, carrying drill cuttings with them. Cuttings are removed
from the drilling fluid by a step-wise process which removes
particles of decreasing size.
Upon reaching the surface, fluids and cuttings pass to the
shale shaker, a vibrating screen that removes large particles
from the fluid. Standard shaker screens generally remove
particles larger than 440 mm and fine screen shakers, using cloth
finer than 30 mm, remove particles down to approximately 120 mm.3
The fluid then is passed to the sand trap, a gravitational
settling tank that removes particles from approximately 74-210 mm
if shale shaker damage or shaker by-passing is a problem. A
desilter, a hydrocyclone using centrifugal forces, can then be
used to remove silt-sized particles (approximately 5-75 mm).
After removal, the cuttings are discharged anywhere from the rig
near the water surface or below the surface of the sea.
Processed drilling fluids return to the mud tanks for
recirculation to the well.
Solids removal system discharges consist of drill cuttings,
wash solution, and dr 11ing mud that still adheres to the
cuttings (see Figure VII-1). The amount of fluids adhering to
the cuttings Varies: At a well on the Southern California outer
continental shelf, it was found that normal cuttings discharges
from solids control equipment was comprised of 0-96% cuttings
VII-4
-------
01
Recycle Muds
Discharge Sand
Development or
Exploration Well
Shale
Shaker
Settling
Tank
L
1
Desander
Mud
Tank
Discharge Silt
_t
Desltter
Recycle Muds
Mud
Cleaner
Discharge Cuttings
Recycle Muds
\
Discharge Muds
FIGURE VII-1. DRILLING FLUIDS AND DRILL CUTTINGS: DISCHARGE SOURCES
-------
solids and 4% adhered drilling fluid.* However, data from a mid-.
Atlantic coast well placed these values at 40% drill cuttings and
60% drilling fluids.5 These data suggest that the nature of the
discharges are well specific.
3. Well Treatment. Completion, and Workover Fluids
As discussed under definitions in Section IV, well
treatment, completion, and workover fluids are being distinctly
defined in this rulemaking. Well treatment fluids are any fuuids
used to restore or improve productivity of the formation. Well
completion fluids are used to prepare the well for actual oil
extraction. Workover fluids are used to restore an abandoned
well to production or to repair a well. The fate of these fluids
varies; they may remain in the formation, become spent (if
acidic), thus losing their character, or resurface with the
produced fluid either as a discrete slug or diffused within the
brines. These fluids are separate and distinct from drilling
fluids. The composition of the fluids varies, but they
frequently are low solids, weighted brines with specialty
additives, or acidic solutions.
4. Produced Water
Produced water (also known as production water or produced
brine) is the total water discharged from the oil and gas
extraction process. It is comprised of the formation water,
which has been brought to the surface with the oil and gas,
injection water (if used for secondary oil recovery and has
broken through into the oil formation), and various chemicals
added during the oil/water separation process. Produced water
contains dissolved, emulsified and particulate crude oil
constituents, natural and added salts, organic chemicals, solids
VII-6
-------
and trace metals. Produced water constitutes the major waste
stream volume from offshore oil and gas production activities.
a) Formation Water
Formation water, comprising the bulk of produced water, is
found in the rock formation, along with crude oil and gas, before
it is brought to the surface. It is. difficult to describe its
chemical composition accurately, because formation water is under
pressure and in equilibrium with crude oil and gas in the
formation.
Formation waters may be classified as meteoric, connate, or
mixed. Meteoric water has fallen as rain and has percolated
through bedding planes and permeable layers; it can contain
carbonates, bicarbonates, and sulfates. Connate waters, or
seawater in which marine sediments were originally deposited, are
characterized by an abundance of chlorides, particularly sodium
chloride (NaCl), and have concentrations of dissolved solids many
times greater than that of common seawater. Mixed waters are
characterized by both a high chloride and sulfate-carbonate-
bicarbonate content, which suggests a multiple origin.
b) Water Flooding
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 water flooding. A grid pattern of wells is established, which
usually requires downhole repairing of old wells and 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
VII-7
-------
pressure and sweeping oil in a flood pattern. Water flooding can,
substantially improve oil recovery from reservoirs that have
, t
little or no remaining ^ervoir pressure. Treated seawater
typically is used offr. a for injection purposes. Treatment
consists of filtration to remove solids that'would plug the
formation and deaeration. Dissolved oxygen is removed to protect
the injection pip' Ine system from corrosion. A variety of
chemicals can be auded to water flooding systems, such as
flocculants, scale inhibitors, and oxygen scavengers. Biocides
also are used to prevent the .growth of anaerobic sulfate-reducing
bacteria, which can produce corrosive hydrogen sulfide in the
injection system. Discharges to the marine environment from
wate- flooding operations will include excess injection water and
backwash from filtering systems. Water flooding is considered to
be a "minor waste discharge" (see Section IV).
c) Enhanced Oil Recovery
When an oil field depleted by primary and secondary
methods (e.g., natural llow, artificial lift, waterflooding), as
much as 50% 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 processes can
be divided into three general classes: l) thermal, 2) chemical,
and 3) miscible displacement.
Thermal Thermal processes include steam stimulation,
steam floodii yl 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-
purop 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
VII-8
-------
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 "washes11 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
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.
Figure VII-2 is a simplified schematic of recycle systems
and sources of discharges for produced water. Discharge of
produced water does not occur until oil recovery and produced
water treatment have occurred. The treatment processes are
discussed in Section IX.
VII-9
-------
Production
Well
Gas to Sales
1
High
Pressure
Separator
Recycle Oil
Oil to Sales
Oil/Water
Separator
Skim
Tank
Recycle Oil
Gas
Rotation
Water Could be
Discharged at this Point
Backwash Water
Filter
Water Is
Either
Relnjected
or Is
Discharged
Overboard
FIGURE VII-2. PRODUCED WATER: RECYCLE AND DISCHARGE
-------
5. Produced Sand
Produced sand and other solids such as scale, corrosion by-
products, and paraffin^ associated with oil and gas production,
accumulate in production tubing, flowlines, and various oil and
gas process vessels. These solids must be removed periodically
to restore oil and gas production and processing and/or to avoid
interruptions to those same activities.
Low volumes of fine sands may be drained into drums on deck
or are carried through the oily water treatment system and appear
as suspended solids in the produced water effluent or settle out
in treatment vessels. If sand volumes are larger and sand
particles coarser, the solids are removed in cyclone separators,
thereby producing a solid phase waste. The sand that drops out
in these separators generally is contaminated with crude oil (oil
production) or condensate (gas production) and requires washing
to recover the oil. The sand is washed with straight water,
water combined with detergent, or solvents. The oily water is
directed to the produced water treatment system, or a separate
oily water separator, and becomes part of the produced water
discharge following oil separation. The clean sand is discharged
overboard or hauled to shore for land disposal. In some
locations (a number of Gulf of Mexico and Cook Inlet platforms),
the produced sands are piped to shore with produced water,
separated, and disposed of on land.
6. Deck Drainage
Deck drainage results primarily from precipitation runoff,
miscellaneous leakage and spills, and washdown of platforms or
drilling rig decks, floors, and vessels. It often contains
petroleum-based oils from miscellaneous spills and leakage of
VIl-ll
-------
oils and other production chemicals used by the facility. Oil
may also be present due to the washdown solvents.
A typical platform-supported rig is equipped with pans to
collect deck and drilling floor drainage. The drainage is
gravity separated into waste material and liquid effluent. Waste
materials are recovered in a sump tank, then treated, prior to
disposal, and used in the drilling mud system or transported to
shore. The liquid effluent, consisting primarily of washwater
and rain water, is dumped overboard.
7. Sanitary Wastes
The sanitary wastes from offshore oil and gas facilities are
composed 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.
Usually the toilets are flushed with brackish water or sea water.
Due to the compact nature of the facilities the wastes have less
dilution water than common municipal wastes. This results in
greater waste concentrations. Some platforms combine sanitary
and domestic wastewaters for treatment; others maintain sanitary
wastes separately for chemical or physical treatment by an
approved marine sanitation device.
8. Domestic Wastes
Domestic wastes (gray water) originate from sinks, showers,
laundries, food preparation areas, and galleys on the larger
facilities. Domestic wastes also may include solid materials
(paper, boxes, etc.) that are combustible.
VII-12
-------
9. Minor Discharges
The term "minor discharges" is used to describe all point
sources originating from offshore soil and/or drilling or
production operations other than produced water, drilling fluids,
drill cuttings, deck drainage, produced sand, well treatment and
workover fluids, and sanitary and domestic wastes. The following
is a list of these discharges and a brief description of them.6
a) Blowout Preventer (BOP) Fluid
An oil (vegetable or mineral) or antifreeze solution
(glycol) is used as a hydraulic fluid in BOP stacks during
drilling of a well. The blowout preventer may be located on the
sea floor and is designed to contain pressures in the well that
cannot be contained by the drilling mud. Small quantities of BOP
fluid are discharged periodically to the sea floor during testing
of the blowout preventer device.
b) 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 offshore. It is
similar to sea water in chemical composition and ratio of major
ions, but concentrations are higher. This waste is discharged
directly to the sea as a separate waste stream.
c) Fire Control System Test Water
Sea water, which may be treated with a biocide, is
discharged periodically, during tests of fire control systems,
directly to the sea as a separate waste stream.
VII-13
-------
d) Non-contact Cooling Water
Non-contact, once-through water Is used to cool crude oil,
produced water, power^generators, and various pieces of
machinery. Biocides can be used to control biofouling in heat
exchanger units. Noncontact cooling waters are maintained
separately and discharged directly.
•
e) Ballast and Storage Displacement Water
Two types of ballast water are found in offshore producing
areas (tanker and platform ballast). Tanker ballast water
comprises sea water or fresh water from the region 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
does not have segregated cargo and ballast tanks.
Unlike tank ballast water, which may have had multiple
sources and which 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 an oil/water separation process prior to
discharge.
Storage displacement water from floating or semi-submersible
offshore crude oil structures is composed mainly of sea water.
Much of this volume usually can be discharged directly without
treatment, since little mixing occurs with the oil floating on
top of the water. The water in contact with the oil can receive
a small amount of dissolved aromatic constituents through
VII-14
-------
molecular diffusion at the oil-water interface. Paraffinic
compounds have low solubilities in water and will not migrate
into water solution to any appreciable degree. Crude oil
constituents will notOae dispersed significantly in particulate
form into the water below, except in unusual 'circumstances such
as in very rough seas, because the oil-water interface is always
maintained. The interface water usually is treated through an
oily water separator system before discharge.
f) Bilae Water
Bilge water, which seeps into all floating vessels, is a
minor waste for floating platforms. This sea water becomes
contaminated with oil and grease and with solids such as rust
where it collects at low points in vessels. This bilge water
usually is directed to the oily water separator system used for
the treatment of ballast water or produced water, or is
discharged intermittently.
g) Boiler Slowdown
Purges from boilers' circulation waters are necessary to
minimize solids build-up in the boilers.
h) Sea Floor Contamination
Part of the drilling process is the initial excavation of a
surface hole. This surface hole may be 30 inches in diameter and
up to 350 feet deep. In addition to drilling, seawater may be
used to jet out this hole. Rock cuttings generated during this
phase are discharged at the sea floor. There is no type of
treatment available for these cuttings. Minor effects have been
reported to near field benthic organisms in the area around the
rig.
VII-15
-------
i) Test Fluids
Test fluids are discharges that would occur if hydrocarbons
are located during exploratory drilling and tested for formation
pressure and content. .
j) Diatoinaceous Earth Filter Media
Diatomaceous earth filter media are used to filter seawater
or other authorized completion fluids and then washed from the
filtration unit.
k) Bulk Transfer Operations
Bulk materials such as barite or cement may be discharged
during transfer operations.
1) Painting Operations
Discharges of sandblast sand, paint chips, and paint spray
may occur during sandblasting and painting operations.
m) Uncontaminated Freshwater
Uncontaminated freshwater discharges come from wastes such
as air conditioning condensate or potable water during transfer
or washing operations.
n) Waterflooding Discharges
(Described under "Produced Waters")
VII-16
-------
o) • Laboratory Wastes
Laboratory wastes contain material used for sample analysis
and the material being analyzed. The volume of this waste stream
is relatively low and is not expected to pose significant
environmental problems. However, freon may be present in
laboratory waste. With the high volatility of freon, these
wastes are not expected to remain in. aqueous state for very long
and are, therefore, not expected to be present in significant
quantity. The Agency is discouraging the discharge of
chlorofluorocarbon to the air or water media.
C. WASTEWATER CHARACTERISTICS
1. Drilling Fluids
Four basic components account for approximately 90% by
weight of all materials consumed in drilling fluids, namely,
barite, clays, lignosulfonates, and lignites.? Such were the
results of a survey conducted by the Agency for offshore drilling
operations in the Gulf of Mexico.3 Other components include
lime, caustic soda, soda ash, and a multitude of specialty
additives. These additives are used to modify the
characteristics of drilling muds as dictated by well requirements
to control site-specific drilling conditions. Table Vll-l lists
some of the common types and functions of materials used in
drilling fluid systems.
a) Barite
Barite, also known as baryte or heavy spar, is a heavy,
soft, and chemically inert mineral. Pure barite contains 58.8%
barium (Ba) and 41.2% sulfate (SOJ . However, commercial forms
can run as low as 92% BaS04 and contain such impurities as
VII-17
-------
TABLE VII-1
FUNCTIONS OF SOME COMMON DRILLING MUD CHEMICAL ADDITIVES
1. Alkalinity and pH -6ontrol; Caustic soda, sodium carbonate,
sodium bicarbonate, and lime are commonly'used to control the
alkalinity of the drilling fluid and secondarily to control
bacterial growth.
2. Bactericides: Paraformaldehyde, alkylamines, caustic soda,
lime, and starch preservatives are typically used as bac-
tericides to reduce the bacteria count in the mud system.
Halogenated phenols are no longer permitted for OCS use.
3. Calcium Removerst Caustic soda, soda ash, sodium bicarbonate,
and certain polyphosphates are added to control the calcium
build-up which prevents proper functioning of drilling
equipment.
4. Corrosion Inhibitors; Hydrated lime and amine salts are added
to drilling fluids to reduce corrosion potential.
5. Defearners; Aluminum stearate and sodium aryl sulfonate are
commonly used and are designed to reduce foaming action that
occurs particularly in bracxish waters and saturated salt-
water muds.
6. Emulsifierst Ethyl hexanol, silicone compounds, modified
lignosulfonates, and amionic and nomionic products are used as
emulsifiers to create a homogeneous mixture of two liquids.
7. Filtrate Loss Reducers: Bentonite clays, a range of cellu-
lose polymers such as sodium carboxymethyl cellulose (CMC) and
hydroxyethyl cellulose (HEC), and pregelated starch are added
to drilling fluid to prevent the invasion of the liquid phase
into the formation.
8. Flocculants; Salt (or brine), hydrated lime, gypsum, and
sodium tetraphosphate cause suspended colloids to group into
"floes" and settle out.
9. Foaming Agents; These products are designed to foam in the
presence of water and allow air or gas drilling through for-
mations producing water.
10. Lost Circulation Materials; Wood chips or fibers, mica,
sawdust, leather, nut shells, cellophane, shredded rubber,
fibrous mineral wool, and perlite are all used to plug pores in
the well-bore wall and to reduce or stop fluid loss into the
formation.
VII-18
-------
TABLE VII-1 (Continued)
FUNCTIONS OF SOME COMMON DRILLING MUD CHEMICAL ADDITIVES
11. Lubricants; CertaoLji hydrocarbons, mineral and vegetable oils,
graphite powder, and soaps are used as lubricants to reduce
friction between the drill bit and the formation.
12. Shale Control Inhibitors; Gypsum, sodium silicate, polymers,
limes, and salt reduce wall collapse caused by swelling or
hydrous disintegration of shales.'
13. Surface Active Agents (Surfactants); Emulsifiers, de-emul-
sifiers, and flocculants reduce the relationship between
viscosity and solids concentration, vary the gel strength, and
reduce the fluids's plastic viscosity.
14. Thinners; Lignosulfonates, tannins, and various polyphos-
phates are used as thinners since most of these also remove
solids. Thinners act by deflocculating associate clay par-
ticles.
15. Weighting Materials: Products with high specific gravities,
predominantly barite, calcite, ferrophosphate ores, siderite,
and iron oxides (hematite), are used to increase drilling mud
weight.
16. Petroleum Hydrocarbons; These produces (diesel or mineral oil)
may be added to mud systems for specialized purposes such as
freeing a stuck pipe.
Source:
VII-19
-------
silica, iron oxide, limestone, and dolomite, as well as various
trace metals.
Nearly all barite consumed in the United States is used as a
weighting agent in drilling muds. Offshore wells, which on
average are deeper and have higher subsurface pressures than
onshore wells, account for a disproportionately high percentage
of total consumption.
Barite is a ubiquitous mineral because barium and sulfur are
common in the crust of the earth, being 16th and 14th in
abundance, respectively, and because BaS04 is very insoluble. It
tends to form a fine precipitate and is found in a range of grain
sizes and textures.
Deposits of barite are classified into three types: l) vein
and cavity-filling deposits, 2) bedded deposits, and 3) residual.
deposits. Residual deposits typically are mined in open opts
after removal of overburden. Bedded and vein deposits may be
mined by open pit or underground methods depending on local
conditions. Following extraction, most ore is beneficiated atthe
extraction site, usually by rigging or flotation. (Some deposits
are pure enough that beneficiation is unnecessary.) The purified
barite then is shipped to a processing plant to be crushed and
ground.
Available data on trace metal analyses are summarized in
Tables VII-2 and VII-3. Vein and residual deposits show a much
wider range than bedded sources: some have trace metal levels
below ocean sediment and crustal averages, but others contain
mercury, cadmium, and zinc in quantities on the order of 100
times greater. The primary source of toxic metals in drilling
fluid discharges is the barite component of drilling fluids. The
principal metals of concern are mercury and cadmium.
VII-20
-------
I
NJ
TABLE VII-2
ANALYSIS OF TRACE ELEMENTS IN BARITE SAMPLES
Source
Fe
Pb
Zn
LITERATURE VALUES:
Vein deposits: 8-22.000
Trace Element Concentration mg/kg
Hg As Ca
4-1220 10-4100 0.06-14 7*
Bedded deposits: 100-3000 <10 <200"* 0.06-0.19 <500*** 1-11
THIS STUDY:
Vein Deposits: 200-59.000 <2-3370 <. 2-9020 0.8-28 0.008-170
Bedded deposits: 2500-6000 1-1.8 6-10 0.13-0.26 1.4-1.8
REFERENCE MATERIAL:
Crust average: 50.000 15 65 0.1 2
Ocean sediment: 50.000 110 40 0.3 8
• - One Analysis
• • - Mean of 83 Analyses
••• - Semlquantltatlve Emission Spectrographic Analysis
Cd
0.6-32
0.5-0.7
0.2
1
Nl
2-26 <0.2-19 19"
<50*** <5-5
15-41
0.4-5.7
80
240
Cu
2-97
3-20
45
350
CO
not
detected
<5-60
0.6-560 O.f-9.2
5.4-7.6 1-2.2
23
100
Source: 9
-------
TABLE VII-3
COMPARISON OF RESULTS OF SOLUBILITY EXPERIMENTS IN BARITE SAMPLES
TO SEA HATER CONCENTRATIONS
Source Trace Metal Concentration a/ka2
Hg Pb Zn Cd Cu Ni As
Opp" Oceans1
^
H Low v . ce Metal Barite
I
M High Trace Metal Barite <.01-.323 50-200 50-200 0.4-5 1-4.3 6.6-10
).3
1 <1
0.03 <2
1
2-5
1
1Fron» compilation by Hogdahl
2Results are for 0.45m filtered samples in ug/kg
3With bentonite <.01-.01
Source: 9
-------
b) Clays
Bentonite is the most widely used clay. Its crystalline
structure causes bentonite to swell upon contact with water, and
this gelling ability suspends solid material and aids in the
removal of drill cuttings from the borehole. The sealing
properties of bentonite are also well established, which enable
them to form an impermeable filter cake on the wellbore wall.
When highly concentrated brine (produced water) is encountered at
great depths, the swelling properties of the bentonites are
severely reduced, and attapulgite or sepiolite clays are
substituted.
c) Lionosulfonates
Lignosulfonates, by-products of the pulp and paper industry,
are considered the best all-purpose deflocculants for water-based
drilling fluids and serve to maintain the mud in a fluid state.
Water generally is not used to thin barite-containing muds,
because this practice generally is self-defeating; therefore,
chemical deflocculants are used.
Ferrochrome lignosulfonate is a widely used form of
lignosulfonate. It performs over a wide alkaline pH range, is
resistant to common mud contaminants, is temperature stable to
approximately 177°C (350°F), and will function in high soluble
salt concentrations. Chromium can represent up to 3% by weight
of ferrochrome lignosulfonate; the mud aqueous fraction of used
seawater ferrochrome lignosulfonate drilling fluid contains
approximately 1 ppm chromium. Most of this chromium is in the
less toxic trivalent form. Moreover, most of the chromium is
bound to clay particles.10
VII-23
-------
d) Lignites
Lignites are used as defloccul.ants, like lignosulfonates,
but are substantially^less soluble in seawater. Lignite products
are used to thin freshwater muds, reduce drilling fluid loss to
the formation, and aid in the control of mud gelation at elevated
temperatures.
e) Other Components
Other components, including lime, caustic soda, soda ash,
and a multitude of specialty additives, are used as dictated by
well requirements. The quantities of components used were found
to vary considerably from well to well, but certain trends were
observed. Wells in federal OCS waters required, on average, more
drilling muds and specialty additives than did wells in state
waters. Also, exploratory wells required more drilling mud and
specialty additives than did development wells. Average total
mud consumption for the surveyed wells amounted to 3.1 million
pounds per exploratory well and 0.8 million pounds per
development well.
f) Volume
Drilling fluid discharges from offshore oil and gas
operations originate from the mud tanks, are generally in bulk
form, and occur intermittently during well drilling. High- and
low-volume bulk discharges of drilling fluids from the mud tanks
usually number 20 to 30 during the drilling of a well. Low-
volume fluid discharges will occur several times during drilling
and are associated with maintaining solids levels in fluids, and
cementing operations. High-volume bulk discharges occur a few
times during the drilling period, when:
VII-24
-------
Drilling fluid must be removed to allow dilution with -
water
Drilling fluid is being changed from one type to
another
Drilling fluid tanks are being emptied at the end of
drilling operations
High-volume discharges generally occur several times per
well during an offshore drilling operation for each drilling
fluid system changeover. Each discharge lasts 20 minutes to 3
hours, at a rate of 250 to 700 bbl/hr or more, for a total volume
of up to 2,000 bbl or more. For instance, bulk mud discharges
for dilution purposes from a semi-submersible rig in Lower Cook
Inlet were at the rate of 720 bbl/hr (for a 17-minute-period
maximum volume of 200 bbl), and occurred three times during the
drilling of a well.3
Table VII-4 provides estimates of the drilling fluid
discharge rates for a Gulf of Mexico well-drilling program.
Discharge rates for wells in different geographic locations are
summarized in Table VII-5. Drilling fluid discharges for the
Tanner Bank are only available on a barrel-per-hour basis. This
could not be extended to a barrel-per-day average because
drilling fluid discharge rates and periods vary with individual
rig operation.
Table VII-6 shows quantities of the basic drilling fluid
components used in wells greater than 2,800 m (9,000 ft) deep as
a function of depth. An analysis of drilling fluid additive use
based on data from ten wells in the Gulf of Mexico and the Mid-
Atlantic OCS showed a correlation between total usage and depth
of well; a linear increase was noted from about 680 metric tons
(750 tons) at 3,100 m (10,000 ft), to about 1,225 metric tons
(1,350 tons) at 5,000 m (15,000 ft), and to 1,815 metric tons
(2,000 tons) at 6,100 m (20,000 ft).
VII-25
-------
TABLE VII-4
PROPOSED DRILLING FLUID DISCHARGE RATES
FOR A GULF OF MEXICO WELL DRILLING PROGRAM
(Shell • Company, 1978)
Drilling Fluid
<
M
l-l
1
Nl
Depth Interval
(feet)
0-500
500-1.000
1.000-3.000
3,000-8.000
8.000-16.000
16,000-20.000
Drilling
Time
(days)
1
2
6
27
61
30
Bit
Diameter
(Inches)
29
26
22
15
12-1/4
8-3/4
Mud
Type(a)
SW
SW
SW-gel
LT FCLS-
FW/SW
FCLS-FW
FCLS-FW
Average
Daily
Discharge
(bbl)
2.500
2.500
200
50
50
50
Total Volume
Discharged
(bbl)
Continuous Bulk
2.500
5,000 1,000
1,200
1,350
3,050
1,900 800
Drilled
Average
Dally
Discharge
(bbl)
722
289
265
65
28
10
Cuttings
Total Volume
of Cuttings
Discharged
(bbl)
722
578
1,588
1.757
*
1,733
361
Total 135
15.000
1,800
6.739
Overall Dally Average: drilling fluid • 116 bbl/day
cutting • 47 bbl/day
(a)SW (Saltwater plus'natural mud)
SW-gel (saltwater plus bentonlte or attapulgite)
LT FCLS-FW/SW (a lightly-treated ferrochrome llgnosulfonate freshwater/saltwater system)
FCLS-FW (a freshwater ferrochrome llgnosulfonate system)
Source: 11
-------
TABLE VI1-5
SUMMARY OP DRILLING FLUID AND CUTTINGS DISCHARGE RATES
BY GEOGRAPHICAL LOCATION
^ (bbl/day/well)
OCS Location
Combined
Average
Drilling Drill Daily
Fluids Cuttings Discharge
Gulf of Mexico
Mid-Atlantic
Mid-Atlantic
116 •
155
190-219
Lower Cook Inlet,
Alaska 93-203
Tanner Bank,
California
33-50
47
33
35
27-47
7-22
163
188
225-254
120-150
40-72
Source: 12
VII-27
-------
TABLE VII-6
BASIC DRILLING FLUID ADDITIVES USAGE VERSUS DEPTH OF WELL
(Depth > 9,000 feet)
Materials Used (Tons)
Depth
(Thousands Total
of feet) Additives Barite
H
M
1
ro
09
9.8
10.4
10.6
11.0
11.1
13.4
13.5
16.3
18.6
19.5
21.1
713
683
720
295
832
1,176
1,148
1,567
1,S25
1,973
1,728
603
511
608
239
732
1,079
977
953
1,660
1,798
1,078
Clays
42
117
31
38
47
49
84
454
58
59
387
Lignosul-
fbnates
14
12.6
29
6.3
24
21
40
48
46
50
41
Cellulosic
Lignites Polymers
14
3.4
23. 7
2.5
13.6
2.5
16.1
51.7
2.5
2.5
40.7
0
2.6
2.4
1.5
1.1
5.4
1.7
4.7
14.6
15.6
9.4
Caustic Soda Ash.
(NaOH) Bicarbonate
39.3
35.1
25.1
6.4
14.7
16.8
28 . 3
55.2
41.5
45.0
140
0.3
1.5
0.5
1.3
0
2.3
0.6
0
2.8
2.8
31.4
Source: 11
-------
For purposes of costing, EPA developed average volumes of
drilling waste based on average well depths (see Section XIII).
The average quantities are developed on a per well basis (as
opposed to daily basis) to obtain net figures. Table VII-7
presents model volumes of drilling waste generated per well depth
per drilling region. As shown, average mud volumes range from
6047-9476 bbls per well.
A distinction should be made between the amount of material
used and the amount of material discharged. Some drilling fluid
is lost to the geologic formations or left in the well annulus at
the completion of drilling. Ayers, et al.7 presented a materials
balance estimate of drilling fluid components used in a Mid-
Atlantic drilling operation. Of the 866 metric tons (955 tons)
of barite used, 87% was discharged, 6% was left downhole, and 7%
was unaccounted for. For bentonite plus drilled solids, 89% was
discharged, 1% was left downhole, and 10% was unaccounted for.
For the combined usage of lignite and chrome lignosulfonate
andcellulose polymer, 95% of the material was discharged and 5%
was unaccounted for. The amounts that are unaccounted for are
presumed to be lost to the formations and left downhole.
g) Composition
The Agency initiated a program for the 1985 relemaking to
evaluate the characteristics of water-based muds. During this
program, eight mud types were selected to represent all water-
based muds, exclusive of specialty additives, used on the outer
continental shelf. Laboratory-prepared muds based on these eight
generic formulations were sent to EPA for analysis. These eight
generic mud types are described in Table VII-8.11 Toxicity tests
and analyses on oil content, BOD, COD, TOC, and priority
pollutants were conducted for each mud type. Results of chemical
and physical analyses15 are summarized in Table VII-9.
VII-29
-------
TABLE VII-7
AVERAGE WELL DEPT.H AND DRILLING WASTE VOLUME
Region
Well Depth (ft)
Waste Volume (bbls)
(rimds/cuttings/total)
Gulf of Mexico
California
Alaska
Atlantic
10,523
7,911
8,922
14,874
6926/1471/8397
6047/1262/7309
6385/1345/7730
9476/2577/12053
Source* 13
VII-30
-------
TABLE VII-8
EPA GENERIC'.DRILLING FLUIDS LIST
Type of Fluid
Base
Components
Typical Concentration
Range (Ib/bbl)
1.
Potassium/
Polymer mud
Caustic Soda
Barite
Cellulose Polymer
Drilled Solids
Potassium Chloride
Seawater or Fresh Water
Starch
Xanthan gum
0.5 - 3
0.0 - 450
0.25 - 5
20.0 - 100
5.0 - 50
As needed
2.0 - 12
0.25 - 2
2. Seawater/
Lignosulfonate
Mud
3. Lime Hud
Nondispersed
Hud
Spud Hud
(slugged
intermittently
with seawater)
Attapulgite or Bentonite
Barite
Caustic Soda
Cellulose Polymer
Drilled Solids
Lignite
Lignosulfonate
Seawater
Soda Ash/Sodium Bicarbonate
Barite
Bentonite
Caustic Soda
Drilled Solids •
Freshwater or Seawater
Lignite
Lignosulfonate
Lime
Soda Ash/Sodium Bicarbonate
Acrylic Polymer
Barite
Bentonite
Drilled Solids
Freshwater or Seawater
Attapulgite or Bentonite
Barite
Caustic Soda
Lime
Seawater
Soda Ash/Sodium Bicarbonate
10
25
1
0
20
1
' 2
•
•
•
•
•
•
•
0
0
0
25
0
0
0
-
50
450
5
5
100
10
15
As needed
0.0 - 2
25.0 - 1BO
10.0 - 50
1.0 - 5
20.0 - 100
As needed
0.0 - 10
2.0 - 15
2.0 - 20
0.0 - 2
0.5 - 2
25.0 - 180
5.0 - 15
20.0 - 70
As needed
10.0 -
0
0
50
0 - 50
0 - 2
0.5 -
1
As needed
0.0 - 2
VII-31
-------
TABLE VII-8 (Continued)
EPA GENERIC •.DRILLING FLUIDS L T
Base Typical Concentration
Type of Fluid Components Ranqe (Ib/bbl)
6. Seawater/Fresh- Attapulgite or Bentonite
Water Gel Mud Barite
Caustic Soda
Cellulose Polymer
Drilled Solids
Lime
Seawater or Fresh Water
Soda Ash/Sodium Bicarbonate
7. Lightly Treated Barite
Lignosulfonate Bentonite
Fresh Water/ Caustic Soda
Seawater Mud Cellulose Polymer
Drilled Solids
Lignite
Lignosulfonate
Lime
Seawater to Fresh Water Ratio
Soda Ash/Sodium Bicarbonate
8. Lignosulfonate Barite
Fresh Water Mud • Bentonite
Caustic
Cellulose Polymer
Drilled Solids
Fresh Water
Lignite
Lignosulfonate
Lime
Soda Ash/Sodium Bicarbonate
10.0
0.0
0.5
0.0
20.0
0.0
- 50
- 50
3
- -2
- 100
- 2
As needed
0.0
0.0
10.0
1.0
0.0
20.0
0.0
2.0
0.0
1:1
0.0
0.0
10.0
2.0
0.0
20.0
2
- 180
- 50
3
2
- 100
4
6
2
approx.
2
- 450
- 50
5
2
- 100
As needed
2.0
4.0
0.0
0.0
- 10
- 15
2
2
Source: 14
VII-32
-------
TABLE VII-9
CONVENTIONAL PARAMETERS FOR GENERIC DRILLING FLUIDS
Generic
Mud
No. Type of Mud
1
2
3
4
5
6
7
§ «
1
w 2-01
2-05
2-10
8-01
8-05
8-10
KCL Polymer Mud
Seawater Llgnosul-
fonate Mud
Lime Mud
Non-dispersed Mud
Spud Mud
Seawater/Freshwater
Gel Mud
Lightly Treated
Llgnosulfonate Mud
Llgnosulfonate
Freshwater Mud
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.
Weight BOD-5 BOD-5 UOD-20 UOD-20
Loss ACT POLY ACT POLY
(103C) In SOW In SOW In SOW In SOW
pH Density mg/kg(a) mg/kg(b) mgflcgfb) mg/kg(b) mg/kg(b)
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
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
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
1813
1483
1657
<50
<50
181
1470
1530
1416
3416
1558
1373
2207
1423
2037
1373
2743
10
9
216
1386
1393
2223
2157
1877
2383
2023
1633
4223
2717
3207
136
160
130
2187
2413
4073
8340
9273
4423
9773
7863
3407
2330
3963
286
124
285
1733
1980
5803
7473
6190
4297
6940
6497
TOC
mg/kg(c)
3.040
15.000
15.000
1.220
100
686
5.650
14.200
15.900
26.300
36.500
13.400
20.800
24.200
Oil and Oil and
Grease Grease
Ext. and Soxhlet
COD Bonification Extraction
mg/kg(b) mg/kg(b) mg/kb(a)
8.000
39,900
41.200
4.200
420
1.800
15.200
34.900
46.100
98,300
144.000
53.800
75.300
99.600
532
1.270
796
520
597
661
1.710
1.400
2.730
11.700
14,800
1.990
7.080
12.300
4.860
2.750
1.240
1.820
140
672
572
7.380
2.400
23.400
40.400
2.560
7.670
2.800
AH data wet weight, (a) Average of duplicates, (b) Average of triplicates, (c) Average of three triplicates
Source: 15
-------
Biochemical oxygen demand (5-day) and ultimate oxygen demand (20--
day) tests were performed with activated seed (ACT) and polyseed
(POLY) in artificial seawater (SOW). Oil and grease analyses
were conducted by Bonification and extraction and by soxhlet
extraction methods.
In addition to these eight mud types, two muds were spiked
with varying amounts of mineral and'diesel oils. The two mud
types selected for testing were those most often used in drilling
situations requiring additives. Analyses of these are also shown
in Table VII-9.
Static sheen tests15 were conducted on the generic muds
using the proposed methodology presented in the 1985 proposal.
Free oil was not detected in any of the eight base formulations
not containing oil additives. Sheen tests were also conducted on
water-based muds containing various amounts of mineral and diesel
oil. Both mineral and diesel additions were found to causesheens
on test waters. However, water-based muds with diesel spikes
produced sheens at spiking concentrations as low as 1% by volume.
Analytical results for organics and metals15 are summarized
in Tables VII-10 and VII-11. None of the organic priority
pollutants were detected in any of the water-based generic
drilling fluid formulations using gas chromatography/mass
spectrometry methods. Several priority pollutants were detected
in the muds spiked with oil. Atomic absorption spectrometry was
used for metals analyses with a combination of flame, graphite
furnace, and cold vapor techniques. A total of 10 of the 13
metals on the priority pollutant list were found in detectable
quantities in the generic formulations. Cadmium and mercury, in
particular, were present in all muds tested, but at levels below
1 mg/kg each.
VII-34
-------
TABLE VII-10
ORGANIC POLLUTANTS DETECTED IN GENERIC DRILLING FLUIDS
Cone, in ug/kg (all base neutral fraction)
Generic
Hud
No. Type of Mud
1 KCL Polymer
2 Seawater Lignosul-
fonate Mud
3 Lime Mud
4 Non-dispersed Mud
5 Spud Mud
6 Seawater/Freshwater
Gel Mud
7 Lightly treated
Lignosulfonate Mud
8 Lignosulfonate
Freshwater Mud
2-01 Mud 2 + 1% Vol. 1060
Mineral Oil
2-05 Mud 2 + 5% Vol. 8270
Mineral Oil
2-10 Mud 2 + 10% Vol. 19300
Mineral Oil
8-01 Mud 8 + 1% Vol.
Mineral Oil
8-05 Mud 8 + 5% Vol. 5580
Mineral Oil
8-10 Mud 8 + 10% Vol. 11100
Phenen- Dibenzo-
thrane furan
827
1040
N-Dodecane Diphenyl-
C-12 amine Biphenyl
899
809
819
854 (822)
847 (802)
736
780
726
6540
13300
4280
867
2290
933
9380
8720
5200
1120
Source: 15
VII-35
-------
I
LO
TABLE VII-11
METAL CONCENTRATIONS IN GENERIC DRILLING FLUIDS
Generic
Mud
No. Type of Mud
1
2
3
4
5
6
7
6
2-01
2-05
2-10
8-01
8-05
8-10
KCL Polymer Mud
Seawater Llgnosul-
fonate Mud
UmeMud
Non-dispersed Mud
Spud Mud
Seawater/Preshwater
Gel Mud
Lightly Treated
Llgnosulfonate Mud
Llgnosulfonate
Freshwater Mud
Mud 2 + 1% Vol.
Mineral Oil
Mud 245% Vol.
Mineral Oil
Mud 2 + 10% Vol.
Mineral Oil
Mud 8 + 1% Vol.
Mineral Oil
Mud 8*5% Vol.
Mineral OH
Mud 8 4 10% Vol.
Zn Be Al Ba
mg/kg mg/kg mg/kg mg/kg
Flame (a) Flame (a) Flame (a) Flame (a)
26.20
42.40
37.00
35.90
8.68
3.28
2.26
90.40
43.40
40.80
46.00
86.80
66.60
77.80
<1.0 190
<1.0 1.150
<1.0 743
<1.0 876
<1.0 347
<1.0 536
<1.0 395
<1.0 1,150
<1.0 1.200
<1.0 1.400
<1.0 955
<1.0 988
<1.0 862
<1.0 857
246.0
74.0
41.2
286.0
293.0
65.4
408.0
54.6
71.3
144.1
47.5
1.240.0
27.0
39.5
Fe Cd Cr
mg/kg mg/kg mg/kg
Flame (a) Flame (a) Flame (a)
1,890
2,860
2.170
1.120
833
392
660
5.110
2.520
3.350
2.800
4,980
3.940
5.020
0.220
0.472(b)
0.378(0)
0.446(0)
0.740(0)
0.420(0)
0.142(0)
0.36
0.395(b)
0.71 7(b)
0.470(0)
0.18
0.28
0.36
<3.0
764
908
<3.0
<3.0
<3.0
299
770
740
720
640
610
541
560
Cu
mg/kg
Flame (a)
3.96
27.50
40.60
6.78
1.61
0.70
2.86
72.20
26.80
26.00
26.10
68.90
77.30
42.80
Nl Pb Hg
mg/kg mg/kg mg/kg
name (a) Flame (a) Flame (a)
<6.0
<6.0
<6.0
<6.0
<6.0
<6.0
<6.0
<6.0
7.76
9.80
6.98
<6.0
<6.0
<6.0
7.74
1.82(b)
1.42(b)
41.20
52.50
1.53(b)
17.80
6.63
6.20 '
1.1 7(b)
24.50
13.00
9.48
0.2610
0.2640
0.7530
0.4370
<0.010
0.2970
0.0961
0.3550
0.1070
0.0910
0.0720
0.3910
0.3680
0.2870
(a) Dry weight basis, average of two samples
(b) Samples run by graphite furnace
(c) Single analysis
Source: 15
-------
TABLE VII-11 (Continued)
METAL CONCENTRATIONS IN GENERIC DRILLING FLUIDS
Generic
Mud
No.
1
2
3
4
5
6
7
8
2-01
2-05
2-10
8-01
8-05
8-10
Type of Mud
KCL Polymer Mud
Seawater Ugnosul-
fonate Mud
Ume Mud
Non-dispersed Mud
Spud Mud
Seawater/Freshwater
Gel Mud
Lightly Treated
Llgnosulfonate Mud
Ugnosulfonate
Freshwater Mud
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.
mg/kg
Furnace (a)
0.089
0.126
0.314
0.228
<0.060
<0.060
•C0.060
0.244
0.110
0.124
0.110
1.390
1.110
1.140
AS
mg/kg
Furnace (a)
4.640
2.400
17.200
5.250
0.258
0.621
0.497
11.700
1.470
1.700
1.970
12.200
9.610
9.240
Se
mg/kg
Furnace (a)
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
<3.0
Sb
mg/kg
Furnace (a)
4.000
0.260
1.060
0.473
<0.060
<0.600
<0.060
0.794
0.239
0.522
0.160
2.650
2.700
2.020
Tl
mg/kg
Furnace (a)
0.078
0.201
0.129
0.114
<0.060
<0.060
<0.060
0.071
0.175
0.184
0.166
0.080(C)
0.074
0.062(C)
(a) Dry weight basis, average of two samples
(b) Samples run by graphite furnace
(c) Single analysis
Source: 15
-------
Bioassay results16 indicate that the acute toxicity of the
generic muds range considerably. No median effects (50%
mortality) were observed for three of the eight mud types,
whereas the most toxic, was found to be the potassium polymer mud.
•
Its suspended particulate phase showed a 96-hour LC50 of 3% by
volume, as measured by the proposed bioassay test method
described in Appendix 3 of the regulation to the 1985 proposal.
A summary of bioassay results is presented in Table V-12.
Drilling fluid toxicity was found to increase with the
addition of mineral oil, but to a lesser extent than with diesel
oil additions. These findings are consistent with results of
other research activities conducted at EPA's Environmental
Research Laboratory in Gulf Breeze, FL.* And, as the DPMP study
(Section VI.C.4) shows, mud toxicity levels are related much more
to diesel content than to mud type.
The Gulf of Mexico Operators Committee conducted a study in
1984 which examined the composition of mineral and diesel mud
additives.18 Data obtained from this QOC study are summarized in
Table VII-13. GC/MS analyses of diesel additives show the
presence of organic priority pollutants, including benzene,
ethylbenzene, naphthalene, fluorene, phenanthrene, and phenol.
Limited analyses of mineral oils also show the presence of
organics, including benzene, naphthalene, phenanthrene, and
fluorene.
More recently, a corpilation of EPA and industry data was
completed in 1990 which charact rized metals content in barite
drilling fluids and drill cuttings (see Section VI.C.4). An
analysis of this data base was performed in 1990 to characterize
metal content in commercially available water-based drilling
fluids.19 Table VII-14 shows the results of this analysis.
VII-38
-------
TABLE VII-12
RESULTS OF ACUTE TOXICITY TESTS WITH
GENERIC DRILLING FLUIDS AND KYSIDS (KYSIDQPSIS BAHIA^
Definitive Test (a)
LC.. & 95% CD
Positive Control (a)
(96-H LC.. & 95% CU
Definitive Test (b)
(96-H LC.-& 95% CD
EFA/ORD,
Gulf Breeze
EPA/ORD,
Narragansett
1
2
3
4
5
6
7
8
1
5
2.7% SPP (c)
(2.5-2.9)
51.6% SPP
(47.2-56.5)
16.3% SPP
(12.4-20.2)
12% mortality
In 100% SPP
12% mortality
In 100% SPP
20% mortality
In 100% SPP
65.4% SPP
(54.4-80.4)
29.3% SPP
(27.2-31.5)
2.8%
(2.5-3.0)
No mortality In
100% SPP
•
5.8 ppm (d)
(4.3-7.6)
7.5 ppm
. (6.9-8.1)
7.3 ppm
(6.6-8.1)
3.4 ppm
(2.8-4.1)
Same as for #1
6.0 ppm
(5.4-6.6)
Same as for #6
Same as for #3
6.2 ppm
(4.4-11)
3.3 ppm
(2.6-3.8)
3.3% SPP
.(3.0-3.5)
62.1% SPP
(58.3-65.4)
20.3% SPP
(15.8-24.3)
--
--
--
68.2% SPP
(55.0-87.4)
30.0% SPP
(27.7-32.3)
--
--
o- Lethal concentration to 50% of test organisms
SPP - Suspended partlculate phase
CL - confidence limit
(a) Calculations by moving average; no correction for control mortality unless started.
(b) Calculation by SAS problt; correction for all control mortality. Analyses performed
by Clifton Bailey, U.S. EPA. Program Integration and Evaluation Staff (WH-586), Office
of Water Regulations and Standards, Washington, D.C. 20460
(c) The suspended partlculate phase (SPP) was prepared by mixing 1 part drilling fluid with
9 parts seawater. Therefore, these values should be multiplied by 0.1 In order to
relate the 1:9 dilution tested to the SPP of the whole drilling fluid.
(d) Corrected for 13% control mortality.
Source: 17
VII-39
-------
TABLE VII-13
ORGANIC CONSTITUENTS OF DIESEL AND MINERAL OILS.
Cone, in mg/mi, unless noted otherwise
Gulf of
Organic Mexico
Constituents Diesel
Benzene
Ethyl benzene
Naphthalene
Fluorene
Phenanthrene
Phenol (ug/g)
AUylated
benzenes (a)
AUylated
naphthalenes (b)
AUylated
fluorenes (b)
AUylated
phenanthrenes (b)
AUylated
phenols (ug/g) (c)
Total
bipnenyls (b)
Total dibenzo-
thiophenes (ug/g)
Aromatic
content (1)
ND
ND
1.43
0.78
UBS
6.0
8.05
75.7
9.11
11.5
52.9
15.0
760
23.8
Calif.
Diesel
0.02
0.47
0.66
0.18
0.36
ND
10.6
18.0
1.60
1.41
106.3
4.03
1200
15.9
Alaska
Diesel
• 0.02
0.26
0.48
0.68
1.61
1.2
1.08
25.2
5.42
4.27
6.60
6.51
900
11.7
EPA/API
Ref.
Fuel Oil
0.08
2.01
0.86
0.45
' 1.06
ND
34.3
38.7
7.26
10.2
12.8
13.5
2100
35.6
•
Mineral
Oil A
ND
ND
0.05
ND
ND
ND
30.0
0.2B
ND
NO
NO
0.23
ND
10.7
Mineral
Oil B '
ND
ND
NO
0.15
0.20
ND
ND
0.69
1.74
0.14
ND
5.57
370
2.1
Mineral
Oil C
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 pur-
pose of the general comparison and suanary presented above, the Alaska. California.
•nd Gulf of Mexico diesels are assumed to be representative of those used in offsnore
drilling operations.
NO • Not Detectable
(a) Includes Cj througn C& aUyl nomologues
(b) Includes Ci through C$ aUyl homologues
(c) Includes cresol and C£ through C< aUyl homologues
Source: 20
VII-40
-------
TABLE VII-14
METAL CONCENTRATIONS IN COMMERCIALLY AVAILABLE
WATER-BASED DRILLING FLUIDS
~~" Range of Mean Concentrations
Pollutant (mg/kg)*
AG 0.40-1.04
AL • 10,222-8,121.6
AS 7.13-17.65
BA 12,119-455,902
BE 0.92-0.56
BO 19.03-35.51
CA . 13,376-14,801
CD 0.32-3.10
CO 5.38-7.40
CR 344.51-830.98
CU 14.62-35.56
FE 13,611-14,991
HG 0.02-0.56
MG 3,044.8-4,812.3
MN 237.10-368.70
MO 1.12-12.11
NA 14,218-40,419
NI 12.61-13.98
PB 38.54-74.75
SB 5.39-5.59
SE 1.12-1.18
SN 2.22-26.69
TI 103.22-79.38
TL 0.88-1.80
V 14.20-19.71
Y 7.55-7.71
ZN 133.86-407.35
*Assumes that concentration is distributed lognormally.
Source: 19
VII-41
-------
2. Drill Cuttings
Drill cuttings are the.solid particles removed by the drill
and carried to the surface by the drilling fluid. Solids control
equipment operates continuously when the drilling rig is in
oper,; ion. Actual drilling accounts for about one-third to one-
half of tJ*f> time a drilling rig is on-site, Continuous and
frequent, intermittent discharges are normally generated by the
operation of solids control equipment. Such discharges occur for
periods of from less than 1 hour to 24 hours per day, depending
on type of operations and well conditions.
a) Volume
Typical sources and discharge rates are presented in Table
VII-15. Approximate quantities of drilled solids for typical
wells are presented in Tables VII-4 and VII-5.
In general, the bulk of the discharged material (about 2,000
bbl) is generated within the first 5,000 feet of drilling;
another 2,000 bbl are produced between 5,000 feet and 15,000
feet; by the 20,000 ft leve , discharges have increased by only
another 1,000 bbl to a tota^ of 5,000 bbl.11 This is because the
diameter of the bore hole decreases with depth, resulting in
lower volumes of drill cutting-, requiring removal. The average
daily discharge also decreases with depth because drilling slows
down as depth increases.
Table VII-7 lists average cuttings generated per well.
These volumes were used as me 5.1 parameters for costing (see
Section XIII). Volumes are generally below the 5,000 bbl total
cited above because the average well depths are shallower.
Average cutting volumes are presented in this table as ranging
from 1262-2577 bbls per well.
VII-42
-------
TABLE VII-15
SOURCES, DISCHARGE RATES, AND DISCHARGE FREQUENCY OF
CONTINUOUS^DISCHARGES FROM A SINGLE WELL LOCATED
IN LOWER COOK INLET, ALASKA
(Atlantic Richfield Company, 1978)
Source
Rate (bbl/hr)
Frequency
Shale shaker
Desander
Desilter
Centrifuge
Sand trap
Sample trap
1-2
3
16-17
30
550-2650
1.5-3
Continuous during drilling
2-3 hr/day during drilling
2-3 hr/day during drilling
1-3 hr; every 2-3 days
2-10 min. every 2-3 days
5-10 min. every 2-3 days
Source: 12
VII-43
-------
b) Composition
Drill cuttings themselves are generally inert particles.
However, drill cutting discharges also contain drilling fluids
and their discharge composition is dependent.upon fluid used.
Cuttings associated with hydrocarbon base drilling fluids or from
petroleum bearing formation adsorb a film of oil on the particle
surfaces. This film is bound to the particle by the polar forces
of oil molecules and resists removal by washing operations.
3. Produced Water - BPT Effluents
Produced water is a combination of the formation waters that
existed prior to development plus any other fluids and chemicals,
such as drilling, treatment, enhanced recovery., and oil
separation agents, that have become mixed during the petroleum
production process. Chemicals that may be added during
production, and that may be present in produced water discharges,
include: biocides, coagulants, corrosion inhibitors, cleaners,
detergents, dispersants, emulsion breakers, paraffin control
agents, reverse emulsion breakers, and scale inhibitors. The use
of these chemicals varies substantially from platform to
platform. This section focuses on the concentration of
pollutants from BPT treated produced waters.
a) Volume
Produced water is the highest volume waste source in the
offshore oil and gas industry. The volume of wastewater
generated by this industry is somewhat unique when compared to
most other industries for which wastewater generation is directly
related to the quantity or quality of raw materials processed.
By contrast, produced water (principally formation water) can
constitute from 2% to 98% of the gross fluid production at a
VII-44
-------
given platform. In general, produced water volume is small
during the initial production phase and increases as the
formation approaches hydrocarbon depletion. Also, produced water
volumes are much greater for oil and for oil and gas structures
•
than for gas-only platforms. Historically, over the life of a
producing formation, approximately equal volumes of water and
hydrocarbons will be produced. However, there are also instances
in which no formation water is ever encountered and others for
which an extensive amount of formation water is encountered at
the start of production. Therefore, the volume of produced water
at a given platform can be viewed as a highly site-specific
natural phenomenon.
According to Walk, Haydel and Associates (1984), the average
produced water discharge rate from an offshore platform usually
is less than 1,800 bpd, whereas discharges from large facilities
handling produced water from many platforms may be as high as
157,000 bpd.22
i (
The three facilities sampled during the three facility study
ranged anywhere from 10,000 bbl/day to 90,000 bbl/day of produced
water production (see Table IX-7, which presents characteristics
of the three facilities). It is important to note that volumes
not only vary with location and well type, but with numbers of
wells per platform. The 90,000 bbl/day platform has three wells
associated with it, although this volume of produced water is
still relatively high. Produced water volumes (brines) are also
presented in Table VII-16, which lists characteristics of the
platforms sampled in the 30-facility study. Volumes range from 2
to 150,000 bbl/day.
EPA estimated average produced water volumes for the
development of model platforms (for costing purposes). These
model characteristics are presented in Section XIII, but the
VII-45
-------
TABLE VII-16
CHARACTERISTICS OF PLATFORMS SELECTED
FOR THE GULF OF MEXICO SAMPLING PROQRAM
Number Platform
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
26
29
30
EC 33*
EC 14CF
V 1190
V 25 5 A
SMI 23B
V 39D
SMI 6A
El 57A-E
SMI 115A
El 120CF
SMI 130B
El 208B
El 18CF
El 238A
El 296B
SS 107(594)
SS 107(593)
SS 219A
ST 177
BM 2C
BDC CF5
ST 135
WD 90A
WD 45E
WD 701
GIB DB600
WD 105C
SP 62A
SP 24/27
SP 65B
Company
Conoco
Mobil
Conoco
Shell
Gulf
Shell
Exxon
Marathon
Shell
Mobil
Shell
Conoco
Shell
Gulf
Placid
Chevron
Chevron
Amoco
Gulf
Shell
Texaco
Gulf
Amoco
Conoco
Conoco
Texaco
Shell
Shell
Shell
Shell
Oil /Con -
dencate
(bbl/d) '
76.6
807
890
950
228 .
395
250
1200
750
3500(1)
21500
1501
2000
40
1500
501
2875
3000 .
2800
10794
873
6000
2244
745
5273
554
2091
1800
24000
5000
Gas
(MMCF/d)
15.2
13.1
3.4
14
13.8
38
0.2
150
45
51 1 )
63
0.2
30
6
100
1.2
5.0
7
10
11.7
2.8
18
10.7
2.3
15.5
0.1
12.1
1.3
40
8
. Brine
•(bbl/d)
62
2005
2817
1298
495
634
625
500-2000
1200
2000( 1 )
9733
350
22000
2
1470
4610
12500
800-1000
1072
6590
11028
8400
15000
1578
10721
3796
7532
3100
150000
3000
Treatment (2)
OS and DXSS
OS
OS and DXSP
DXSP
OS and DXSP
OS and DXSP
OS'
OS
OS and DISP
OS and DISS
OS and DISP
DXSP
OS and DXSS
DXSP
OS and DXSS
DXSP
DXSP
OS
DXSP
OS and DISP
OS and DXSP
DXSP
OS and DXSP
DXSP
DXSP
OS and DXSP
DXSP
OS and DISS
OS and DXSP
OS and DISP
(1> Value for Sampling Period
(2) os . QH Skimming; OXSS • Dissolved Gas Flotation;
DXSP » Dispersed Gas Flotation
VII-46
-------
model produced water volumes are specifically listed here in
Table VII-17. Produced volumes range from 68 to 50,718 bbls/day.
b) Composition
t
This section presents produced water effluent
characteristics after BPT Treatment. Data from the 30-platform
study are presented here. The term "treated effluents" is used
as a baseline from which the need for additional BAT or NSPS
treatment (the focus of this rulemaking) is investigated.
Baseline represents effluents from platforms permitted under the
existing permit conditions at the time of sampling. These
effluents may represent BPT or more stringent control according
to permit conditions.
Because the 30-platform study does not include data from
Alaska, a separate section presenting data from this area is
included also.
During the period October 9-30, 1981, 30 oil and gas
production platforms located in the Gulf of Mexico were sampled
to characterize the quantities of selected conventional, non-
conventional and priority pollutants present in their produced
brine discharges.23 Table Vll-16 presents the production
characteristics of the 30 sites selected. Overall, 79 individual
samples were collected and analyzed. Pollutants analyzed were
the priority organics, chloride, iron, oil and grease, TDS, and
certain metals, namely, cadmium, chromium, copper, lead, nickel,
silver, and zinc. Twenty of the 79 samples collected were
obtained from the influent to the platform treatment systems
while the remaining 59 were treated effluent samples. Table VII-
18 presents an overall summary of occurrence of the organic
VII-47
-------
LOCATION/
STRUCTURE TYPE*
TABLE VII-17
AVERAGE PRODUCED WA7, VOLUMES FOR MODEL STRUCTURES
MAXIMUM FLOW - PRODUCED WATER (bbls/day)
TOTAL NUMBER OF
PRODUCING WELLS
PER STRUCTURE
OIL
OIL AND GAS
GAS
Gulf
Gulf
-------
TABLE VII-18
PERCENT.OCCURRENCE OF ORGANICS
FOR TREATED EFFLUENT SAMPLES
GULF-,OF MEXICO SAMPLING PROGRAM
PARAMETER ( 1 )
Benzene
Ethylbenzene
Naphthalene
Phenol
Toluene
2 , 4-Dimethylphenol
Bis (2-Ethylhexyl) Phthalate
Di-N-Butyl Phthalate
Fluorene
Diethyl Phthalate
Anthracene
Acenaphthene
Benzo(A) Pyrene
P-Chloro-M-Cresol
Dibenzo (A,H) Anthracene
Chlorobenzene
Di-N-Octyl Phthalate
3 , 4-Benzof luoranthene
1 1 , 12-Benzof luoranthene
Pentachlorophenol
1 , 1-Dichloroethane
Bis (2-Chloroethyl) Ether
NUMBER OF(2)
VALID
DETERMINATIONS
59
59
59
58
59
56
59
59
59
59
29
59
59
59
59 -
59
59
59
59
59
59
59
NUMBER
OF TIMES
DETECTED
59
59
59
58
59
52
47
19
• 13
12
3
4
3
1
1
1
1
1
1
1
1
1
PERCENT
OF TIMES
DETECTED
100
100
100
100
100
93
80
32
22
20
10
7
5
2
2
2
2
2
2
2
2
2
(1) -Pollutants not listed were never detected
(2) - Number of samples which yielded valid analytical results
Source: 23
VII-49
-------
priority pollutants detected in the effluents. As can be seen
from this table, benzene, ethylbenzene, naphthalene, phenol,
toluene," 2,4-dimethylphenol, and bis-(2-ethylhexyl) phthalate
were observed in 80% -sr more of the effluent samples analyzed.
»
An additional 15 organics were detected far less frequently. The
occurrence for these parameters ranged from 2% to 32% of the
effluent samples analyzed. Many were either at or just above the
detection limits.
The 30-platform data were used to support the proposed
rulemaking for the 1985 proposal. EPA, for the current
rulemaking, has performed a recomputation of the data to reflect
updated statistical procedures.25 Specific reasons for the
reanalysis are as follows:
• Concentration values for metals were previously
calculated without reference to detection limits. The
values reported in Table VII-19 treat sample values
reported below the detection limit to be zero.
• Duplicates were previously treated as individual
samples. However, distinctions should have been made
where "duplicate" samples are those split at the sample
site and "replicate" samples are those split at the
lab. For this reanalysis, where duplicate samples were
taken, the value for an independent sample is the
arithmetic average of the values for each duplicate.
Furthermore, the value for a duplicate, or an
independent sample that does not have a duplicate, is
the arithmetic average of the replicate analyses if
replicate analyses were performed.
Table VII-19 presents the results of the recomputation of
pollutant concentrations from the 30-platform study. This study
illustrates baseline effluent characteristics achievable by BPT
technology. Effluent concentrations are shown for each type of
platform: 91!-, gas-, or oil and gas producing. Also shown in
Table VII-19 are flow weighted averages for each pollutant.
VII-50
-------
TABLE VII-19
BPT* EFFLUENT CONCENTRATIONS FOR PRODUCED WATERS
(Reanalysie of 30-Platform Study)
MEAN CONCENTRATION
POLLUTANT
GAS
OIL
OIL AND GAS
FLOW
WEIGHTED
AVERAGE*
Oil and grease (mg/L)**
Priority Oreanics (mg/L)***
Benzene
Bis(2-ethylhexyl)phthalate
Ethylbenzene
Naphthalene
Phenol
Toluene
2,4-dimethylphenol
Priority Metals (ug/L)***
Cadmium
Copper
Lead
Nickel
Silver
Zinc
28.42
79.16
92.13
89.8
6049.31
100.50
735.61
409.94
7456.19
4964.61
720.11
931.32
30.68
66.02
90.09
913.96
692.85
0**
1796.58
105.55
533.03
135.86
814.23
1533.34
0
1823
101
505
138
954
1545
14.4
0
0
0
0
0
153.50
0
106.74
0
149.97
58.93
132.77
32.18
193.16
384.40
145.22
60.50
2574.05
29.35
183.42
350.57
142.64
59.19
2360
*Based on gas flotation or gravity separation.
**SAIC memo to EPA, 'Estimated Effluent Means for Oil and Grease from the
Produced Waters 30 Platform Study," 9/29/90.
***EPA memo, "Long-Term Averages for Analyte Concentrations in the Proposed
Offshore Oil and Gas Regulations." 9/20/89.
*ERCE memo to file "Produced Water - Determination of Aggregate Contaminant
Levels in BPT Treated Effluent," Nov. 21, 1990.
**"0"s refer to number of samples above the detection limit.
VII-51
-------
These averages were calculated by weighting the pollutant
concentration for each well type with the modeled produced water
flow associated with each type. (Produced water flow rates can
be found using information in Section XIII.)
*
There are two major oil and gas producing fields in Alaska:
one is offshore in Cook Inlet (Kenai Peninsula) and the other is
onshore in Prudhoe Bay on the North'Slope of the Books Range.
Two operating sites in Cook Inlet were sampled prior to the 1985
proposal - one treated produced water on the platform and the
other onshore.26 Data obtained from this study are included in
the 1985 development document. The Prudhoe Bay facility
reinjects all produced water; thus, treatment of produced water,
in the conventional sense, is not provided.
More recent data have been obtained on Cook Inlet since the
1985 proposal. A comprehensive Cook Inlet Discharge Monitoring
Study was conducted by Region X to investigate oil and gas
extraction discharges.27 These discharges were meeting NPDES BPT
requirements and were sampled and analyzed over a period between
September 1988 - August 1989. Samples were collected from two
oil platforms and one gas platform, all of which discharge
directly to the inlet, and also from three shore-based central
treatment facilities. Table VII-20 presents averages of effluent
concentrations from these six facilities.
4. Well Treatment. Completion, and Workover Fluids
The volumes and constituents of well treatment and workover
fluids are well-specific, and the discharge frequency varies
between locations. A review of a Gulf company's Discharge
Monitoring Reports found that well treatment fluids are
discharged at a rate of 1283 bbl/discharge and that, generally,
there was only one discharge per workover job.6
VII-52
-------
TABLE VII-20
ARITHMETIC MEAN EFFLUENT PRODUCED WATER
CONCENTRATIONS FOUND IN COOK INLET
POLLUTANT COMPOSITION
Oil and grease (mg/L) 30.3
TOC (mg/L) " 389.0
Priority Pollutants (ug/L)
Benzene 7,452
Toluene 3,326
Ethylbenzene 311
p & m xylenes 952
0-xylene 521
2,4-dimethylphenol 293
Phenol 825
Naphthalene 1,150
Acenaphthalene 335
Zinc 719
Source: 27
VII-53
-------
A comprehensive study was performed by Region X on these
fluids being discharged in Cook Inlet, Alaska from April-
September, 1987.2B A total of 10 workover, completion, or
treatment fluid jobs were sampled. Individual discharges in this
*
study have been estimated to range from 12 bbls/day to 1,800
bbls/day. Table VII-21 lists the chemical quality of fluids
discharged in the Cook Inlet, Alaska. Table VII-22 shows the
hazardous compounds (as determined by material safety data
sheets) discharged with well treatment, workover, and completion
fluids in this same Cook Inlet study.
Static sheen tests were also compared to oil and grease
analyses in the Cook Inlet study. Oil sheens were not observed
in any of the discharges, however, oil and grease concentrations
ranged from 0.1 to 1,420 mg/L.
Additional data on well treatment fluids were obtained from
one facility in the three-facility study. A sample of a well
being acidized for production enhancement at the coastal facility
was analyzed and results are presented in Table VII-23.
5. Produced Sand
Literature indicates that typical produced sand discharge
rates for the Gulf Coast range from 25 to 250 bbl per day and, in
California, 2 kg per day.30 Another source states that the
amount of produced sand generated equals .05% (or 1 in 2000
barrels) of produced water flow.6 However, EPA discovered during
their three-facility study that all three facilities generated
virtually no sands during the 3-day sample visits. Actual
volumes of sand production experienced by- facilities depend upon
the characteristics of the producing reservoir, sand control
procedures utilized, and drawdowns experienced by the reservoir,
among other factors. Produced sand volumes are decreasing with
Table 7-21
VII-54
-------
TABLE VII-21
SUMMARY OF THE CHEMICAL QUALITY OF WORKOVER, COMPLETION, AND
WELL TREATMENT FLUIDS DISCHARGED IN THE COOK INLET, ALASKA
^ TYPE OF FLUID/JOB
POLLUTANT
pH (s.u.)
Mean
Min
Max
O&G (mg/L)
Mean
Min
Max
BOD (mg/L)
Mean
Min
Max
COD (mg/L)
Mean
Min
Max
TOC (mg/L)
Mean
Min
Max
Zinc (mg/L)
Mean
Min
Max
WORKOVER/
NON-ACID
7.00
6.90
7.10
10.25
0.34
21.00
151.50
3.40
400.00
715.00
236.00
1500.00
96.00
23.00
203.00
N/A
N/A
N/A
COMPLETION/
NON-ACID
7.80
7.10
8.50
3.20
0.20
6.10
57.00
6.00
100.00
727.50
590.00
865.00
47.00
4.00
90.00
N/A
N/A
N/A
WORKOVER/
ACID
7.30
7.20
7.60
15.33
12.00
21.00
645.00
600.00
668.00
1067.00
1010.00
1130.00
296.00
249.00
350.00
0.054
0.015
0.130
Source: 28
VII-55
-------
TABLE VII-22
CHEMICAL COMPOUNDS DISCHARGED "DURING WORKOVER, COMPLETION
AND WELL TREATMENT FLUID DISCHARGE EVENTS
Chemical Compound
Composition and/or MSDS Number
(Concentration)
A250
Clayfix (NH4C1)
Dirt Mac iet
EDTA
FDP-W396 Clay Stabilizer
FR26L
HAI 75 Corrosion Inhibitor
HC1
HF Acid
J347 Gel
KC1 Salt
LD-8 Defoamer
Liteplug Fine1
LiteplugX1
Litesal XCP
Losurf 300
Max Pac
MD
NaCl Salt
NH,NO3
pH 6 buffer
Soda Ash
Thermpac UL
XC
Substitued Amines, substituted
Alcohols, acetylenic
alcohol, isopropyl alcohol,
and formaldehyde (<9%)
Ammonium Chloride
Alkylalkanolamide
Ethylenediamine tetracetic
Acid (>60%)
Quanternary Polyamine (>60%)
Organic
Acetylenic Alcohols (30-60%);
Isopropanol (1-10%) :
Aromatic Naphtha (1-10%)
Hydrochloric Acid (30-60%)
Hydrofluoric Acid (60%)
Polysaccharide Derivative
Potassium Chloride
Fatty acid salt in an
alkoxylated alcohol (<.08%)
Borate (proprietary blend)
Borate (proprietary blend)
Borate proprietary blend
(contains Alkaline Borate
Salt)
Organc: Isopropanol (30-60%);
Heavy Aromatic Naphtha (10-
30%)
Ethyl Cellulose
Proprietary (Hazardous
ingredient: Ethylene glycol
Vapor) (30-40%)
Sodium Chloride
Ammonium Nitrate
pH 6 buffer (Proprietary)
Sodium Carbonate
Sodium caroxymethyl Starch
Xanthan Gum
1 Same compound but different grind (mesh) size.
VII-56
-------
TABLE VII-23
COMPOSITION OF .ACIDIZING TREATMENT FLUID
DURING THREE-FACILITY STUDY
POLLUTANT
Oil and Grease (mg/L)
PH
Aluminum (ug/L)
Antimony
Arsenic
Barium
Beryllium
Boron
Cd
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Yttrium
Zinc
Aniline
Naphthalene
O-toluidine
P-cresol
2-methylnaphthalene
2,4,5-trimethylaniline
CONCENTRATION
619.0
2.48
53.1
< 3.9
< 1.9
12.6
< 0.1
31.9
0.4
35.3
19.0
< 1.9
3.0
572.0
< 9.82
162.0
8.0
< 0.1
< 0.96
52.9
< 2.9
< 0.7
1640.0
5.0
6.66
0.68
36.1
0.19
28.5
434
ND
1852
ND
ND
2048
Source: 29
VII-57
-------
improved well packing methods. Gravel packing of the well will •
significantly reduce sand production becasue it is filtered out
in the packing media. • "
The material that generally is classified as produced sand
is a mixture of many different kinds of solids. The primary
component is sand (Si02) with varying amounts of mineral scale,
corrosion products, and other formation fines (clays, etc.). The
mineral scales that may be present include epsom salts (MgSOJ ,
magnesite (MgCO,), gypsum (CaSOJ, calcite (CaC03), barite
(BaSOJ , and celestite (SrS04). The corrosion products which may
be present include FeC03 and FeS.31 Which, if any, of these
materials may be present will depend upon the water chemistry and
the nature of the oil involved at a particular installation.
The primary pollutant of concern in produced sand wastes is
oil.
6. Deck Drainage
Recent data on untreated deck drainage collected by the
Agency comes from the three-facility sampling program conducted
during 1989. This information is shown in Table VII-24. Table
VII-25 shows the results of an earlier Agency study, included in
the 19c,j rulemaking, which utilized the data contained in
discharge monitoring reports from the Gulf of Mexico. These
data represent discharged (or treated) effluents. Also, in 1989,
EPA reviewed extensive records of deck drainage data provided by
API in the 1970s.31 The information provided by the API surveys
included records from over 30 facilities in the Gulf of Mexico
and California between 1974 and 1977. Deck drainage at these
facilities was monitored by field personnel for time periods
ranging from 6 days to 1 year. An analysis of data from this
VII-58
-------
TABLE VII-24
POLLUTANT CONCENTRATIONS IN UNTREATED DECK DRAINAGE
POLLUTANT
RANGE OF CONCENTRATIONS*
Temperature (°C) ^
Conventionals (mg/L)
PH
BOD
TSS
Oil & grease
Nonconvent iona1s
TOC (mg/L)
Aluminum (ug/L)
Barium "
Boron "
Calcium "
Cobalt "
Iron "
Magnesium "
Manganese "
Molybdenum "
Sodium "
Tin "
Titanium "
Vanadium "
Yttrium "
Priority Metals (ug/L)
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Silver
Thallium
Zinc
Priority Organics (ug/L)
Acetone
Benzene
M-xylene
Methylene chloride
N-octadecane (N-C18)
Naphthalene
O-P-xylene
Toluene
1,1-dichloroethene
20-32
6.6-6.8
<18-550
37.2-220.4
12-1310
21-
176-
2420-
3110-
98200-
< 20
830-
50400-
133-
151X10*
<30
4
*Ranges of four samples, two each,
in the three-facility study.
-137
-23100
-20500
-19300
-341000
-81300
-219000
-919
-20
568x10*
-2030
-92
-17
<4-<40
<2-<20
<1-1
<4-25
<10-83
14-219
<50-352
<4
<30-75
<3-47.5
<7
<20
2970-6980
ND-852
ND-205
ND-47
ND-874
ND-106
392-3144
105-195
ND-260
ND-26
at two of the three facilities
Sources: 29,31
VII-59
-------
TABLE VII-25
QUALITY AND QUANTITY OF DECK DRAINAGE FROM OFFSHORE RIGS
(GULF OF MEXICO); DATA SUMMARIZED FROM TWO TEARS OF
DMR6 (NUMBER OF SITES IN PARATHENSES)
Quality
(reported as oil and grease in ing/I)
Monthly Average Daily Maximum
Range Average _ Range Average
1981-82 5-47 22 19 - 72 51
(19) (19) (19) (19)
1982-83 2 - 183 28 5 - 1363 75
(117) (117) (117) (117)
Quantity (BBl/day)
1981-82 0 - 4276 65 0 - 4700 106
(425) (425) (425) (425)
1982-83 0 - 4204 50 0 - 9698 90
(950) (950) (945) (945)
Source: 32
VII-60
-------
study showed that the oil and grease concentration of discharged -
deck drainage ranged from 1 ppm to 673 ppm, while the volume
ranged from 1 bbl to 440 bbls per incident.6 (Influent oil and
grease values ranged-from 1-16,908 ppm.) Both the Agency's data
gathering efforts and API's survey information indicate that the
frequency, volume, and content of deck drainage is highly
variable. The data also indicate that the oil and grease content
of deck drainage may, at times, greatly exceed the discharge
limits of produced water.
The oil in deck drainage may be present either due to the
washing solutions themselves or to oil on the deck. In addition
to oil, various other chemicals may be present in deck drainage.
Virtually any chemical used on offshore rigs or production
platforms may be found in deck drainage at one time or another.
Table VII-26 is a partial list of hazardous compounds which may
be present in deck drainage. This list was acquired through a
study conducted for Region X to determine deck drainage
characteristics of platforms in Cook Inlet, Alaska.
7. Sanitary and Domestic Wastes
Sanitary wastes are human body wastes from toilets and
urinals. The volume of these wastes vary widely with time,
platform characteristics, and operational situations. Sanitary
and domestic wastes may be reported together although they are
usually segregated on offshore platforms. Combined sanitary and
domestic waste discharge rates of 3,000 to 13,000 gallons per day
have been reported.34 Monthly average sanitary waste flow from
Gulf Coast platforms was 35 gallons per day based on discharge
monitoring reports.35 Tables VII-27 and VII-28 summarize the
volume and pollutant characteristics of sanitary wastes.
VII-61
-------
TABLE VII-26
JIDOUS COM? ^DS E CHARGED IN DECK DRAINAGE
Product -
B/B (3100) Turbine
Chemical Cleaner
Big Red
Cabot-166
Carboline 13 Cleaner
Penetone Citri-Clean
409 Spray
Ancol Chemlinfc CI-922
Altex Solvent 325
Devoe Devprep 68
Ethylene glycol
JCleen Flow
Corrizle Chemical
Kikro Quat
Nalclean 6900
Nalco 1111
Component
Naphtha .
Trade Secret A
Trade Secret B
None
None
None
t
Diethylene glycol monobutyl
ether
Ethanolamine
Methanol
Ethylene glycol nonobutyl
ether
Isopropyl alcohol
Cj
Trade secrete 14-01, 6114-02,
6114-03, 6114- j4
Paraffins
(includin naphthenes)
Aromatics
C.,
Benzene
Concentration
NL
<25 ppm
£25 ppm
6%
5%
NL
0.5-5%
NL
NL
NL
98%
2%
<0.02%
Lfonate salt
Ar^aatic
Silicate
Acid salt
Surfactant
Surfactant
Ethylene glycol
None
None
None
Sndium Hydroxide
Kethyl alcohol
Ethoxylated nonylphenol
90%
10-20%
20-40%
VI -62
-------
TABLE VII-26 (Continued)
HAZARDOUS COMPOUNDS DISCHARGED IN DECK DRAINAGE
Product
Nalco Visco 1175
Kalco Visco 1176
Nalco 4300
Nalco 7348
Kalco 8173
Nalco 8910
Nalco 945
Nalco Bleach
(Sunny Sol)
Component
Methyl alcohol
Potassium hydroxide
Sodium xylene sulfonate
Ethoxylated nonylphenol
Heavy aromatic hydrocarbon
solvent
Ethylene glycol
Tri-basic- sodium phosphate
None
None
Caustic compound
Zsobutanol
Sodium hypochlorite
Sodium hydroxide
Paint Thinner (Valspar) Naphtha
Petrolite FW-132
Petrolite XC-102
Rig Wash IPS
Rig Wash Roughneck
Stoddard Solvent
Tretolite TK-14
Tretolite TK-16
Tretolite TK-64
Methanol
Ammonium Bisulfite
Sulfur Dioxide
Glutaraldehyde
None
None
Naphtha
Heavy aliphatic naphtha
Heavy aromatic naphtha
Ethylene glycol
Zsopropyl alcohol
Methanol
Tetra sodium salt of EDTA
Heavy aromatic naphtha
Concentration
1-10%
1-10%
1-10%
1-10%
40-*-%
20-40%
NL
NL
10-20%
7.5-12.5%
.8%
100%
200-250 ppm
NL
0.5-5 ppm
25%
100%
15 ppm
25 ppm
1
400-500 ppm
200 ppm
NL
25 ppm
Source: 33
VII-63
-------
TABLE VII-27
TYPICAL UNTREATED COMBINED SANITARY AND DOMESTIC WASTES
FROM OFFSHORE FACILITIES
NO.
Men
76
66
67
42
10-40
Source:
Flow
gal/day
5500
1060
1875
2155
2900
38
BOD fncr/1)
Average Range
460 270-770
875
460
225
920
Suspended
Solids (mcr/H
Average Range
195 14-543
1025
620
220
Total
Colifonns
(X 10)
10-180
TABLE VII-28
TYPICAL OFFSHORE SANITARY AND DOMESTIC WASTE CHARACTERISTICS
DISCHARGE LOADING
RATE BOD S.S
(ms/cap/day) (kg/cap/day) (kg/cap/day)
CONCENTRATION
BOD S.S RESIDUAL
CHLOR
(mg/L) (ng/L) (mg/L)
Sanitary 0.075
Waste
(treated)
0.002 (1)
0.003 (1)
30
40
1.7
Domestic 0.110
waste
(direct
discharge)
0.022 (2)
0.016 (2)
195
140
Source: 39
VII-64
-------
Domestic wastes result from sinks, galleys, and laundries.
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 capita ger day.36'37 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 VII-28 and VII-29 also
summarize the volume and pollutant characteristics of domestic
wastes.
8. Minor Discharges
Information concerning the characteristics, discharge
volumes, and frequency of discharge for several of these minor
waste streams is limited. Available information for certain
discharges is included in Table VII-29. The following provides a
range of discharge volumes for these streams:6
Waste
BOP fluid
Boiler blowdown
Desalinization waste
Fire system test water ....
Seafloor discharges
Noncontact cooling water . . .
Uncontaminated
ballast/bilge water
Waterflooding discharges . . .
Test fluids
Diatomaceous earth filter media
Bulk transfer operations . . .
Painting operations
Uncontaminated fresh water . .
Discharge Volume
67 to 314 bbl/day
0 to 5 bbl/day
typically < 238 bbl/day
24 bbl/test
0 to 191 bbl/event
7 to 124,000 bbl/day
70 to 620 bbl/day
up to 4030 Ib solids/month
Unknown
Unknown
Unknown
Unknown
Unknown
VII-65
-------
TABLE VII-29
PROPERTIES OF MINOR OFFSHORE PRODUCTION WASTES
WASTE TYPE
COMPOSITION
VOLUME
HANDLING
i
ON
Desalination Brlna
reverse osmosis reject
(potable water only)
distillation
(producing 65m-*
potable water and
process water)
Cooling Water
California production
platform
California processing
and storage platform
Fire Control Test Water
California
California
TDS - 1.15 x seawater
bisulphite added as bloclde
TDS - 2 x seawater
TSS - 28 mg/1
pH - 7.35
COD - 1,125 mg/1*
Residual chlorine <0.1 mg/1
Temperature Increase <11°C
Seawater
Temperature Increase <11°C
Seawater
Temperature Increase <11°C
Residual chlorine 0.5 mg/L
TSS - 28 mg/1
pH - 7.35
COD - 1.125
Seawater
Ambient temperature
Seawater
Chlorine disinfectant
20 m3/d
several
100 gpd)
33 m3/d
450m3/d
(several
thousand gph)
10,500m3/d
10m3 (few
thousand gallons)
80m3/d
Continuous or Intermittent
direct discharge overboard
Mixed with cooling water
Direct discharge to the
sea surface
Mixed with desalination
waste and discharged to
surface
Discharge once per week
Intermittent discharge
* Mixed with 10.500 n3/d cooling water
Source: 39
-------
These discharges may contain various chemical additives.
Tables VII-30 and VII-31 list some of the hazardous compounds
associated with these waste streams. Data concerning the
characteristics and volumes of test fluids, diatoroaceous earth
filter media, bulk transfer operations, and painting operations
are unavailable.
VII-67
-------
TABLE-VII-10
HAZARDOUS COMPOUNDS IN BOP FLIT , BOX- ( BLOWi:,Vy7N, BILGE, FIRE
CONTROL SYSTEM, BALLA ', A WATER*LOODING DISCHARGES
Product .
KW-154(Proprietary)
MP-3000
Nalco 4956
Nalco 7202
Nalco 3801
XC-102
XC-402
Arco Chem 401
i
Arco Chem 915
CheiUink WC401
Corexite 1257
Hy-Flo Super-Cel
Nalco 933
Nalco 3340
Nalco 3346
Nalco 3380
Nc. .20 3657
Compound •
Sodium Nitrite
Proprietary
Sodium Nitrite
Sodium Mercaptobenzothiazole
Sodium Tetraborate
Cyclohexylamine
Sodium Bisulfite
Kerosene
Mineral Seal Oil
Glutaraldehyde
Methanol
Isopropanol
None
Isopropanol
Acetic Acid
None
Acrylic Polymer
Silica
Zinc Chloride
Phosphoric Acid
None
Methanol
Ethylene Glycol
Hydrotreated Light
Distillate
Ethoxylated Nonylphenol
sonium Bisulfite
Concentration
NL
NL
1-10%
1-10%
1-10%
1-10%
1-10%
10- %
40-. »
25%
T
4
ppm
ppm
400-500 ppm
10-15 ppm
NL
60%
10-20%
10-20%
10-20%
10-20%
20-40%
.1-1%
NL
Notet NL * not lie .ad
VII-68
-------
TABLE VII-30 (Continued)
HAZARDOUS COMPOUNDS IN BOP FLUID, BOILER SLOWDOWN, BILGE, FIRE
CONTROL SYSTEM*-BALLAST, AND WATERFLOOPING DISCHARGES
Product
Kalco 3991
Nalco 3999
Kalco 7348
Kalco 7766
Kalco 8173
Kalco Bleach
(Sunny Sol)
Tretolite TK-16
Compound
2,2-dibromo-3-
nitrilopropionamide
Dimethylformamide
Isopropyl Alcohol
1-(2-hydroxyethyl)-2-
methyl-5-nitroimidazole
Kone
Ethoxylated Octylphenol
Paraffinic/Naphthenic
Solvent
Kone
Sodium Hypochlorite
Sodium Hydroxide
Methanol
Tetrasodium salt of EDTA
Concentration
20-40%
1-10%
20-40%
.1-1%
1-10%
20-40%
7.5-12.5%
0.8%
200 ppm
NL
Kotet NL - not listed
Source: 40
VII-69
-------
TABLE VII-31
HAZARDOUS COMPOUNDS DISCHARGED IN COOLING WATER AND
DESALINIZATION WASTES
product
Malco 3657
Malco 3991
Nalco 3999
Nalco 7348
Tretolite K-58
Tretolite WF199
Tretolite ZC209
Compound
Ammonium bisulfite
2,2-dibros»o-3-
nitilopropionamide
Dinethylfonnahide
Isopropyl alcohol
1-(2-hydroxyethyl)-2-
methyl-5-nitroimidazole
None
Sodium hypochlorite
Sodium hydroxide
Chlorine
Trade secret
Sodium hypochlorite
Sodium hydroxide
Chlorine
Ancol Chemlink CI-922 Isopropyl alcohol
Nalco Bleach
(Sunny Sol)
Nalco 900
Halco 7766
Nalco 8173
Nalco ViBCO 1176
Sodium hypochlorite
Sodium hydroxide
Sulfamic acid
Diethylthiourea
Ethoxylated octylphenol
Para f f ini c/naphthenic
solvent
None
Ethoxylated nonylphenol
Heavy aromatic hydrocarbon
solvent
Concentration
NL
20-40%
1-10%
20-40%
0.1-1%
12%
<1%
NL
NL
12%
<1%
NL
400-500 ppm
7.5-12.5%
0.6%
40*%
ML
1-10%
20-40%
1-10%
40+%
Motes ML • not listed
Source: 41
VII-70
-------
D. REFERENCES
1. Applied Mud Technology/ by IMCO Service, Houston/ Texas.
2. Assessment of Environmental Fate and Effects of Discharges
from Offshore Oil and Gas Operations, Original by Dalton-
Dalton-Newport, As Amended by Technical Resources, Inc.,
Prepared for U.S. Environmental Protection Agency,
Monitoring and Data Support Division, EPA 440/4-85-002,
March 1985.
3. Houghton, J. P., K. R. Critchlow, D. C. Lees, and R. D.
Czlapinski, Fate and Effects of Drilling Fluids and Cuttings
Discharges in the Lower Cook Inlet, Alaska, and on Georges
Bank - Final Report. U.S. Department of Commerce, National
Oceanic and Atmospheric Administration, and the U.S.
Department of the Interior, Bureau of Land Management, 1981.
4. 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.
5. Ayers, R. C., Jr., T. C. Sauer, Jr., R. P. Meek and G.
Bowers, An Environmental Study to Assess the Impact of
Drilling Discharges in the Mid-Atlantic, Report 1 - Quantity
and Fate of Discharges, Symposium - Research on
Environmental Fate and Effects of Drilling Fluids and
Cuttings. Sponsored by API, Lake Buena Vista, Florida,
January 1980.
6. SAIC for EPA, Summary of Data Relating to Miscellaneous and
Minor Discharges. February 1991.
7. Oil and Gas Well Drilling Fluid Chemicals. Bulletin 13F,
American Petroleum Institute, August 1978.
8. Analysis of Drilling Muds from 74 Offshore Oil and Gas Wells
in the Gulf of Mexico, Prepared by Dalton-Dalton-Newport for
the U.S. Environmental Protection Agency, Monitoring and
Data Support Division, June 1, 1984.
9. Kramer, J. R., H. D. 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.
VII-71
-------
10. McCulloch, W. L., J. M. Neff, and R. S. Carr,
Bioavailability of Selected Metals from Used Offshore
Drilling Muds to the Clam Ranaia cuneata and the Oyster
Crassostrea aiaas. Symposium - Research on Environmental
Fate and Effects of Drilling Fluids and Cuttings. Sponsored
by API, Lake Bueha Vista, Florida, January 1980.
11. Petrazzuolo, Gary, "Preliminary Report: An Environmental
Assessment of Drilling Fluids, and Cuttings Released Onto the
Outer Continental Shelf", Volume One, Technical Assessment,
prepared by: (EPA) Industrial Permits Branch, Office of
Water Enforcement and the Ocean Programs Branch, Office of
Water and Waste Management, March 26, 1981.
12. Petrazzuolo, G., Draft Final Technical Support Document
"Environmental Assessment: Drilling Fluids and Cuttings
Released on to the OCS", Submitted to: Office of Water
Enforcement and Permits, U.S. EPA, January 1983.
13. ERCE, "Offshore Oil and Gas Industry BAT and NSPS Analysis
of Implementation - Cost and Contaminant Removal - Drilling
Waste," Draft, 11/9/90.
14. Ayers, R. c., Sauer, T. C., Exxon, Anderson, P.E. U.S. EPA
"The Generic Mud Concept for Offshore Drilling for NPDES"
presented at IADC/SPE Drilling Conference, New Orleans, LA,
February 20-23, 1983.
15. Results of Laboratory Analysis Performed on Drilling Fluids
and Cuttings, Submitted to: U.S. EPA, Effluent Guidelines
Division, Submitted by: CENTEC Analytical Services, April
3, 1984.
16. Duke, T. W., Parris, P. R., Montgomery, R., Macauley, S.,
Macauley, J., and Cripe, G. M., "Acute Toxicity of Eight
Laboratory - Prepared Generic Drilling Fluids to Mysids
(Mysidopsis Bahia)" Environmental Research Laboratory Sabine
Island Gulf Breeze, FL, May 1984.
17. Duke, T. W., Parris, P. R., "Results of the Drilling Fluids
Research Program Sponsored by the Gulf Breeze Environmental
Research Laboratory, 1976>1983 and Their Application to
Hazard Assessment". Environmental Research Lab - Office of
Research and Development, U.S. EPA Gulf Breeze, FL., EPA-
600/484-055, June 1984.
18. Offshore Operators Committee, "Final Report for Research
Program on Organic Chemical Characterization of Diesel and
Mineral Oils Used as Drilling Mud Additives - Phase II,"
prepared by Battelle New England Marine Research Laboratory,
December 24, 1986.
VII-72
-------
19. SAIC, Descriptive Statistics and Distributional Analyses of .
Cadmium and Mercury Concentrations in Barite. Drilling
Fluids, and Drill Cuttings from the US API/USEPA Metals
Database." February 1991.
20. Final Report for^esearch on Organic Chemical
Characterization of Diesel and Mineral Oils Used as Drilling
Mud Additives, Prepared for: Offshore Operators Committee,
Environmental Subcommittee, by: BATTELLE New England Marine
Research Laboratory, December 1984.
21. Envirosphere Company, Summary Report of Cook Inlet Discharge
Monitoring Study: Workover, Completion, and Well Completion
Fluids (Discharge Nos. 017, 018, 019) 10 April, 1987-10 Sept
1987, prepared for EPA Region X, no date.
22. 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.
23. Oil and Gas Extraction Industry, Evaluation of Analytical
Data Obtained from the Gulf of Mexico Sampling Program,
Volume 1, Discussion, Prepared by Burns and Roe Industrial
Services Corporation, Prepared for U.S. Environmental
Protection Agency, Effluent Guidelines Division, January
1983, Revised February 1983.
24. ERCE, "Offshore Oil and Gas Industry BAT and NSPS Analysis
of Implementaion - Cost and Contaminant Removal - Produced
Water," Draft, 11/15/90.
25. SAIC, "Produced Water Pollutant Variability Factors and
Filtration Efficacy Assessments From the Three Facility Oil
and Gas Study", March 1991.
26. Lysyj, I. , and M. A. Curran, Priority Pollutants in
Offshore Produced Oil Brines, Rockwell International,
Environmental Monitoring and Services Center and U.S.
Environmental Protection Agency, Industrial Environmental
Research Laboratory, respectively, November 1982.
27. Envirosphere Co. for EPA Region X, "Cook Inlet Discharge
Monitoring Study: Produced Water," Bellevue, Washington,
September 1988 - August 1989.
28. Envirosphere Company, Summary Report Cook Inlet Discharge
Monitoring Study: Workover, Completion and Well Completion
Fluids (Discharge Numbers 017, 018, 019) 10 April 1987 - 10
September 1987 (prepared for U.S. EPA Region X), no date.
VII-73
-------
29. 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, March
1990.
30. Arctic Laboratories Limited, ESL Environmental Sciences
Limited, and SKM Consulting Ltd., Offshore oil and Gas
Production Waste Characteristics, Treatment Methods,
Biological Effects and Their Applications to Canadian
Regions, DSS File No. 47SS-KE 145-2-0245 (Draft Rept.
Prepared for Environmental Protection Service Water
Pollution Control Directorate), April 1983.
31. American Petroleum Institute, American Petroleum Institute
Survey Upset & Bypass & Deck Drainage Treatment Systems
Coastal and Offshore Platforms, 1976; in API et al. v EPA et
al. No. 79 - 1829 and Consolidated Cases, Records Excerpts,
Vol. Ill, Documents 7-12, pp. 1053-1061.
32. ERCE, "The Results of the Sampling of Produced Water
Treatment System and Miscellaneous Wastes at the Shell
Western E & P, Inc. - Beta Complex," Draft, March 1990.
33. Burns and Roe Industrial Services Corp., "Review of U.S. EPA
Region VI Discharge Monitoring Report, Offshore Oil and Gas
Industry," draft, 1984.
34. Envirosphere Company, Summary Report Cook Inlet Discharge
Monitoring Study: Deck Drainage (Discharge 003) 10 April
1987 - 10 April 1988, prepared for U.S. EPA Region X, no
date.
35. U.S. EPA, Assessment of Environmental Fate and Effects of
Discharges From Offshore Oil and Gas Operations (Prepared by
Dalton, Dalton, Newport and Technical Resources, Inc. for
U.S. EPA) EPA Document 440/4-85-002, 1985.
36. Mors, T. A., R. J. Rolan, and S. E. 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.
37. 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 - 9-12-89 (prepared for U.S. EPA Region
X), no date.
VII-74
-------
38. U.S. EPA, Development Document for Interim Final Effluent
Limitations Guidelines and New Source Performance Standards
for the Oil and Gas Extraction Point Source Category, EPA
440/1-76/055-a, Sept 1976.
39. U.S. EPA, Development Document for Effluent Limitations
Guidelines and Standards for the dffshore Segment of the Oil
and Gas Extraction Point Source Category (Proposed), EPA
440/1-85/055, July 1985.
40. Envirosphere Company, Summary Report Cook Inlet Discharge
Monitoring Study: Blowout Preventer Fluid, Boiler Slowdown,
Fire Control System Test Water, Uncontaminated Ballast
Water, Uncontaminated Bilge Water, and Water Flooding
Discharges (Discharge Numbers 007, 008, Oil, 012, and 015)
10 April 1987 - 10 April 1987 (prepared for U.S. EPA Region
X), no date.
41. Envirosphere Company, Summary Report Cook Inlet Discharge
Monitoring Study: Non-Contact Cooling Water and Desalination
Waste (Discharge Numbers 010 and 006) 10 April 1987 - 10
April 1988 (prepared for U.S. EPA Region X), no date.
VII-75
-------
SECTION VIII
SELECTION OF POLLUTANT PARAMETERS
A. INTRODUCTION
Based on detailed assessments of information collected by
the Agency on the quantities and characteristics of waste
discharges from this industry, a list of pollutants of concern
has been developed. This list, presented below, includes
pollutants present at levels significant enough to be considered
for regulation:
- Oil and grease
- Free oil
Toxicity
Priority pollutants
Diesel oil
Fecal coliform (total residual chlorine)
Floating solids
Foam
The following provides a discussion regarding control for
each of these parameters.
B. DIESEL OIL
In 1985, EPA proposed in several of its regulatory options
for drilling fluids and cuttings a prohibition on the discharge
of diesel oil. EPA is not changing that proposal in this
rulemaking.
Generic drilling muds with no added diesel oil or mineral
oil have relatively low acute, lethal toxicity. However,
industry contends that the use of diesel and/or mineral oils as
VIII-1
-------
lubricating and spotting agents in water-based muds, at
relatively high levels (2-4%), is necessary for reliable
operations. The addition of even small amounts of diesel oil to
water-based generic drilling muds cause them to become
significantly more toxic. Also, diesel oil has a high,
statistically demonstrable correlation to observed toxicity.
Diesel oil, either as a component in an oil-based drilling fluid
or as an additive to a water-based drilling fluid is an indicator
of toxic pollutants. The term indicator as used here is a
pollutant, constituent or characteristic that exhibits a
correlation with one or more other constituents in the same
waste. The objective in regulating an indicator is to control
the level(s) of the other constituents(s). The nature of the
correlation is positive. That is, when the indicator's level is
increased, the other constituents' levels are increased; when the
indicator's level is decreased, the other constituents' levels
are decreased.
The listed priority pollutants found in various diesel oils
can include benzene, toluene, ethylbenzene, naphthalene,
phenanthrene, fluorene, and phenol. Diesel oil may contain from
20% to 60% by volume aromatic hydrocarbons. The aromatic
hydrocarbons, such as benzenes, naphthalenes, and phenanthrenes,
constitute the more toxic components of petroleum products such
as diesel oil. Diesel oil also contains a number of
nonconventional pollutants, including polynuclear aromatic
hydrocarbons such as methylnaphthalene, dimethylnaphthalene,
methylphenanthrene, and other alkylated forms of each of the
listed toxic pollutants.
Because "diesel oil" is neither a listed toxic pollutant nor
a listed conventional pollutant it is a nonconventional
pollutant. The parameter diesel oil is used as an indicator for
the toxic organic pollutants that it ,.s composed of because it
VIII-2
-------
would be technologically infeasible to develop effluent
limitations for all of the individual toxic organic pollutants.
The proposed level of control is to prohibit the discharge of
diesel oil. Method 1£51, published in the Federal Register (54
FR 634), presents the analytical method to measure diesel oil
concentrations.
The use of mineral oil instead of diesel oil as an additive
in water-based drilling fluids will reduce the quantity of toxic
and nonconventional organic pollutants that are present in a
drilling fluid, as compared to the quantity of these pollutants
present when using diesel oil as an additive. Mineral oils, with
their lower aromatic hydrocarbon content and lower toxicity,
contain lower concentrations of toxic pollutants than do diesel
oils.
C. FREE OIL
As in the 1985 proposal, EPA currently is considering a no
discharge of free oil in several of its regulatory options for
drilling fluids and cuttings, produced sand, deck drainage, and
well treatment fluids.
Also, a change in the analytical method of compliance for
free oil (to that of the BPT compliance method) was proposed in
1985. This rulemaking will not affect that proposal. The
proposed test procedure is for use in determining compliance with
the prohibition on free oil discharges. This test is the "static
sheen test" used in definition s. 435.11(m) and presented in
Appendix 1 of the regulation to the 1985 proposal. This would
apply to the same waste streams that are covered by the existing
BPT prohibition, i.e., deck drainage, drilling fluids, drill
cuttings, and well treatment fluids and also for produced sands.
VIII-3
-------
Prior to the 1985 proposal, the BPT compliance monitoring
procedure was a visual inspection of the receiving water after
discharge. However, since the intent of the limitations is to
prohibit discharges containing free oil that will cause a" sheen,
the method of determining compliance should examine oil
contamination prior to discharge. Also, concerns have been
raised that the intent of the existing definition of "no
discharge of free oil" may be violated too easily for the
limitation to be effective. Violations which may result from
intentional or unintentional actions include the use of
emulsifiers or surfactants, discharges that occur under poor
visibility conditions (i.e., at night or during stormy weather),
and discharges into heavy seas, which are common on the outer
continental shelf. Additionally, concerns have been expressed
over the utility of the visual observation of the receiving water
compliance monitoring procedure for certain discharges during ice
conditions as in Alaskan operations. These include above-ice
discharges where the receiving water would be covered with broken
or solid ice, and below-ice discharges where the effluent stream
would be obscured.
To correct these monitoring problems, the Agency developed
an alternative compliance test, the Static Sheen Test. The
alternative test continues the visual observation for sheen but
provides for inspection before discharge using laboratory
procedures. The test is conducted by adding samples of the
effluent stream into a container in which the sample is
mechanically mixed with a specific proportion of seawater,
allowed to stand for a designated period of time, and then viewed
for a sheen.
Since the intent of a "no discharge of free oil" limitation
is to prevent the occurrence of a sheen on the receiving water,
VIII-4
-------
the new test method will prevent the discharge of fluids that
will cause such a sheen.
In addition to a proposed change from a visual sheen test to
a static sheen test, EPA is investigating several different
methods of compliance with the static sheen test (although the
method in Appendix 1 of the 1985 regulation remains the proposed
method at this time). These methods.are discussed in Section VI.
Free oil is being regulated under BAT and NSPS as an
"indicator" pollutant for the control of priority pollutants (see
Section X.B below). Free oil is being regulated under BCT as
well. Although it is not a conventional pollutant, as is oil and
grease, EPA is limiting free oil as a surrogate for oil and
grease under BCT in recognition of the complex nature of the oils
present in drilling fluids.
Free oil and diesel oil are both related to the concen-
tration of priority as well as conventional and nonconventional
pollutants present in those oils. The pollutants "free oil" and
"diesel oil" are each considered to be "indicators" of specific
priority pollutants present in these complex hydrocarbon mixtures
used in drilling fluid systems. These pollutants include
benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and
phenol.
In addition, as also previously proposed in 1985, EPA is
proposing a change in the definition of "no discharge of free
oil." This definition differs from that currently specified in
40 CFR 435.11, which requires "... that a discharge not cause a
film or sheen upon or a discoloration on the surface of the water
or adjoining shorelines or cause a sludge or emulsion to be
deposited beneath the surface of the water or upon adjoining
shorelines." The limitation was originally intended to prohibit
the discharge of drilling fluids (as well as drill cuttings and
VIII-5
-------
well treatment fluids) that, when discharged, would cause a sheen
on the r reiving water. The limitation was then extended for
final BPT regulations to incl ;:e deck drainage, and th> current
definition of the term "no discharge of. free oil" was established
to be consistent with the oil discharge provisions of Section 311
of the Act. Technically, however, discharged drilling fluids
could be considered "sludge." For this reason, the Agency is
proposing to amend the current definition by excluding language
that prohibits the deposit of sludge beneath the surface of the
receiving water. This would allow the discharge of drilling
fluids, provided that other effluent limitations are met.
Sampling ;.nd analysis data demonstrate that when the amount
of oil, especially diesel, is reduced in drilling fluid, the
concentrations of priority pollutants and the overall toxicity of
the fluid generally is reduced. Controlling of the amount and
type of oil present in drilling fluids with limitations on these
two "indicators" provides a substantial level of control of the
priority pollutants present in drilling fluids.
D. TOXICITY (LCjo)
1. Effluent Limitations
In 1985, EPA proposed as part of its regulatory options for
muds and cuttings, a limitation on toxicity. EPA is not changing
that proposal in this rulemaking. The limitation is set, at
30,000 ppm based on the toxicity of the most toxic of eight
generic drilling fluids (see Section VII) in use at the time of
the 1985 proposal. The toxicit limit is expressed as the
concentration of the suspended particulate phase (SPP) of the
drilling fluid that is lethal to 50% or more of a particular
species exposed to that concentration of the SPP, i.e., the LC30
of tlie discharge.
VIII-6
-------
Additives such as oils and some of the numerous specialty
additives—especially biocides—may greatly increase the toxicity
of the drilling fluid*. The toxicity is, in part, caused by the
presence and concentration of priority pollutants. However,
control of free oil and diesel oil nay not be an effective means
of regulating these additives. A toxicity limitation would
require that operators consider toxicity in selecting additives
and select the less toxic alternative. Thus, the toxicity
limitation will also act as an indicator of toxic pollutant
reduction. The limitation would encourage the use of generic
water-based drilling fluids and the use of low-toxicity drilling
fluid additives (i.e., product substitution).
The eight generic water-based drilling fluids whose
formulations are presented in Section VII of this document are
adequate for virtually all drilling situations and are less toxic
than oil-based drilling fluids. In order for a drilling fluid to
be discharged, it should be no more toxic than the proposed LC50
standard as determined with the drilling fluids toxicity test
presented in Appendix 3 of the regulation to the 1985 proposal.
The most toxic generic fluid is potassium/polymer mud (see
Table VII-8 of this document). The imposition of an LC50
toxicity limitation for all drilling fluids which are to be
discharged would allow for use of at least any of the eight
generic drilling fluids. Seven of the generic drilling fluids
(i.e., all but potassium/polymer mud) could be supplemented with
low-toxicity specialty additives and lubricity agents to meet
operational requirements, and be able to comply with the LCSO
toxicity limitation prior to discharge. This conclusion is based
on the results of a toxicity study in which mud samples were
spiked with mineral oil at various concentrations.1
VIII-7
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The toxicity of water-based muds which have either mineral
oil or diesel oil added for spotting or lubricitv is a concern
also. Studies described in Section VI show tha :he presence of
petroleum hydrocarbon* in drilling fluid contributes
significantly to its toxicity—especially for diesel oil.
The reliance of the toxicity testing protocol has been in
question since the 1985 proposal. Studies performed since then,
and described in Section VI, support EPA's conclusion that the
testing protocol is adequate for regulatory purposes.
2. Environmental Effects and Testing Procedures
Results of research activities show that drilling fluids are
toxic to marine organisms at certain concentrations and exposure
regimes. Further, drilling fluids can adversely affect animals—
especially benthos—through physical contact, by burying, or by
altering substrate composition. Drilling fluids also can exert
effects by disrupting essential physiological functions of
organisms.2
The area where drilling fluids are most likely to cause
detectable problems associated with water column toxicity are
those with shallow water (i.e., where dispersion is limited) or
poorly flushed/low energy areas (i.e., where the amount of muds
discharged is large compared to local water flux). Sediment
toxicity to benthic organisms, oxygen depletion effects, and
physical effects due to deposition also are most likely to be
observed in these areas.3
When discharges are made from platforms located in open,
well-mixed, and relatively deep (>20 m) marine environments, most
detectable acute effects will be limited to within several
hundred meters of the point of discharge. Based on laboratory
VIII-8
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derived effects data, there will be sufficient dilution of the
drilling fluids in the water column to minimize acute effects on
water column organisms. Benthic organisms within about 300 m of
the discharge will be potentially subject to adverse effects
caused by burial and chemical toxicity; they also may be
susceptible to direct effects or substrate changes for greater
distances. Possible exceptions to these generalizations could
occur when discharges are near sensitive biological areas, such
as coral reefs, or in poorly flushed environments.2
Toxicity tests are used to determine levels of pollutant
concentrations which can cause lethal or sublethal effects on
organisms and are categorized as either acute or chronic. Acute
toxicity tests involve exposures of 96 hours or less, while
chronic toxicity tests involve long-term exposures, usually
entire or partial life cycles.3
Acute toxicity tests are used to determine the short-term
effects of a chemical or mixture on an organism. Results are
generally reported as the concentration at which 50% of the
organisms are killed (the LCSO, or median lethal concentration),
or display a defined effect of toxicological importance, such as
loss of mobility (the ECSO or median effects concentration). The
higher the LC50 or EC50 for a given exposure time, the lower the
toxicity of the substance being tested.3
Acute toxicity tests can be conducted in static, renewal, or
flow-through systems. Static systems involve exposure to a
single batch of test solution for the full test period. Renewal
systems involve periodically replacing the test solution with new
solution of the same concentration. In flow-through systems, the
test solution is continuously replaced and excreted metabolites
are removed. EPA's proposed protocol for toxicity testing of
VIII-9
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drilling fluids specifies a static bioassay system (Appendix 3 of.
the 1985 proposed regulation).3
Chronic toxicity^ tests evaluate the long-term effects of
pollutant exposure on survivability, growth, 'maturation, and
reproduction. The results generally are expressed as a range,
with the smaller value the lowest concentration resulting in the
prescribed effect and the larger value the highest concentration
not producing the effect.3
Chronic tests can be life cycle, partial life cycle, or
early life stage. Life-cycle testing exposes organisms from
embryo or newly hatched larval stage through at least 24 hours
after the hatching of the next generation. Partial life-cycle
tests expose organisms through part of the life cycle, and are
used in situations where the organism takes a long period (e.g.,
a year or more) to mature. Early life-stage testing focuses on
the embryonic stage shortly after fertilization through early
juvenile development.3
E. OIL CONTENT
The 1985 proposal included an option for regulating oil
content for drill cuttings. However, this option was rejected in
1985 because it was believed that establishing an oil content
limitation on drill cuttings could be redundant because, as
stated in the Federal Register, the prohibition on the discharge
of free oil appeared to be a more stringent limitation. Data on
the performance of mechanical cuttings washer technologies showed
residual oil content reduction to be less than 10% by weight.
Data on the visual sheen test (used at that time for the no
discharge of free oil limitation) showed compliance with this
limitation required reductions in oil content to less than 1%.
VIII-10
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The Agency continued to study washer technology and
presented their findings in the 1988 Notice. This study was
expanded to explore the applicability of an oil content limit to
drilling fluids as well as to drill cuttings. A number of
conclusions evolved from this study which EPA reiterates below:
1. Drilling Fluids
An oil content limit for drilling fluids is not appropriate
because the volume of fluids is much greater than for drill
cuttings. Space is insufficient on platforms to accommodate the
volumes of fluids that must be stored in preparation for
processing. In addition, in the case of thermal technologies,
the much higher relative water content of drilling fluids
requires a higher input of thermal energy to the process to
vaporize the water present, resulting in unreasonable costs.
2. Drill Cuttings
EPA investigated washer technologies with respect to both
oil-based and water-based muds.4 Oil content of untreated drill
cuttings associated with oil-based drilling fluids were estimated
to contain 20% oil by weight. Untreated drill cuttings from
water-based drilling fluids to which oil had been added for
spotting or lubricity were estimated to contain 1% oil by weight.
Data on performance of thermal distillation showed that oil
content for drill cuttings (associated with either water- or oil-
based fluids) could be reduced to 1% by weight. For solvent
extraction, reductions were attained to 0.3% by weight. Thus, it
was stated that drill cuttings from water-based muds to which oil
had been added for spotting or lubricity would not require
treatment to comply with an oil content limit of 1% by weight.
VIII-11
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EPA maintains that reductions even to 1% are, again,
redundant. The free oil limitation -eady results in compliance
to this level. In addition; limitat s on fiee oil, diesel oil,
and toxicity adequately cover toxic i \j.lutants associated with .
oil content of drilling wastes. Reductions of another 0.7%
exhibited by the solvent extraction technology do not compensate
for the disadvantages in using this system. As discussed in the
1988 notice, the potential for losses of chlorofluorocarbon-type
solvents to the atmosphere are a major concern for solvent
extraction.
In addition, EPA is not in the position to develop
limitations based on the thermal distillation technologies
because this technology has not been demonstrated either by full
scale or pilot testing to be capable of operating at offshore
facilities and due to safety concerns regarding fire hazards.
Furthermore, EPA believes that the prohibition on the offshore
discharge of free oil effectively prohibits the discharge of oil-
based cuttings by requiring land disposal.
F. OIL AND GREASE
1. Effluent Limitations
Oil and grease is already reflated under BPT for produced
waters. EPA is proposing certain options that will either equal
or be more stringent than the BPT oil and grease limits for
produced water, oil and grease is considered a conventional
pollutant subject to BCT limitations as well as NSPS.
EPA is also proposing to limit oil and grease under BAT as
an indicator pollutant for certain toxic and metal priority
pollutants as well as nonconventional pollutants. As further
discussed in Section IX, filtration technology, the basis for the
VIII-12
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oil and grease limitations, also removes other toxics and
nonconventionals. The filtration technologies, forming the basis
for certain regulatory options, are membrane and granular media
filtration. Granular^media filtration, while it primarily
removes suspended insoluble matter, does exhibit a degree of
organic and metal removal as well. Membrane filtration removes
considerably more of the soluble hydrocarbon constituents.
Analysis of data in the three-facility study on performance
of granular media filtration showed significant reductions of 2-
propanone and hydrocarbons across filtration.5 The hydrocarbons
include m-xylene, o+p xylene, n-decane, n-decosane, n-erocosane,
n-hexadecane, naphthalene, toluene, and methylnaphthalene.
Significant reductions in iron, manganese, and aluminum were also
achieved. Data supplied by membrane filtration vendors show this
technology capable of removing 95% of the soluble hydrocarbons
(the bulk of organics in produced waters are in the soluble
hydrocarbon phase).6
Thus, for these reasons, EPA is limiting oil and grease
under BAT and NSPS as an "indicator11 for other organic and metal
pollutant removals.
Two analytical methods for oil and grease analysis have been
investigated by EPA. These methods, discussed in Section VI, are
the gravimetric method and the silica gel method. The proposed
effluent limitations for oil and grease are based on the
gravimetric method.
2. Environmental Effects
The most obvious pollutant of concern for produced water is
oil and grease. Oil emulsions may adhere to the gills of fish or
coat and destroy algae or other plankton. Deposition of oil in
VIII-13
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the bottom sediments can inhibit normal benthic growth rates,
thus interrupting the aquatic food chain. Soluble and emulsified
materials ingested by fish can taint the flesh which can reduce
the commercial and recreational value of the fishery. Water
soluble components may have toxic effects on fish. The water
insoluble hydrocarbons and free floating emulsified oils in a
wastewater interferes with oxygen transfer, damages the plumage
and coats of water animals and fowl 'and increase oxygen demand.
G. PRIORITY POLLUTANTS
Priority pollutants may be present in all oil and gas
discharges. However, their control is indirectly regulated by
limiting "indicator" pollutants as further discussed below.
1. Metals
The trace metals of concern in drilling fluids include
mercury, barium, zinc, lead, chromium, cadmium, copper, and
arsenic. The source of barium in drilling fluids is barite.
Barite is mined from either bedded or vein deposits. Research
has shown that the bedded deposits are characterized by
substantially lower concentrations of heavy metal contaminants
such as cadmium and mercury (Kramer, J.R. et al, "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,
Florida, 1/80).
Barite may be contaminated with several metals of interest,
including mercury, cadmium, zinc, lead, arsenic, and other
substances. However, seawater solubilities for trace metals
associated with powdered barite generally result in
concentrations below background levels.3 The Agency believes
VIII-14
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that by limiting the levels of cadmium and mercury in barite,
concentrations of other related metals would be limited as well.
EPA is proposing^to regulate these two toxic metals in order
to control the metals content of the barite component of any
drilling waste discharges. Cadmium and mercury are "toxic
pollutants" subject to BAT and NSPS limitations.
The August 26, 1985 proposal included proposed effluent
limitations of 1 mg/kg each of cadmium and mercury in the whole
drilling fluid on a dry weight basis. The proposed effluent
limitations would be maximum values (no single analysis to
exceed). These effluent limitations are also included in some of
EPA's regulatory options for this rulemaking.
In the 1988 notice, two alternative limitations for cadmium
and mercury were presented. One was for 2.5 mg/kg cadmium and
1.5 mg/kg mercury in the whole drilling fluid. This was
developed in response to comments of concern about the cost and
availability of barite "clean" enough to meet the 1/1 mg/kg
cadmium/mercury limitations. The 2.5/1.5 mg/kg limitations were
suggested based on the use of barite containing no more than 5
mg/kg cadmium and 3 mg/kg mercury which, commenters declared, was
available in adequate supply. The 2.5 mg/kg cadmium and
1.5 mg/kg mercury limitations came from the assumption that
barite is diluted by 50% or more in the drilling fluid. In the
1988 notice, the Agency also presented the option of limiting
cadmium and mercury at 5 mg/kg and 3 mg/kg, respectively, in the
barite instead of an effluent limitation in the drilling fluid.
Based on additional information since the 1988 notice, EPA
is considering three alternatives for cadmium and mercury
limitations: 1) maintaining the 1985 proposed discharge
limitations of 1/1 mg/kg of cadmium and mercury each in the
VIII-15
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drilling fluid, 2) limitations based on barite composition of 5 -
mg/kg cadmium and 3 mg/kg mercury as included in the 1988 notice,
and 3) an additional limitation of 3 mg/kg of cadmium and 1.0
mg/kg of mercury alsp^based on barite composition. All of these
limitations would be a maximum (no single sample to exceed)
value. Compliance would depend on the barite composition.
The limitations for cadmium and mercury of 2.5 and 1.5
mg/kg, respectively, in the drilling fluid are no longer
considered appropriate because insufficient support exists for
the assumption that a 50% dilution rate occurs once barite is
mixed with drilling fluids.
EPA is evaluating limitations of 3.0 mg/kg cadmium and 1.0
mg/kg mercury in the stock barite because discharges at these
levels are currently being achieved at ongoing operations.
Recent information to evaluate EPA's current alternatives
for metals limitations comes from data compiled during a joint
effort by EPA and API. The current version of this database,
"API - USEPA Metals Database for Metals Content in Drilling
Fluids - Drill Cuttings/Formations - Barites - Sediments," is
from April 1990. This database contains data sets, from all
studies currently known to EPA and API, on the metals content of,
drilling fluids and drill cuttings.
Six datasets provide information that was used to determine
compliance achievability.7 These datasets come from the Diesel
Pill Monitoring Program (DPMP), the Offshore Operators
Committee's (OOC) Fifteen Rig Study (15RS) as well as two other
studies performed in 1986 and 1988, monitoring data from EPA's
Region IX, and monitoring data from Region X.
VIII-16
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The DPMP study contains 38 cadmium and mercury measurements.
from a joint effort of EPA and API in Region VI. Limitations in
the methods used to collect the data were considered in the
analysis. The sampling design called for self-selected offshore
oil and gas operators with stuck drilling pipes to submit self-
monitoring reports. As an incentive to participate, operators
were allowed to discharge, as opposed to hauling onshore, water-
based drilling muds and cuttings after recovery of a diesel pill
that was used to free the stuck pipe. Samples considered for
this analysis were all collected before the diesel pill was
spotted. Region VI did not have cadmium and mercury limitations
at the time of this data collection.
The 15RS contains 14 cadmium and mercury measurements from a
joint effort of API and OOC, most likely conducted in Region VI.
The sampling design called for self-selected offshore oil and gas
operators who were in the process of drilling wells, whose names
and locations remain confidential, to submit standardized
reports. Samples were analyzed by both industry and EPA.
The OOC also collected samples during 1986 and 1988. In
1986, drilling muds and barite were sampled. The sampling design
called for self-selected offshore oil and gas operators who were
in the process of drilling wells. Only total metal analyses data
were used. In 1988 only barite was sampled. The sampling design
also called for oil and gas operators who were in the process of
drilling.
The Region IX data, measurements from four samples, are from
discharge monitoring reports submitted by offshore oil and gas
operators under the requirements of their permits. The Region IX
general permit requires that barite used to formulate drilling
fluid must contain 2 mg/kg or less of cadmium and 1 mg/kg or less
of mercury.
VIII-17
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The Region X data, measurements from 116 samples, are from
discharge monitoring reports submitted by offshore oil and gas
operators under the requirements of their permits. The Region X
general permit requires that barite used to formulate drilling
fluid must contain 3 mg/kg or less of cadmium and 1 mg/kg or less
of mercury.
Analysis of a select set of data sources from this data
base, considered appropriate for the following statistical
analyses, was performed to determine compliance rates with each
set of limitations.8 All of the data sets show passing rates to
some degree for all limitation options. Table VIII-l shows the
percent of samples from each data set that pass the 5/3 and 3/1
cadmium/mercury barite limitations. One-hundred-percent
compliance was exhibited by data from Region IX for both
standards, with generally high percentage compliance rates for
all data sets. Table VIII-2 shows the percent of samples passing
the three sets of standards for cadmium and mercury in the
drilling fluids. Again, 100% compliance with all standards was
exhibited by data from Region IX. From a Best Available
Technology standpoint, EPA prefers the most stringent limitation
exhibiting the ability to comply. The limitations for 1/1 mg/kg
cadmium and mercury in the drilling fluids are the most
stringent. Region IX shows a 100% compliance with this limit
probably because their general permit has a 2/1 mg/kg limitation
for cadmium and mercury, respectively, in the barite composition.
Region X, which includes in its general permit limitations oi :>/!
mg/kg cadmium and mercury, respectively, in barite composition,
shows a 67% compliance rate for 1/1 mg/kg cadmium and mercury in
drilling fluids. Data from Gulf facilities show a lower
VIII-18
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TABLE VIII-1
PERCENT OF SAMPLES PASSING BOTH CADMIUM
AND MERCURY PROPOSED LIMITATIONS ON BARITE
<
H
I
M
VO
Standard
Standard 1
- 5 mg/kg
Cadmium
- 3 mgAg
Mercury
Standard 2
- 3 mgAg
Cadmium
- 1 mgAg
Mercury
Study
OCC86
OOC88
REG10
REG9
15RS
15RSEPA
OOC86
OOC88
REG10
REG9
15RS
15RSEPA
Number of Samples
Passing Both
Samples Cd and Hg
15
48
52
11
14
14
15
48
52
11
14
14
14
44
52
11
12
12
11
32
52
10
7
6
Percent
Passing
Cd and Hg
93
92
100
100
86
86
73
67
100
91
50
43
Source: 8
-------
TABLE VIII-2
PERCENT OF SAMPLES PASSING BOTH CADMIUM
AND MERCURY PROPOSED LIMITATIONS ON DRILLING FLUIDS
H
I
NJ
O
Standard
Standard 1
- 1 mgAg
Cadmium
- 1 mgAg
Mercury
Standard 2
- 2.5 mgAg
Cadmium
- 1.5 mgAg
Mercury
Standard 3
- 1.5 mgAg
Cadmium
- 0.5 mgAg
Mercury
Study
DPMP
OOC86
REG10
REG9
15RS
15RSEPA
DPMP
OOC86
REG10
REG9
15RS
15RSEPA
DPMP
OOC86
REG10
REG9
15RS
15RSEPA
Samples
38
31
116
4
14
13
38
31
116
4
14
13
38
31
116
4
14
13
Number of Samples
Passing Both
Cd and Hg
6
4
78
4
8
3
19
27
102
4
12
12
21
29
71
100
50
31
Percent
Passing
Cd and Hg
16
13
100
100
86
86
73
67
100
91
50
43
73
67
100
91
50
43
Source: 8
-------
percentage of compliance; however, there are currently no metals -
limitations in their general permit. For comparative purposes,
EPA is evaluating in its regulatory options the most stringent
cadmium and mercury limitations (1/1 mg/kg in the fluids) and the
least stringent option (the 5/3 mg/kg cadmium and mercury
limitations in the barite composition).
In response to comments regarding concern over availability
of barite supplies, EPA commissioned investigations into this for
limitations on cadmium and mercury of either 1/1 mg/kg in the
fluids or 5/3 mg/kg in barite.9 This investigation reviewed
foreign and domestic barite supplies, with compositions adequate
to meet the proposed limitation, to the projected industrial
demand. Two sets of limits were investigated: the 1/1 mg/kg
each of cadmium and mercury in the drilling fluids, and 5/3 mg/kg
of cadmium and mercury in the barite. The study was performed on
1985 data. This report first investigated the amount of
available barite having a composition that could meet the metals
limits. This information was obtained from a survey on cadmium
and mercury content in barite. The survey covered only 8
countries while 47 countries are listed as producers in the 1985
Minerals Yearbook (U.S. Department of the Interior, 1985).
Results of this survey, extrapolated to 1985 production, are
shown in Table VIII-3. However, these 8 countries account for
3,911 thousand short tons out of 6,671 thousand short tons
produced in 1985. It could not be estimated how much of the
remaining 41% of 1985 production might have met either cadmium
and mercury limitation. For the most adversely affected
producer, Peru, none of the samples met the 1 mg/kg limitation
and only one-third of the samples met the 5 mg/kg and 3 mg/kg
limitations on cadmium and mercury* All U.S. samples met the 5
mg/kg and 3 mg/kg limitations while 82% met the 1 mg/kg each
limitation for these metals.
VIII-21
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TABLE VIII-3
AMOUNT OF BARITE MEETING CADMIUM AND MERCURY
LIMITATIONS - 1985 DATA
Meeting
Hg and Cd Limits
Meeting
Hg and Cd Limits
Country
Quantity
Produced or
Imported to
U.f: (000
short tons)
of 1 and 1 mg/lkg
Quantity
% (000 sht. tns.)
of 3 and 5 mg/kg
Quantity
% (000 sht. tns.)
Chile
China
India
Mexico
Morocco
Peru
Thailand
U.S.
Total of
Listed
Countries
U.S. Barite
Use in Well
Drilling
Total
Onshore
Offshore
24
1,100
670
540
468
180
190
739
5,911
57
56
81
36
34
0
33
82
14
616
543
194
159
0
63
606
2,195
93
81
100
79
78
33
100
100
22
891
670
427
365
59
190
739
3,363
2,042
1,096
946
Source: 9
VIII-22
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For the countries surveyed, 2,195 thousand short tons or
3,363 short tons of "clean11 barite would have been available from
1985 production depending on the limits chosen for cadmium and
mercury. Total U.S. 4aarite use in 1985 for well drilling was
2,042 thousand tons. In other words, even though only 59% of
world production was extrapolated, there would have been
sufficient "clean" barite to meet aJLJL U.S. drilling needs, not
just offshore.
Table VIII-4 compares the projected barite needs to the
"clean" barite available based on 1985 production levels,
assuming three different oil price scenarios. (The $21 per
barrel price is the same profile as the "unconstrained" profile
in Sections III and IV). Under the 1 mg/kg each limitation,
barite needs exceed 1985 domestic production but form only 28% to
41% of the production of the tested countries. Additional
supplies are likely to be available from the untested countries
as well.
Under the 5 mg/kg and 3 mg/kg limitations, 1985 domestic
consumption alone would suffice to cover the number of wells
projected for the $15/bbl scenario and almost cover the number of
wells projected under the $21/bbl scenario. Under this limit,
U.S. offshore barite needs would require only 18% to 27% of the
1985 production from the tested countries.
The conclusion reached from this information is that there
appears to be adequate supplies to meet the needs of offshore
drilling operations if either limitation was in place.
Reasons for noncompliance with these limitations would be
using barite with high cadmium and mercury content or, as brought
up by coromenters, the presence of cadmium in the formation
itself. In response to this comment, EPA has analyzed data from
VIII-23
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TABLE VIII-4
COMPARISON OF PROJECTED BARITE NEEDS AND SUPPLIES
Available Barlte (1985 Production)
(000 short tons)
Hg and Cd Limits of 1 and 1 rag/kg Hg and Cd Limits of 3 and 5 rag/kg
M
H
I
to
Price
Assumption
($/bbl)
15
21
32
Average
Annual Barite
Requirements
613
742
894
United States
Quantity %
606 101
606 122
606 148
Tested Countries
Quantity %
2,195 28
2,195 34
2,195 41
United States
Quantity %
739 83
739 100
739 121
Tested Countries
Quantity
3,365
•3,365
3,365
18
22
. 27
Source: 9
-------
the American Petroleum Institute's Fifteen Rig Study.7 In this -
study, operators of 14 rigs volunteered to collect matched sets
of measurements. Each rig collected a sample of drill cuttings,
a sample of used drilling fluids, and a sample of barite that was
present at the time the first two samples were taken. Splits or
duplicates of these samples were analyzed by labs associated with
the Agency. Results of statistical analysis indicate that some
cadmium present in the drilling fluids came from a source other
than the barite. In particular, physical analyses by the
industry lab indicate that 11 out of 14 rigs had higher cadmium
concentrations in their drilling fluid than in their barite.
These results suggest that cadmium, from a source other than
barite, is contaminating the drilling fluid. Physical analyses by
the Agency lab indicate that 13 out of 13 rigs, for which the
Agency lab reported results, had higher cadmium concentrations in
their drilling fluid than in their barite.
This conclusion is based on the assumption that metals are
uniformly distributed throughout the barite present at a single
rig and thoughout the drilling fluids used on that rig. The EPA
is not convinced as to the validity of this assumption and is
requesting information on what additional sources of cadmium may
affect drilling fluids. If, however, the metals limitations
could not be met for this reason, then barging would be necessary
for land disposal.
Cadmium and mercury are proposed as being limited for BAT
and NSPS to control the metals content of drilling waste
discharges. The same report referenced above8 concluded that
concentrations of other toxic metals are positively correlated
with concentrations of cadmium and mercury.
VIII-25
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2. Organics
Priority organics consistently found in significant
concentrations in produced waters were phenol, 2-4-dimethyl
*
phenol, ethylbenzene, naphthalene, toluene, bis(2-ethylhexyl)-
phthalate, and benzene (see Section VII). Priority organics most
often found in drilling wastes were benzene, naphthalene,
fluorene, phenol, and phenanthrene.' As discussed under "Oil and
Grease" of this section, oil and grease will be regulated under
BAT as an indicator for the reduction of toxics for produced
water. As also discussed under "Free Oil," "Diesel Oil," and
"Toxicity" of this section, these three parameters will be
regulated as indicators for the reduction of toxics for drilling
wastes.
H. FECAL COLIFORM (TOTAL RESIDUAL CHLORINE)
The concentration of fecal coliform bacteria can serve as an
indication of the potential pathogenicity of water resulting from
the disposal of uman wastes. Fecal coliform levels have been
established to protect beneficial water use (recreation and
shellfish propagation) in the coastal areas.
The most direct method to determine compliance with
specified limits is to measure the fecal coliform levels in the
effluent for a period representing a normal cycle of operations.
This approach may be applicable to onshore installations;
however, for offshore operations the logistics become complex,
and simplified methods are desirable.
The presence of specific levels of suspended solids and
chlorine residual in an effluent are indicative of corresponding
levels of fecal coliforms. In general if suspended solids levels
VIII-26
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in the effluent are less than 150 mg/L and the chlorine residual.
is maintained at 1.0 mg/L, the fecal coliform level should be
less than 200 per 100 ml. Properly operating biological
treatment systems on^pffshore platforms have effluents containing
less than 150 mg/L of suspended solids; therefore, total residual
chlorine is selected as a control parameter in lieu of direct
fecal coliform monitoring of sanitary waste discharges. Residual
chlorine is used as a surrogate parameter for fecal coliform.
I. FOAM
The general permits for the Gulf of Mexico regulate foam for
what they term "miscellaneous wastes." Limitations on foam are
intended to control discharges that include detergents. EPA
believes this is also an appropriate pollutant to limit for
domestic wastes. Domestic wastes typically include spent
detergents which may cause foam.
VIII-27
-------
J. REFERENCES
1. Duke, T., Parrish, P., Montgomery, R., Macauley, S.,
Macauley, J., and Cripe, G. M., "Acute Toxicity of Eight
Laboratory-prepared Generic Drilling Fluids to Mysids
fMvsidopsis Bahial," Environmental Research Laboratory,
Sabine Island, Gulf Breeze, FL, May 1984.
2. Duke, T. W., Parrish, P. R., "Results of the Drilling Fluids
Research Program Sponsored by the Gulf Breeze Environmental
Research Laboratory, 1976-1983 and Their Application to
Hazard Assessment." Environmental Research Lab - Office of
Research and Development, U.S. EPA, Gulf Breeze, FL, EPA-
600/484-055, June 1984.
3. "Assessment of Environmental Fate and Effects of Discharges
from Offshore Oil and Gas Operations," Original by Dalton-
Dalton-Newport, As Amended by Technical Resources, Inc.,
Prepared for U.S. Environmental Protection Agency,
Monitoring and Data Support Division, EPA 440/4-85-002,
March 1985.
4. KRE, "Report on Costs, Energy Requirements and Processing
Rates for Treating Drilling Fluids and Drill Cuttings Using
Thermal Distillation and Solvent Extraction Processes,11
April 1988.
5. SAIC, "Produced Water Pollutant Variability Factors and
Filtration Efficacy Assessments from the Three Facility Oil
and Gas Study," Draft, March 1991.
6. Letter from Kenneth M. Thomas, Alcoa Separations Technology
Inc., to Ron Jordan, EPA, October 10, 1990.
7. SAIC, "Descriptive Statistics and Distributional Analyses of
Cadmium and Mercury Concentrations in Barite, Drilling
Fluids, and Drill Cuttings from the API/USEPA Metals Data
Base," February 1991.
8. Memorandum from SAIC to EPA, "Pass Rate Summary Statistics
for Proposed Cadmium and Mercury Standards Applied to Barite
and Drilling Fluids Data," September 28, 1990.
9. Memorandum from ERG to EPA, "The Adequacy of Available
Foreign and Domestic Supplies of Barite that Meet Revised
Limitations for Cadmium and Mercury Content," November 4,
1987.
VIII-28
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SECTION IX
CONTROL AND TREATMENT TECHNOLOGY
A. INTRODUCTION
This section describes the control and treatment
technologies available for use in the offshore oil and gas
industry for the treatment and disposal of wastewater effluents.
The performance and applicability of these technologies was
evaluated. Some were rejected for the most part due to
technological infeasibility. The performance of those
technologies that are being considered appropriate have been
investigated further. The results of this performance analysis
is what ultimately lays the foundation for the Agency's
regulatory options selection.
Current regulations require compliance with the Best
Practicable Control Technology Currently Available (BPT) effluent
limitations. The 1976 development document1 describes in detail
the basic technologies, treatment effectiveness and analytical
data evaluation used to establish BPT effluent guidelines for
each of these waste streams. A brief description of the control
and treatment technologies used to achieve BPT limitations for
each waste stream is presented in this section. Additional
treatment technologies beyond BPT are presented also which were
investigated for purposes of developing BAT and NSPS.
While control and treatment technologies for all of this
industry's waste streams are described in this section, the focus
of this development document effort has been on treatment beyond
what is required for BPT for the following major streams:
drilling fluids, drill cuttings, and produced water.
IX-1
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B. DRILLING FLUIDS
Disposal practices for offshore oil and gas drilling fluids
are dependent on whether or not they are: 1) water-based fluids,
or 2) oil-based fluids or water-based fluids 'with oil added for
lubricity or spotting.
1. BPT Technology
BPT requirements address the oil and grease content of this
waste stream with use of process control practices plus end-of-
pipe treatment. Process control equipment and practices for
drilling fluids that are commonly used in both offshore and
onshore drilling operations include:
Accessory circulating equipment such as shaleshakers,
agitators, desanders, desilters, mud centrifuges,
degassers, and other mud handling equipment.
Mud saving and housekeeping equipment such as pipe and
kelly wipers, mud saver sub, drill pipe pan, rotary
table catch pan, and mud saver box.
- Recycling/reuse of oil based muds.
BPT end-of-pipe treatment technologies are based on existing
waste treatment processes currently used by the oil industry in
drilling operations. (Detailed discussion of these technologies
can be found in the 1976/1985 development documents.)
The BPT effluent limitations for offshore drilling fluids
prohibit the discharge of free oil in muds that would cause a
sheen upon the receiving water when discharged. Oil-based muds
effectively cannot be discharged to surface waters because of the
prohibition on discharge of free oil and/or diesel oil. These
muds are to be recycled and reused or transported to shore for
reuse or disposal in an approved disposal site.
IX-2
-------
2. Additional Treatment
Waste management^practices which control priority pollutant
discharges in drilling fluids include:
Recycle/reuse
Treatment and/or disposal on land
Product substitution (use of low toxicity drilling
fluids)
Recycle/reuse and on-land disposal are methods used in order
to achieve a zero discharge requirement. Product substitution is
necessary in order to meet discharge limitations for toxicity,
mercury and cadmium, and a prohibition of diesel and free oil
discharges.
EPA considered other treatment or waste management options
including a clearinghouse approach (see 50 FR 34603), and thermal
distillation and solvent extraction (53 FR 41375). These
technologies were excluded from further consideration. Reasons
for this, as well as a discussion of various available treatment
options, are included below.
a) Recycle and Reuse
Since drilling fluids are expensive, the economics of well
drilling provide a high incentive for reuse of both toxic and
low-toxicity drilling fluids. This is particularly true of
fluids that have a hydrocarbon (diesel or mineral oil) liquid
base. However, storage and equipment limitations on drilling
platforms restrict conservation alternatives. Drilling platforms
contain equipment which removes drill cuttings from the drilling
fluid, and the processed fluid is recycled to the well hole.
IX-3
-------
Eventually the drilling fluid becomes contaminated with an excess
of fine particles that cannot be removed by the platform
equipment. The particulates alter drilling .aid characteristics
(e.g., viscosity), which makes the fluid unacceptable for
continued use.
Example'- of reuse practices for contaminated fluids that are
ecc- nmically attractive for oil-base'd muds are:
Mud company buys back the used mud which is
hauled to shore, processed, and re-used.
Mud is treated with additional solids-
suspending agent and used as a packer fluid.
b) Treatment and/or Disposal on Land
EPA also considered zero discharge of drilling fluids for
water-based muds. This option is based upon the transport of
spent drilling fluids and cuttings to shore for recovery,
reconditioning for reuse, or land disposal. This option would
result in no discharge of pollutants to surface wal .rs. EPA
determined that barging drilling wastes is technically and
economically feasible and, in response to both industry and
Agency concerns, has studied the availability of land disposal
capacity. Although the study concluded that enough land is
available to support the disposal requirements for this option
(see Section XIV), EPA has concerns over the use of large areas
for the disposal of drilling wastes. In addition, the increased
barging and handling operations, both on platforms and at dock
facilities, require a significant increase in fuel use and result
in large amounts of air pollutant emissions. For these reasons,
EPA has developed options for zero discharge which require only
certain portions of the industry to meet a zero discharge limit
based on well location. This is discussed in faction XII.
IX-4
-------
The most common methods of disposal for offshore muds and
cuttings are:2
Reserve pit
Stabilization or chemical treatment prior to landfill
Landfarming
Thermal oxidation prior to landfill
Disposal at hazardous waste landfill
Landfarming and stabilization/landfill are the most likely
disposal methods.
Reserve pits3 are used to accumulate, store, and dispose of
spent drilling fluids, cuttings, and associated drill waste
generated during drilling and completion operations. Pits are
built or excavated into surface soil zones or into unconsolidated
sediments (both of which are highly permeable). The pits
generally are unlined. The reserve pit can be used for final
disposal of the drilling waste with or without prior waste
treatment or for temporary storage prior to offsite storage. The
most common onsite disposal methods include:
Evaporation of supernatant
Backfilling and burying of the pit by mixing
the pit solids with the pit wells
Landspreading the pit contents into the area
adjacent to the pit.
Reserve pits usually are used for onshore drilling
operations; however, they are a possible method of disposal for
offshore operations where permitting allows such practices.
IX-5
-------
Stabilization techniques consist of adding chemicals to the -
mud which react to form a solid material that then can be :
disposed of. The equipment, consists of a specially designed
blender to mix the drilling.fluids and chemicals and to pump the
slurry into the prepared area for solidification. The prepared
area can be level farmland that has had the topsoil layer removed
and a shallow pit excavated to contain the volume of fluid/
•
The most commonly employed technique for disposal of
nonhazardous drilling muds and cuttings is landfarming.3
Landfarming is the direct cultivation of the waste into the soil
in order to allow the microorganisms which naturally occur in the
soil to reduce the organics, nitrogen, phosphorus, exchangeable
cations, and trace elements in the waste. A typical landfarm has
the capacity to receive approximately 13,000 barrels of solids
for each acre over its entire operational life.
Treatment of drill waste by thermal oxidation in a rotary
kiln prior to disposal as clean fill or landfilling is practiced
by one firm in Louisiana.2 The process essentially volatilizes
or oxidizes organics present in the waste. The waste is also
dried by the process. Although the process produces an
environmentally stable waste with minimum potential for adverse
impact when disposed on land, the process is more expensive
compared to landfilling, landfarming, or chemical stabilization.
Drilling waste would be disposed at RCRA class C hazardous
waste landfills either when it exhibits hazardous characteristics
or because it is the only available disposal option.2 RCRA class
C landfills are highly regulated and must meet stringent permit
requirements to ensure that the Utility poses little
environmental threat. The landfill cells are lined and generally
have leachate collection systems and monitoring wells to ensure
that the waste is not contaminating the adjacent area. Drill
IX-6
-------
waste disposed in such facilities is designed to pose little
environmental impact. The cost of such disposal, due to the many
, t
inherent safeguards, is considerably more expensive than
nonhazardous landfill^ng, landfarming, or stabilization.
•
The usual methods of transportation of muds or cuttings from
the drilling site to the licensed disposal facilities are supply
boats or barges which take the mud slimes and liquids to a marine
unloading terminal. Once onshore, trucks transport the wastes to
the disposal site.6
c) Product Substitution
Product substitution is a means to lower the toxicity of the
drilling fluid by the use of low-toxicity generic muds, the use
of mineral oil instead of diesel oil, or the use of barite with
low levels of cadmium and mercury.
Drilling fluids which are considered to have "low toxicity11
may be discharged directly to the ocean depths, ranging from just
below the surface to near the ocean floor, if they meet all other
requirements such as the limit on free oil, and mercury and
cadmium content. The key, of course, is in the use of materials
classified as "low toxicity."
During the development of the 1985 proposed regulation, the
Agency conducted a program to determine the relative toxicity of
certain "generic" mud formulations. These generic formulations
would then serve as a basis on which industry and regulatory
authorities could plan effective control of drilling fluid
discharges. The study designated eight generic water-based
drilling formulas exhibiting relatively low toxicity levels. A
listing of drilling fluid additives which exhibit relatively low
toxicity levels in drilling fluid systems has also been compiled
IX-7
-------
(see listing of generic drilling fluids and additives in Section .
VII). Using these "generic" materials as a base, the
acceptability for discharge of other drilling fluids and
additives can be evaluated based upon their constituents and/or
relative toxicity as determined by established laboratory
procedures.
In addition, lower toxicity (elg., mineral) oils generally
have been found to serve as acceptable substitutes for diesel oil
in drilling fluids. Low-toxicity, or mineral, oils are derived
from the same type of crude oil from which diesel oil is derived.
The significant difference between the two types of oils from an
environmental standpoint is the relatively high aromatic
hydrocarbon content of diesel oil and relatively low aromatic
content of mineral oils. The aromatic components of the oils
generally are the components that are most toxic to marine life.
The lower toxicity oils are composed of a wide variation of
paraffinic/naphthenic components with very low aromatic
concentrations. The oils are referred to by various names such
as mineral oils, lower toxicity oils, low aromatic oils, etc.
White oils are even more highly refined and purified mineral oils
that have even lower (sometimes zero) aromatic content. High
purity white mineral oils are used in foods, laxatives,
cosmetics, etc. Thus, the key to lowering the toxicity of
hydrocarbon base oils is to lower, remove, or alter the aromatic
compounds.
Studies conducted prior to the 1985 rulemaking on mineral
oil versus diesel oil in muds concluded that: 1) mineral oils
ar less toxic than diesel oils,7'8'9 2) mineral oil muds may be
more cost effective by reducing the operational costs of cleaning
and disposin: of cuttingr 7 and 3) mineral oil is equally
effective in free g stuc -jipe.10
IX-8
-------
Since the 1985 proposal, the Agency has acquired additional
information of the use of mineral oil as a substitute for diesel
oil for spotting or lubricity purposes. A survey by the American
Petroleum Institute (see Section VI) showed that mineral oil is
being used instead of diesel oil by the industry. Mineral oil
was shown in this study to be more frequently used as a
lubricant, while diesel oil is more.commonly used for spotting
purposes.
An additional study was performed by the Offshore Operators
Committee (see also Section VI). The Agency concluded from this
study that not only is mineral oil in common use and a reliable
alternative to diesel oil, but success rates using mineral oil as
a spotting fluid are comparable to those using diesel oil.
The Agency, in cooperation with API, conducted a study to
determine the effectiveness of removing diesel oils from mud
systems after spotting (see Section VI). Results of this diesel
pill monitoring program (DPMP) showed that current pill recovery
techniques do not result in sufficient amounts of diesel pill and
reduction of mud toxicity to acceptable levels for discharge of
bulk mud systems. Systems for approximately one-half of all
wells in the DPMP contained residual diesel levels between 1-5%
by weight after introduction of a diesel pill and subsequent pill
recovery efforts. In addition, systems for approximately 80% of
the DPMP wells failed the proposed 30,000 ppm LCSO limitation
after pill recovery. Almost half that number (40% of the total)
of the DPMP wells had water-based systems that contained residual
diesel following pill recovery and showed LC50 values of less
than (more toxic than) 5,000 ppm.
Hence, substitution for diesel oil when used for spotting or
lubricity with mineral oil is necessary before a discharge option
IX-9
-------
can be considered. In addition, where diesel oil is used in a
mud system, the treatment/disposal method considered by the
Agency for the muds and cuttings is onshore disposal.
Finally, in order to comply with the cadmium and mercury
limits, the use of barite with a low toxic metals content should
be considered. EPA sponsored an investigation of the
availability of "clean barite" which estimated that adequate
supplies of domestic and foreign barite exist for use in offshore
drilling (see Section VIII). This study showed that quantities
of barite far surpass the amount required for regulatory
compliance.
d) Clearinghouse Approach
In 1985, one of the options proposed for limiting the
discharge of muds was labeled the Clearinghouse/Toxicity
Approach. The clearinghouse concept is based on the fact that
operationally satisfactory drilling fluids can be formulated with
constituents that are less environmentally harmful than many that
are available. As discussed in Section VII, the generic drilling
fluid concept was developed in 1978 when the Agency used NPDES
permits for operations in the Atlantic Ocean lease sale areas to
institute a joint testing program for various formulations. EPA
Region II and the OCC conducted the Mid-Atlantic Bioassay Program
which yielded eight water-based drilling fluid types (generic
fluids) that encompassed virtually all types of drilling fluids
in use at the time. The generic fluids were then bioassayed once
as an alternative to having the DCS. operators in Region II
perform bioassay and chemical tests every time a discharge
occurred. The selected generic fluids demonstrated relatively
low toxicity in the referenced bioassay program. Operators were
then allowed to discharge the generic fluid types, including
certain approved specialty additives ("additives"), without .
IX-10
-------
conducting additional testing. Other EPA Regions used the
results from the generic fluids testing in permits issued for DCS
lease areas.
In the 1985 proposal, Option 2 - Clearinghouse Approach
discussed the establishment of a national clearinghouse to be
•
administered by EPA. The Agency would serve as repository for
all toxicity and related physical and chemical characteristics of
base drilling fluid formulations and additives. The information
would be used by the public and operators for use in selecting
fluid/additive formulations that would likely comply with the
established toxicity regulation.
Based on the 1985 proposal, EPA Region X issued several
NPDES general permits (Norton Sound (50 £E 23578, 6/4/85), Cook
Inlet/Gulf of Alaska (51 FR 35460, 10/3/86), Chukchi Sea and
Beaufort Sea II (53 FR 37846, 9/28/88)). These permits used the
generic fluids concept and authorized the discharge of certain
additives without bioassay testing in the discharged fluids upon
discharge. In all of these permits, Region X listed generic
fluids and additives authorized without further bioassay
requirements in a table in the permit. However, operators
required specialty additives that were not authorized in Region
X's permit. Lacking any method to determine the cumulative
toxicity of generic fluids discharge with additives not in the
permits, Region X applied the concept of additivity to estimate
the cumulative toxicity of fluids and additives.
In the 1985 proposal, the Agency rejected the Clearinghouse
option based on the promulgation of NSPS, the time required to
develop such a program, and the complexity of managing such a
program on a national level. Although the Agency has received
many comments in favor of the clearinghouse type of approach to
IX-11
-------
fluids/additive discharge authorization, several important
reasons remain in support of rejection of this regulatory option.
First, the Agenqv's NPDES permitting program (Section 402 of
the Act) is based on point of discharge (end-of-pipe) accounta-
bility. While bioassays are a good measure of compliance with
discharge toxicity limits, it is a matter of best professional
judgment to authorize the discharge -of fluids/additives on the
basis of cumulative toxicity estimates. Second, one of the basic
permitting principles under Section 402 of the Act is fundamental
accountability at the point of discharge. Since all estimates of
cumulative discharge toxicity are based on bioassays of fluids
and additives before use, they represent toxicity of
fluids/additives upstream of the discharge point. Therefore,
administration of a complex and comprehensive program through
Section 402 of the Act would place a huge burden upon the Agency.
Finally, the Agency would be required to maintain all of the data
with up-to-date information on fluids and additives and provide
resources to track the data, oversee procedures, and respond to
legal challenges.
Although it has been demonstrated that the clearinghouse
system can be effective on a small scale, the Agency has
reservations regarding a nationwide program. The success of the
Region X program is due, in large part, to the relatively small
number of wells drilled in the past and estimated for the future.
(The projected number of new drillings for the Region X offshore
area is 12 per year in the unconstrained scenario). A national
clearinghouse program involving almost 1,000 new drillings per
year and requiring maintenance and updating of a database
containing information on numerous additives and fluids
combinations would be much more difficult to manage and would
place an enormous burden on the Agency.
IX-12
-------
For these reasons, EPA in this rulemaking is not changing
the rejection of this option as proposed in 1985; however, this
does not preclude the use of this type of authorization procedure
as a means of compliance with the national regulation.
•
e) Other technologies
Thermal distillation and solvent extraction were considered
both in the 1985 proposal and 1988 notice. The operation of
these technologies results in a reduction of oil content in
drilling wastes. Thus, the regulated parameter associated with
these technologies would be oil content. EPA rejected these
technologies as a basis for regulatory control on the general
premise that limitations on the other parameters, diesel oil,
free oil, and toxicity are sufficient to reduce toxics from
drilling wastes. In addition, thermal distillation is not
considered an option because it does not reduce pollutants below
the capability of BPT performance. Solvent extraction is not
considered because the Agency remains concerned (as stated in the
1988 notice) over the potential losses of chlorofluorocarbon-type
solvents from these processes to the atmosphere. In addition,
both technologies are not successfully demonstrated. Operating
problems and safety hazards make them unreliable sources for
regulation development.
Incineration was considered but rejected due to equipment
size, energy costs, and possible fire hazards associated with
this process. Some of these technologies may be applicable for
onshore treatment of drilling fluids and cuttings that are barged
and transported to central locations for reconditioning,
treatment, and/or disposal.
IX-13
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C. DRILL CUTTINGS
, i
Pollutant type and waste management practices for drill
cuttings are integrally related to the drilling fluid that was
employed. That is, .drill cuttings from an oil-based drilling
fluid are heavily contaminated with hydrocarbon wastes (diesel or
mineral oil). Cuttings resulting from use of a low-toxicity,
water-based drilling fluid are considered non-toxic and may be
discharged directly if other requirements, such as limits on
cadmium and mercury content of barite and free oil, are met.
Drill cuttings are carried to the surface thoroughly mixed
in drilling fluid. At the surface, a mud treatment system
separates the drill cutting particles from the drilling fluid.
1. BPT Technology
BPT for drill cuttings is based on treatment and disposal
methods presently used by the oil industry. The BPT limitations
for offshore drill cuttings prohibit the discharge of free oil
based upon the presence of a visible sheen upon the receiving
water. Cuttings that contain free oil should be collected and
transported to shore for disposal in an approved disposal site or
sufficiently washed to remove free oil prior to discharge. A
typical mud treatment system contains the following items of
equipment:
Shaleshaker: A vibrating screen through which returning mud
is passed for removal of large solids. The standard shaker
removes cuttings larger than 440 urn while the fine screen
shaker removes cuttings larger than 150 urn.
Desander; A cyclone separator which is designed to remove
solids larger than 40 to 90 urn.
IX-14
-------
Desilter; A cyclone separator similar to the desander but
designed to remove solids larger than 15-25 urn.
Centrifuge; Increases the rate of settling for particles in
a drilling fluid and removes particles larger than 3-10 urn.
Mud Cleaner; A desander for a Veighted mud. The weighting
material (barite) passes through with the mud and the
cuttings and fines are separated.
Figure IX-1 is a flow diagram of a typical mud treatment
system which shows that seawater may be used to dilute the mud
and cuttings prior to disposal.
The drilling fluid is reclaimed and recycled to the well and
the cuttings are sorted out for disposal. Discharge from the
solids control system contains rock cuttings, sand and clay
particles, washwater and residual drilling fluid which has not
been removed from the cuttings.
Disposal of cuttings from lower toxicity, water-based
drilling fluids is generally by direct discharge to the ocean.
Some regulatory authorities stipulate shunting through a vertical
pipe to a specified depth below the water surface. Cuttings
contaminated with oil are either washed, such that a sheen does
not occur upon discharge, or transported to approved land
disposal sites.
2. Additional Treatment
Technologies for cleaning drill cuttings can be classified
according to the following means of separating oil from cuttings:
IX-15
-------
FLOWLINE
DRILL CUTTINGS
MUD CLEANER
CSWECO)
SLUICING
WATER
Source: 11
FIGURE IX-1. FLOW DIAGRAM FOR A TYPICAL SOLIDS CONTROL SYSTEM
IX-16
-------
Mechanical processes
Solvent extraction
Thermal distillation
Table IX-1 presents the technology type, equipment features,
capacity, and performance for each of the systems studied for the
1985 rulemaking. Mechanical processes are generally at the BPT
level. Solvent extraction and thermal distillation technologies
are incremental to BPT.
The 1988 notice of availability included a discussion of
EPA's consideration for an oil content limit for drilling wastes.
Vendor performance data indicates that achieving a residual oil
level of no more than 10% by weight is within the capabilities of
mechanical cleaning systems. However, the Agency rejected the
use of cuttings washer technology as a basis for an oil content
limitation, because it believed that the cuttings washer
technology did not achieve a reduction in oil content of the
drill cuttings sufficient to meet the BPT requirement of "no
discharge of oil." The use of cuttings washer technology appears
to have diminished, possibly due to the relatively high residual
oil content of the processed cuttings and problems with proper
disposal of by-product water/oil/detergent wastes.
Following the 1985 proposal, the Agency investigated other
technologies for reducing the oil content of drilling wastes.
These technologies fall into two general classes. In one class
are thermal processes (thermal distillation or thermal
oxidation). In the other class are solvent extraction processes.
To reduce the level by an order of magnitude (i.e., less than 1%
by weight), more sophisticated solvent extraction or thermal
distillation methods would be required. EPA is not considering
IX-17
-------
TABLE IX-1
CUTTINGS WASHER TECHNOLOGY
00
COMPANY
A
B
C
D
TYPE OF
WASHING
TECHNOLOGY
Mechanics)
(a) Mechanical
(b) Mechanical
(a) Mechanical
(b) Mechanical
Solvent
tixtractkm
FEATURES
Continuous Process, Immersion
Method Seawater Wash, Surfactant,
2-800 Gallon Tanks, Eductors, Screen,
Centrifuge for Fine Particles
Single Stage Centrifuge System for
Mineral OH Based Muds. Agitated
Holding Tank, Pump, Centrifuge.
Two Stage Centrifuge System for
Diesel OH Based Mud, Wash Tank,
Dlspersant and Polymer, Vibra-
Feeder, Centrifuge, Catch Tank,
Pump, Centrifuge.
Seawater Spray, Flume Discharge,
OR Recovery by Submerged Pumps
Agitated Holding Tank. No Detergent.
Pump and Centrifuge
Continuous Process. Diesel Wash
Freon Solvent, Extractor Column,
Oil-Water Separation, Freon
Separation
CAPACITY OF
UNITS
125 Cu. Ft. Per
Hour
5 Tons Per Hour
5-12 Tons Per
Hour
7700 Pounds Per
Hour
25000 Pounds
Per Hour
7000 Pounds
Per Hour
RESIDUAL OIL
ON CUTTINGS
10% by Volume
7-10% w/w of Dry
Cuttings
3-8.5% w/w of
Dry Cuttings
Less Than 6% by
Weight for
Mineral On-
Based Mud
Less Than 10% by
Weight
0.2-1% w/W
REMARKS
Used hi Norwegian North
Sea. for a Union Oil Rig
hi Louisiana
Used hi U.K. North Sea. .
Used hi U.K. North Sea
Used hi U.S. Gulf Coast
-------
TABLE IX-1 (Continued)
CUTTINGS WASHER TECHNOLOGY
X
I
>—1
vo
COMPANY
E
F
Q
H
1
J
TYPE OF
WASHING
TECHNOLOGY
ii»nh •••!«»!
M0U Ml IICol
Mechanical
Vacuum
Distillation
Mecnanwai
BJJu^__Mfld«Al
MBcnarncai
FEATURES
Salt Water Spray, Inclined Trommel
lor SoHd-UqukJ Separation
Diesel Wash, Screen for Coarse
Particles, Centrifuge for Fine
Particles. Sluiced to Seawater
Grinding, Vacuum Distillation Unit,
Condenser for OK and Water, >
Vacuum Pumps
OH Based Wash Solution, Spray,
Screen, Destltlng Cones, Oil-Water
Separators, Flume Discharge
Wash Tank, Dlsperaant, Solid Shaker,
DesDter, Oil-Water Separator
MIxtnQ Tftnk, CVosnfnQ CnofinCflis,
Oil and Sludge Separation, High
Pressure Jets.
CAPACITY OF
UNITS
120 Cu. Ft. Per
Hour
12.500 Pounds
Per Hour
Peak 25,000
Pounds/Hour
6 Barrels Per
Hour
-
3-4 Cu. Ft. Per
Hour
RESIDUAL OIL
ON CUTTINGS .
Less Than 10%.
With Free OH
1 00-500 ppm
100-500 pom
2%
8-7% by Volume
REMARKS
Used In Guff of Mexico,
Off Coast of California
Operated hi North Sea.
i
i
None .
None
Source: 12
-------
these methods for regulatory options selection for the same
reasons as discus-ed under drilling *!"uids.
Rather, EPA is considering the same treatment/disposal
methods as for drilling fluids. Those are product substitution
and on-land disposal. Mineral oil instead of diesel oil would be
required for discharge options, along with the use of barite with
a low metals content to meet limitations on cadmium and mercury.
For those situations where zero discharge is being considered,
on-lane disposal systems would be appropriate.
D. PRODUCED WATER
Treatment processes are primarily designed to control the
oil and grease and priority pollutant content of this waste
stream. Currently, most states allow the discharge of brine to
surface, saline water bodies, subject to limitations on the oil
and grease content.
1. BPT Technology
Oil is present in produced water in a range of sizes from
molecular to droplet. Reducing the oil content of produced water
involves removing three basic forms of oil: 1) large droplets of
coalescable oil, 2) small droplets of emulsified oil, and 3)
dissolved oil. Oil removal units are generally effective in
removing most of the free oil. The removal efficiency and
resultant effluent quality achieved by the treatment unit is
dependent upon the influent flow, the influent concentrations of
oil and grease and suspended solids, and the type of chemicals in
the wastewater.
Examples of working ranges for some oil and grease removal
units are:
IX-20
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Unit Sizes Removed
Flotation above 10-20 um
Parallel plate coalescers above 30-40 um
Proprietary (API) separators above 6 um
Skim Tanks above 15 um
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.13 Any operational change that promotes
the formation of smaller droplets or the stabilization of small
droplets will result in upset conditions and higher contents of
oil in the effluent after treatment. Upset conditions can be
caused by detergent washdowns in deck drainage entering the
treatment unit, unusually high flow volumes caused by heavy
rainfall, and equipment failures. Other factors leading to
treatment plant upsets are slugs of completion and workover
fluids combining with the produced water.
Existing BPT effluent limitations restrict the oil and
grease concentrations of produced water to a maximum of 72 mg/L
for any one day and an average of 48 mg/L for thirty consecutive
days. BPT end-of-pipe treatment can consist of some, or all, of
the following:
Equalization (surge tanks, skimmer tanks)
Solids removal desander (with or without sand washer)
Chemical addition (feed pumps)
- Oil and/or solids removal
Flotation
Filters
IX-21
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Plate coalescers
Gravity separation
Subsurface^disposal (reinjection)
End-of-pipe control technology for offshore treatment of
produced water from oil and gas production primarily consists of
physical/chemical methods. The type of treatment system selected
for a particular facility is dependent upon availability of
space, waste characteristics, volumes of waste produced, existing
discharge limitations, and other local factors. Because of space
limitations on offshore production platforms, oil skimming/
equalization, chemical treatment, and flotations comprise the
most widely used treatment train. See Section VII for wastewater
characterization based on BPT treatment.
While these treatment methods listed above are in place at
existing offshore oil and gas facilities, it should be noted that
the BPT oil and grease limitations were based on the performance
capability of oil/gas separation and/or gas flotation.
a) Equalization
Surge tanks provide surge volume and primary separation of
oil and water before further treatment.
Skim piles remove that portion of oil which quickly and
easily separates from water. 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 baffle plates
where it coalesces (see Figure IX-2). Due to the difference in
specific gravity, oil floats upward through oil risers from
IX-22
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OIL RISERS
I QUIESCENT ZONE
FLOWING ZONE
Source: 14
FIGURE IX-2. TYPICAL SKIM PILE
IX-23
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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 liquid to a skimming vessel for
further treatment.13
b) Solids Removal
The fluids produced with oil and gas may contain small
amounts of sand wh ch must be removed from lines and vessels.
This removal may be accomplished by opening valves to create high
fluid velocity which flushes the sand into a collector or a 55-
gallon drum. Produced sand may also be removed in cyclone
separators .
c) 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 improved the treatment
efficiencies of flotation units, plate coalescers, and gravity
systems .
Three basic types of chemicals are used for wastewater
ti itment. Many different formulations of these chemicals have
been developed for specific applications. The basic types of
chemicals used are:
Surface Active Agents: These chemicals modify the
interfacial tensions between the gas, suspended solids, and
liquids. They ^re also referred to as surfactants, foaming
agents, demulsifiers, and emulsion breakers.
Coagulating Chemicals; Coagulating agents assist the
format! T of a floe and .prove the f station or settling
IX-24
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characteristics of the suspended natter. The most common
coagulating agents are aluminum sulfate and ferrous sulfate.
Polyelectrolytes^. These chemicals are long chain, high
*
molecular weight polymers used to assist in the
agglomeration of colloidal and extremely fine suspended
solid or oil particles.
•
Surface active agents and polyelectrolytes are the most
commonly used chemicals for wastewater treatment. The chemicals
are injected into the wastewater upstream of the treatment unit
and do not require special premixing units. Serpentine pipes,
existing piping arrangements, etc., induce turbulence which
disperses polyelectrolytes throughout the wastewater. Recovered
oil foam, floe, and suspended particles skimmed from the
treatment units are returned to the initial oil/produced water
separation system.
d) Gas Flotation
In a gas flotation unit gas bubbles are released into the
body of wastewater to be treated. As the bubbles rise through
the liquid, they attach to oil droplets in their path, and the
gas and oil rise to the surface where they may be skimmed off as
a froth. Two types of gas flotation systems are presently used
in oil production: 1) dispersed, and 2) dissolved gas flotation
(see Figure IX-3).
Dispersed gas flotation units use specially shaped rotating
blades or dispersers which form small gas bubbles that float to
the surface with the contacted oil. The gas is drawn down into
the water phase through the vortex created by the rotors from a
gas blanket maintained above the surface. The rising bubbles
contact the oil droplets and come to the surface as a froth,
IX-25
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CRUDE OIL PRODUCTION PROCESSING
X
i
ro
PROCESS OH
WATER SEPARATION
(HEATER TREATER.
CHEMICAL. EUC
TRICAI.
GUN BARREL FREE
WATER KNOCK OUT
ETC.I
LOW PRESSURE OIL WELly
INTERMEDIATE
PRESSURE OH
WEIL
SURGE TANK.
SKIMMER TANK
HIGH
PRESSURE
SEPARATOR
HIGH PRESSURE
OIL WELL
SKIMMED OIL RECYCLE
CHEMICAL INJECTION
WASTE WATER TO EITHER
SKIMMED OIL RECYCLE
ROTOR-DISPERSERS
GAS OR AIR
AND CHEMICALS
FLOTATION
UNIT
SKIMMED OIL RECYCLE TO PROCESS SEPARATION
ROTOR-DISPERSER CAS FLOTATION PROCESS DISSOLVED CAS FLOTATION PROCESS
Source t 1
FIGURE IX-3. PLOW DIAGRAM OP GAS FILTRATION PROCESSES FOR TREATMENT OF PRODUCED WATER
-------
which is then skimmed off. These units are normally arranged as.
a series of cells, each one operating as outlined above. The
wastewater flows from one cell to the next, with oil removal in
each cell. ^
Dissolved gas flotation units differ from dispersed gas
flotation because the gas bubbles are created by a change in
pressure which lowers the dissolved gas solubility, releasing
tiny bubbles. This gasification is accomplished by passing the
wastewater through a pump to raise the pressure and then through
a contact tank filled with gas. The wastewater leaves the
contact tank with a concentration of gas equivalent to the gas
solubility at the elevated pressure. When the recycled
(gasified) water is released in the bottom of the cell (at
atmospheric pressure) the solubility of the gas decreases and the
excess gas is released in the form of microscopic bubbles. The
gas and oil then rise to the surface where they are skimmed off.
Dissolved gas flotation units are usually a single cell only.
On production facilities, it is usual practice to recycle
the skimmed oily froth back through the production oil-water
separating units.
The addition of chemicals can increase the effectiveness of
either type of gas flotation unit. Some chemicals increase the
forces of attraction between the oil droplets and the gas
bubbles. Others induce a floe formation which eases the capture
of oil droplets, gas bubbles, and fine suspended solids, making
treatment more effective.
IX-27
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e) Filter Systems
Although not standard for BPT treatment, filters also may be
used to treat produced water. Two types of media are in general
use:
Fibrous media, such as fiberglass, usually in the form
of a replaceable element or cartridge.15
Granular media filters, which normally use a bed of
granular material such as sand, gravel, and/or crushed
coal (see discussion of "Additional Treatment" later in
this section).
f) Parallel Plate Coalescers
Parallel plate coalescers are gravity separators which
contain groups of parallel, tilted plates arranged so that oil
droplets passing through the plates need only rise a short
distance before striking the underside of a plate. Guided by the
tilted plate, the droplet then rises and coalesces with other
droplets until it reaches the top of the plate where channels are
provided to carry the oil away. The general theory of overall
operation of parallel plate coalescers is similar to API gravity
oil-water separators. However, the parallel plates reduce the
distance that oil droplets must rise in order to be separated;
thus unit sizing is much more compact than an API separator.
Particles which tend to sink move down along the plates to the
bottom of the unit where they are deposited as a sludge and can
be periodically drawn off. Particles may become attached (scale)
to the surface of the plates requiring periodic shutdown and
cleaning of the units.
Where stable emulsions are present, or where the oil
droplets are dispersed in the water, separation in this type of
unit may not be possible.
IX-28
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g) Gravity Separation
The simplest form of treatment is gravity separation. The
produced water is retained for a sufficient time for the oil and
water to separate. Tanks, ponds, pits, and, occasionally, barges
are used as gravity separation vessels. Large storage volumes
for sufficient retention times are characteristic of these
systems. Performance is dependent upon the characteristics of
the wastewater, water flow rate, and availability of space. The
majority are located onshore and have limited application on
offshore platforms because of space limitations. While total
treatment by gravity separation requires large containers and
long retention times, any treatment system can benefit from even
short periods of quiescent retention prior to further treatment.
This retention allows some gravity separation and dampens surges
in flow rate and oil content.
h) Reinlection
Subsurface disposal may be used in BPT treatment, but
generally it is used for water flooding which, as a result, meets
BPT limits. Reinjection is discussed further in this section
under "Additional Treatment."
2. Additional Treatment - Improved Performance of BPT
Technology
EPA evaluated the costs and feasibility of improved
performance of existing BPT treatment technologies to determine
whether more stringent effluent limitations for oil and grease
would be appropriate. This technology would consist of improved
operation and maintenance of existing BPT treatment equipment
(e.g., gas flotation, coalescers, gravity oil separation), more
operator attention to treatment system operation, and possible
IX-29
-------
resizing of certain treatment system components for better
treatment efficiency.
Based upon statistical analyses of effluent data from
facilities sampled during the Agency's 30-platform survey, EPA
determined that an oil and grease effluent limitation of 59 mg/L
maximum (i.e., no single sample to exceed) can be achieved
through improved performance of BPT'technology. This limitation
is supported by information presented in the report, titled
"Potential Impact of Proposed EPA Offshore Oil and Gas Extraction
Industry," (January 1984), sponsored by the Offshore Operator's
Committee for the Gulf of Mexico. However, problems with the
original 1984 analysis included lack of documentation for the
platforms selected as examples of improved performance for BPT
and the treatment of samples split for quality control of lab
results as if they were independent samples from the wastewater
treatment process.
EPA has since then performed a re-analysis of this data
which shows that the appropriate limitations are 38 mg/L as a
daily maximum value not to be exceeded in any single daily
composite analysis and 27 mg/L as a monthly average value not to
be exceeded.15* A daily composite sample consists of four grab
samples taken at different times throughout the day. These
potential limitations can be compared to current BPT limitations
of 72 mg/L daily maximum and 48 mg/L monthly average. The
potential limitations are calculated based on the same number of
grab samples per day as current limitations. The data used to
determine the potential limitations were obtained at platforms
whose selection is documented and where split sample results are
averaged prior to capability analysis for the effluent.
The 1985 proposal, in its options selection process, chose
this option for all deep water facilities, and for all gas
IX-30
-------
facilities regardless of water depth. This option, although
still being considered is no longer a preferred option for this
rulemaking because of the problems identified with the
performance evaluation.
•
Aside from the analyses used, the removal of priority
pollutants in BPT treatment systems is a complex phenomenon that
has not been fully explored. While the sampling data indicated
quantifiable reductions of naphthalene, lead, and ethylbenzene
after BPT treatment (i.e., by oil-water separator technology),
the presence of significant levels of priority pollutants (e.g.,
naphthalene and ethylbenzene) in all effluent samples
demonstrates the limitations of such treatment technologies.
3. Additional Treatment - Reinfection
Various technologies for the control of priority pollutants
contained in produced water were studied. These technologies
included zero discharge (reinjection or evaporation), biological
treatment, chemical precipitation, filtration, and activated
carbon absorption. Biological treatment, chemical precipitation,
evaporation for zero discharge, and activated carbon absorption
were determined technically infeasible for the offshore oil and
gas industry (see the 1985 development document) and will not be
considered for purposes of this document. The following
discussion outlines the techniques and design considerations
involved in the selection and possible application for zero
discharge based on reinjection.
a) Industrial Practice
Disposal of produced water by reinjecting it into the
subsurface geological strata can serve a number of purposes:
IX-31
-------
Provide zero discharge of wastewater pollutants to
surface waters.
Increase hydrocarbon recovery by flooding or
pressurizing the oil bearing strata.
Stabilize (support) geological formations which settle
during oil and gas extraction (a significant problem
for onshore and some offshore well fields).
Reinjection is practiced onshore and offshore. Onshore
produced water reinjection is a well-established practice used
for most produced water disposal.
In Texas, the largest oil-producing state in the United
States, more than 99% of all produced water generated onshore was
being reinjected as of the late 1970s.16
In California, 58% of onshore.produced waters were
reinjected, and all of the produced waters offshore were
reinjected (also as of 1978)." Reasons for reinjection are
primarily for enhanced recovery by water flooding. In fact, the
demand for offshore water flooding exceeded the total amount of
produced waters available through California's offshore oil
production. To meet this demand, 72.5 million barrels of water
produced onshore were reinjected offshore. The usual practice is
to convert a marginally producing well, on an offshore platform,
to serve as a reinjection well. It is not the usual industry
practice to drill a new offshore well for reinjection.
In Louisiana, about 65% of the total onshore produced water
was be, ng reinjected for disposal purposes as of 1978. Most
offshc^a producers treated to meet BPT discharge standards.16
Since the 1970s, water flooding both for enhanced recovery
and for secondary recovery of marginal wells is increasingly
performed where possible.
IX-32
-------
In the Gulf of Mexico, most produced water from offshore
platforms receives BPT treatment and is discharged overboard.
Onshore reinjection experience in Texas and Louisiana has shown
that the regional geology is particularly well suited for the
reinjection of produced waters. Also, geological formations are
similar and thus produced water reinjection conditions are
essentially the same offshore and onshore.
Additional examples of injection are found in Alaska. Water
flooding is employed at a majority of the platforms in Cook
Inlet.17 Also, reinjection of produced waters is the proposed
means of disposal at the Endicott Project (Beaufort Sea).18
Reinjection of produced water is considered to be
demonstrated and technically feasible for the disposal of
produced water for facilities in the Gulf of Mexico, California,
and in Alaskan waters.
b) Well Selection and Availability
Many of the requirements in the planning, design, and
operation of a produced water reinjection system are the same
whether the location is onshore or offshore. Significant
operational parameters include scaling, corrosion,
incompatibility with receiving stratum, and bacterial fouling.
In addition, important design parameters must be considered such
as selection of a receiving formation, preparation of an
injection well, and choice of equipment and materials. These
design considerations are discussed below.
Reinjection of produced water from new sources in the Gulf
of Mexico depends upon the availability of suitable disposal
formations offshore. Initially, there will be little demand for
IX-33
-------
produced waters as reinjection fluids to enhanced recovery. The .
produced water would be reinjected for disposal purposes only.
The onshore reinjection experience in Texas and Louisiana has
shown that the regional geology is particularly well suited for
the injection of produced water. Suitable disposal formations
are generally available in the production leases. Since in the
Gulf region the geological conditions are essentially the same
offshore and onshore, it is concluded that suitable disposal
formations are available offshore in the Gulf of Mexico.
Further, adequate reservoir capacities are available for the
reinjection of all produced waters from new sources. It should
be noted that, consistent with the onshore experience, there may
be instances where a suitable disposal formation may not be
available at each and every offshore facility. Reinjection at
different offshore locations would be required in these cases.
Selection of the receiving formation should be based on
geologic as well as hydrologic factors. This is to determine the
injection capacity of the formation and the chemical
compatibility of the injected produced water and the water within
the formation. The important region-wide 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
reinjection 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
IX-34
-------
2) solution vugs and fracture channels. Formations with
intergranular openings are usually made up of sandstone,
limestone, and dolomite formations and often have vugulor or
cavity-type porosity*^ Also, limestone, dolomite, and shale
»
formations may be naturally fractured. Formations with solution
vugs and 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 high in suspended solids to be injected into the
receiving formation under minimum pumping pressure with a minimal
amount of produced water pretreatment at the surface.
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 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 reinjected 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 reinjection exceeds fluid
withdrawals. Pressure-depleted aquifers of older producing
reservoirs are highly desirable as disposal formations.
Formations capped or sandwiched by impervious strata
generally will assure that fluids pumped into the formation will
remain in place and not migrate to another location.18 Previous
producing formations are again ideal for disposal because fluids
originally were trapped in the formation. Fluids reinjected into
IX-35
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those formations also will be trapped and will not migrate into
other areas.
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.19 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) place an
impermeable formation adjacent to the disposal formation creating
a trap which will limit the area available for disposal, or 2)
place a different permeable formation opposite the disposal
formation which could allow fluids to migrate to unintended
locations. The third possibility is that 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. Either the
second or third possibility has the potential to create a
pollution problem.
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.19 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. Unknown at the time
of drilling was that 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.
IX-36
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Whether the objective is enhanced ("secondary") recovery or-
disposal, a primary requirement for the proper design of a
reinjection well is that the produced water are delivered to the
receiving formation without leaking or contaminating fresh water
or other mineral bearing formations. The reinjection 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 reinjection from offshore
platforms, equipment and storage space must be provided at the
facilities.
Reinjection of formation water into the producing formation
may be the most attractive option.18 Fluids injected down dip of
producing wells would migrate back to the areas where they were
originally trapped, compatibility of formation and reinjected
waters should not be a problem, reservoir pressure may be low,
and formation permeability and areal extent should be adequate.
In essence, the reinjected water is going back to the place from
where it was produced.
Whether or not this is desirable from the operations point
would be dependent upon conditions existing in the production
area. Reinjection is a routine practice in California because
the oil is viscous and reinjected water is used as a water flood
for enhanced oil recovery (EOR). Reinjection into producing
formations is not, however, extensively practiced either onshore
or offshore along the Gulf Coast because of potential problems
that water flooding can cause by changing the field pressure.19
These pressure changes can cause a production loss from either
coning at the wellbore or, if there is directional permeability
within the reservoir, the rapid return of injected water back to
IX-37
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the wellbore. Increased pressure can also cause movement of the.
oil/water and oil/gas contacts away from the wellbore. Depth
changes of these contacts can result in reduced production at
wells located near the contacts and the loss of oil because of
adhesion to rock particles not previously saturated with oil.
Reinjection into producing formations does not have the same
beneficial economics for Gulf Coast operators as it does for West
Coast operators. Because each production area has its own unique
set of conditions, each site must be individually evaluated for
potential problems that may arise from reinjection into a
producing formation.
Reinjecting ito marginal or abandoned wells is desirable if
available. Since pressure-depleted aquifers of older producing
reservoirs are highly reliable receiving formations, conversion
of a marginal w II to a reinjection well is often a desirable
alternative. The cost of conversion of an existing well is also
much less costly r .ian drilling a new well.
c) Pretreatment of Produced Water Prior to
Rein-iection
Pretreatment of produced water may be necessary to prevent
scaling, corrosion, precipitation, and fouling from solids and
bacterial slimes. Corrosion and deposits lead to decreased
capacity in the equipment and to plugging in the underground
formation. One method o. overc .ing this problem is to increase
reinjection pressures. However excessive i* ection pressure may
fracture the r neiving format ic,. causing the .scape of produced
water into fresnwater or other mineral bearing formations.
In California pretreatment may consist of gravity
separation, gas flotation, and filtration. Offshore facilities
in Louisiana typically pretreat using separation and sedimen-
tation. While this level of treatment may be more than current
IX-38
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practices in the Gulf of Mexico, space requirements or
reliability of such pretreatment technology should pose no
additional problems beyond those encountered in other states.
Treatment systems may be classified as closed (absence of
air) or open (presence of air), although some systems employ
features of both. The closed system prevents produced water/air
contact and, thus, maintains the chemical equilibrium of the
fluid by alleviating the problems arising from oxygen induced
corrosion, scaling, and chemical precipitation. In pressure
vessels, where oil-water separation and emulsion treating are
carried out, a closed system is advantageous. In a closed
system, a blanket of natural gas is maintained over the produced
water in pipelines and tanks. An oil blanket is not an effective
method of preventing oxygen contamination.
In open systems produced water is aerated for two primary
purposes. The first purpose is to drive all acid-causing gases
(carbon dioxide and hydrogen sulfide) out of solution and reduce
corrosion. The second is to oxidize iron and form precipitates
which will be retained in settling tanks or on filters, thereby
preventing these precipitates from coming out of solution in
another part of the system or in the formation. If manganese is
present, it also will be oxidized and precipitated. Aeration has
one disadvantage in that oxygen is dissolved in the water and
will cause corrosion downstream in the system. For this reason,
the use of aeration should be carefully controlled.
Pretreatment in a closed system may consist -of residual oil
removal and filtration prior to reinjection. In an open system,
the treatment train may be residual oil removal, aeration and
gasification, chemical treatment, including coagulation and
settling, and filtration prior to reinjection.
IX-39
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4. Additional Treatment - Filtration
In the 1985 proposal, EPA considered filtration as both an
add-on technology to^BPT and as pretreatment for reinjection.
The primary purpose of filtration is to remove suspended matter,
including insoluble oils, from produced water. Additional
removal of soluble pollutants can also be achieved, but not as
significantly as the reduction of conventional pollutants such as
suspended solids and oil and grease. The 1985 proposal
considered the granular media technology as an option for
treatment of produced waters, but only for BCT and NSPS, since
significant reduction in soluble organics or metals was not
evident. For NSPS, the proposal included, as an option,
limitations for both TSS and oil and grease of 20 mg/L monthly
average and 30 mg/L daily maximum. However, this option was
rejected in the 1985 proposal because of high aggregate costs.
After the 1985 proposal, EPA continued to evaluate
filtration technologies. In fact, an intensive granular media
filtration study (known as the three-facility study and discussed
under the Data Gathering section) was conducted to acquire
additional data on the performance of this technology. In
addition, the Agency has been supplied with vendor information on
a newer filtration technology known as membrane filtration.
Membrane filtration is more effective in removing constituents of
wastewaters which are normally referred to as soluble and are
more resistant to physical separation by filters. However, the
three facility study showed significant removals of hydrocarbons
from granular media filtration as well.
a) Granular Media Filtration
Granular media filtration involves the passage of water
through a bed of filter media with resulting deposition of
IX-40
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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, and effluent quality. There are a number
of variations in filter design. 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 flowrate control: constant-rate
or variable-declining-rate.20 See Figure IX-4 for an
illustration of an upflow media filter.
Filtration is widely used for produced water treatment at
onshore facilities throughout the United States as well as at
offshore facilities located in California state waters. The
filters are used as a polishing step for the removal of suspended
solids and are usually preceded by oil removal treatment
facilities. High levels of treatment which include filtration
are generally utilized to improve the injectivity of produced
waters into underground reservoirs for enhanced oil recovery.20
Filtration is used, but much less frequently, for pretreatmeht
prior to injection for disposal. Although the additional
treatment costs money, it often saves money in the long run by
reducing the power necessary for injection and minimizing
remedial treatment on injection wells. The idea is to remove
anything from the water which could plug injection lines or
formation flow channels, causing a gradually increasing back-
pressure against injection pumps.
During the three-facility study (discussed in Section VI),
the effluents from three platforms were sampled and analyzed.
All used granular media filtration as a means of pretreatment
prior to reinjection. Table IX-2 describes the characteristics
of the three facilities sampled. Flow diagrams of two of the
pretreatment systems studied are shown in Figures IX-5 and IX-6.
IX-41
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TABLE IX-2
CHARACTERISTICS OF PLATFORMS SAMPLED
IN THE THREE-FACILITY STUDY
LOCATION
PRODUCED WATER
(bbl/d)
TREATMENT
PURPOSE OF
INJECTION
X
I
New Mexico
California
coast
Gravel island
off Long Beach,
California
18,000
10,000
100,000
Skim tanks,
polymer addition,
sand filtration
Skim tanks, gas
flotation, granular
media filtration
Skim tanks, gas
flotation, polymer
addition, ultra-
high rate, granular
media filtration
Meet BPT zero dis-
charge ; enhanced
oil recovery
Enhanced oil
recovery
Waterflooding;
enhanced oil
recovery
-------
-
=:—. Scoantcd hydroarbom .
ijiii
Source: 21
FIGURE IX-4. GRANULAR MEDIA COALESCER
IX-43
-------
VATCR
SI
PRODUCED
VATCR
rRTJH —*-
BATIEWIES
X
i
SKIN TANK
TO OIL
RtCDVERY
Ml • WWIIH* POIHT
VI 9* • MCKMSN
31 SV0 • DISPOSAL CONTMCTO*
OIL
S4
*
TO SVO
2
TO SVO
FILTER
FEED TANK
IT301 I
S?
1
riLTCR
TEED
rtto
rtLTRATION
13 UNITS I
BV VATCR
riRST TLOSM
SKIMMED
OIL
TANK
0ACKVASH
TANK
(T302I
A
to
rttto
rm INJECTION
Sourcet 22
FIGURE IX-5. PRODUCED HATER REINJECTION SYSTEM FOR A PLATFORM IN NEW MEXICO
-------
OIL
DEMULSIFIER
COAGULANT
DISPERSED
GAS FLOTATIONS
- UNITS
PUMP
SOLIDS ^
TO *
SHORE
S4
TO
INJECTION "
WELLS
NOTES:
MAKEUP WATER
FROM PIER J
{M-S9
RECEIVING
TANK
JL-
SAMPLING
POINTS
BACKWASH
WATER
ULTRA
HIGH RATE
FILTERS
4 - UNITS
AIR
BLOWERS
PUMP
Sourcei 23
FIGURE IX-6. PRODUCED WATER REINJECTION STSTEM FOR A PLATFORM IN LONG BEACH, CALIFORNIA
-------
Data from these two systems were used to determine granular media
performance. These particular operations i^-'ect produced water
because of the zero discharge permit requirements, to enhance oil
recovery, or for water flooding.
At the New Mexico facility illustrated in Figure IX-6,
approximately 18,000 barrels per day of produced water are
treated. To provide sufficient water for reinjection purposes,
approximately 5,000 barrels per day of fresh water is added to
the produced water before filtration, requiring the filters to
handle approximately 24,000 barrels per day. Filter water is
returned to the various batteries for reinjection. The skim
tanks receive all the produced water from the oil field after the
initial removal of oils is complete at each battery of the oil
field. The skim tanks remove additional oil by gravity before
treatment. Fresh makeup water is combined with the produced
waters at the filter feed tank. These combined waters are pumped
to three sand filters. Normally, two filters are operating in an
upflow direction whil, the third either is on standby or
backwashing. The filtered water is returned to the batteries for
reinjection. Prior to the filters, chemicals are added to the
water consisting of a corrosion inhibitor, a coagulant, and a
flocculent aid.
EPA statistically analyzed the data from this study to
determine effluent levels achievable from granular-media
filtration technology. Data from only two of the three
facilities (those in Figures IX-5 and 6) were used in this
analysis, because performance of one of the facilities'
filtration systems was low due to the absence of chemical
pretreatment prior to filtration.
IX-46
-------
Table IX-3 shows the performance of granular media
filtration from the three-platform study. Pollutants not
included in this table were either not detected or detected only
once.
The applicable effluent limits based on granular media
filtration were developed from data collected for the three-
facility study. As shown in Table IX-3, the long-term average of
11.33 mg/L is the mean oil and grease concentration. The daily
maximum, a value not to be exceeded, is the 99th percentile. The
daily maximum was statistically determined to be 29 mg/L. And
the monthly average of 16 mg/L is the 95th percentile for the
average of four oil and grease observations.
b) Membrane Separation Filtration
The use of membrane separation by crossflow microfiltration
to treat produced water is a relatively new application for this
process. Membrane, (or ceramic) filters are used to separate
oil, bacteria, solids, and emulsified material from water in
several industrial applications, including the dairy, beverage,
pharmaceutical, drinking water, and industrial wastes categories.
The resulting discharge is low in oil and solids. A concentrated
sludge requiring disposal is also produced.
Crossflow microfiltration is a separation and concentration
technology utilizing a solid microfilter support (polymeric or
inorganic) and a "dynamic membrane11. The contaminated produced
water is chemically pretreated to flocculate a portion of the
emulsified oil and suspended solids. The treated water is then
introduced into the filtration device, flowing tangentially to
the surface of the. membrane. The ceramic filters consist of
multichannel, cylindrical tubes (or passages) in a ceramic block
(See Figures IX-7 and IX-8). The channels are superstratified
IX-47
-------
TABLE IX- 3
GRANULAR MEDIA FILTRATION EFFLUENT
POLLUTANT PARAMETER .' LONG-TERM AVERAGES*
Conventional e
TSS 21.17
Oil and grease 11.33
Organic s (ug/L)
Benzene 4,390.30
Benzoic acid 759.37
Ethylbenzene 475.39
M-xylene 129.17
Naphthalene 26.75
0 + P-xylene 74.87
0-cresol 83.29
P-cresol 150.18
Phenol 191.95
Toluene 2,492.29
2-methylnaphthalene 10.60
2-propanone 318.27
2,4-dimethylphenol 80.76
Metals (ug/1)
B 22,418.26
Ba 19,834.99
Cu 54.84
Fe 2,640.56
Mg 368,847.11
Mn 151.30
Na 16.922.879.86
Ti 6.93
V 3.94
Zn 30.42
* Long-term averages are determined using the statistical method employing natural
logarithms of average platform medians.
Source; 24
IX-48
-------
X
4t
tO
I
f
i r
MULTICHANNEL ELEMENT
GASKET
J
i
METAL HOUSING
Sourcei 26
FIGURE IX-7. CROSS SECTION OF A MONOLITHIC MULTICHANNEL MEMBRALOX* CERAMIC FILTER
-------
FEED
PT^IUS SUPPORT
MEMBRANE
x
01
o
CHANNEL
CONCENTRATE
PERMEATE
Sources 25
FIGURE IX-8. MODULE ASSEMBLY OF SEVERAL MULTICHANNEL ELEMENTS
-------
with one or two aluminum ceramic layers which form the filter.
This material is resistant to organics and can withstand the full
range of pH.
The fluid that passes through the membrane (permeate) is
depleted in contaminants (potentially dischargeable), while the
fluid that flows tangentially to the filter surface (or rather
through the channels), is enriched in contamination (retentate).
The retentate is then recycled back into the feed, and with
successive passes through the filtration device, is concentrated.
A periodic blowdown of the retentate is necessary.
By regulating the velocity of tangential flow (crossflow),
the membrane is controllably "fouled". Fouling is the process in
which a concentration polarization effect reduces the pore size
of the membrane and functionally increases the rejection of the
membrane. Fouling can lead to complete obstruction of the
membrane resulting in loss of permeate flow. However, by
controlling the degree of fouling, the rejection properties of
the membrane can be tailored to the contaminant type and degree
of cleanliness, while maximizing permeate flux rates. This mode
of filtration utilizes a "dynamic membrane". The dynamic
membrane is formed during the actual separation and is
transitory. The properties of the dynamic membrane are
controlled by the types of pre-treatment chemicals, the crossflow
velocity, and transmembrane pressure.
The crossflow microfiltration system is not totally immune
to fouling, and eventually must be cleaned to restore permeate
flux rates. Cleaning can be accomplished through such processes
as chemical cleaning, backwashing, or backpulsing.
IX-51
-------
The units can tolerate high temperatures and pressures,.
and, due to their compact size, are suited for use on offshore
oil and gas platforms.
The Agency has been supplied with information concerning one
full scale ceramic membrane filtration unit operating in the Gulf
of Mexico and data from pilot scale tests conducted in Kansas,
Alaska, California, Canada, the Gulf of Mexico, and the North
Sea. Table IX-4 shows the results of some of these tests.
Tests using produced water from a North Sea operation showed
oil and grease concentrations in the filtration effluent to
average 4 mg/L. Feed concentrations averaged 50,000 mg/L. Tests
performed at an onshore facility in Louisiana showed effluents of
<8.8 mg/L oil and grease where feed levels ranged from 166-583
mg/L. Feed streams were effluents from oil and grease separation
and chemical addition operations. In a commercial scale test
program in the Gulf, membrane effluents were less than 5 mg/L in
tests also performed on pretreated (chemical/water precipitator)
produced waters containing oil and grease at levels of 27-108
mg/L. TSS effluent from these tests were <1 mg/L.
Table IX-5 presents data on conventional pollutant removal
from a pilot scale operation in Louisiana using membrane
separation. As shown in Table IX-5, total oil and grease removal
is 97.6%; soluble hydrocarbon removal is 95.3%. Assuming that
all of the organic pollutants are dissolved in the produced
water, it can be concluded that their removal expectancies via
membrane separation should also be approximately 95%.
The data received thus far indicate that the oil and grease
concentrations in produced water have been consistently reduced
by the application of this equipment to effluent levels ranging
from 2 to 9 mg/L. This equipment may be utilized as add-on
IX-52
-------
Gulf**
Gulf**
TABLE IX-4
MEMBRANE SEPARATION TECHNOLOGY PERFORMANCE
Location
North Sea*
LA**
Test
Scale
Bench
Pilot
Character of
Feed
Spiked
Raw produced water
Effluent from
Infl.
50,000
R/L)
£££*
4
166-583* <8.8
TSSfmg/L")
Infl . Ef f 1 .
N/A N/A
N/A N/A
separator/chemical
addition
Commercial Chemical addition/
water precipitator
Pilot
*Source: 27
**Source: 25
Chemical addition/
water precipitator/
Parallel plate
coalescers
27-108 <5.0 100-290* <1
105-574 2-5 73-350* <1
IX-53
-------
TABLE IX-5
MEMBRANE SEPARATION CONVENTIONAL POLLUTANT REMOVAL
REMOVAL
FEED EFFLUENT EFFICIENCY
Ph 6.3 5.5-6.5
Total oil & grease (mg/L)
High 992 20
Low 75 10
Average 584 14 97.6%
Soluble hydrocarbon (mg/L)
High 345 . 12
Low 35 2
Average 154 7 95.3%
TSS (mg/L) 175 - 800
-------
technology or as replacement equipment for present produced water-
treatment technologies and shows potential for more efficient
removals of the soluble oil and grease (organics) than the BPT
technology and granular-media filtration technology.
Extensive testing has also been conducted on membrane
filtration systems in Canada and the Netherlands. Pilot scale
data on a Canadian unit have been supplied to EPA by the same
vendor, which showed oil and grease removals to 1 mg/L from
influent produced water levels of 100-500 mg/L.29 A full-scale
commercial unit is in place in Canada awaiting start-up in late
1990.30 Two additional commercial units are committed to
production, one in the North Sea and one in the Gulf.30
Assimilation of available data regarding membrane filtration
performance has resulted in a determination of pollutant
reduction potential estimates as shown on Table IX-6. Organic
removals capability is determined to be 95% based on the
performance of membrane filtration. Other metal pollutant
removal determinations are also given in Table IX-6.
The effluent limits based on membrane filtration were
developed from data with an assumed detection limit (ASTM
Gravimetric Method 4281) of 5.0 mg/L. Data obtained from
performance tests of the membrane technology are reported lower
than this limit (as low as 1 mg/L), but the Agency believes that
it is not appropriate for technology based limitations to be set
lower than the minimum level (a form of "detection limit")
specified for the Agency approved oil and grease method. Hence,
the Agency will consider 5.0 mg/L to be the long-term average oil
and grease concentration. The daily maximum limitation of 13
mg/L and the monthly average limitation of 7 mg/L are calculated
using the variance estimated for granular media filtration.
Since membrane and granular media filtration are similar
IX-55
-------
TABLE IX-6
ESTIMATES OF MEMBRANE FILTRATION PERFORMANCE
Baseline .Membrane Filtration
Contaminant Concentration Effluent*
n-alkanes 1642** 82
2-butanone 1670** 84
Steranes 63** 3.2
Triterpanes 76** 3.8
Benzene 1823 91
Bis(2-ethylhexyl)
phthalate 101 5.1
Ethylbenzene 505 25
Naphthalene 138 6.9
Phenol 954 48
Toluene 1545 77
2-4-dimethyl-
phenol 14.4 0.7
Copper 183.42 54.84
Zinc 2360 30.42
*0rganics estimates based on 95% removal. Metals removal based
on performance of granular media filtration.
**Source: 31
IX-56
-------
technologies, relying principally on a physical separation
process, the variance estimated for granular media filtration is
believed to be roughly equivalent to that associated with
membrane filtration. The primary difference between these
technologies is believed to be the mean effluent concentration.
This assumption will be tested by obtaining data from full-scale
operation of this technology in an offshore environment before
promulgation of the final rule.
c) Other Technologies
EPA has not considered technologies other than those just
previously described for this rulemaking. In 1985, EPA
considered other technologies such as carbon adsorption and
biological treatment for treatment of produced waters. Carbon
adsorption was rejected from further investigation due to lack of
performance data. Biological treatment was rejected because of
the severely difficult problems associated with biologically
treating briny wastes. Chemical precipitation was also
considered but rejected because of operational problems and
nonguantifiable reductions of priority pollutant metals levels.
The use of hydro-cyclones to treat produced water was also
investigated in 1985. This process uses the kinetic energy of
pumped produced water to spin it causing materials of different
specific gravity to separate, in this case, oil and water. A
hydro-cyclone is a cylindrical tube with a conical end. The
pumped produced water enters the tube tangentially and spins
around the internal diameter of the tube. The oil is removed at
the center of the cylindrical portion of the tube and the water
is removed at the center of the conical portion.
Theoretically, the higher the pressure that the units are
operated, the higher the spinning velocity and the greater the
IX-57
-------
contaminant removal. The units are relatively simple to operate -
and are suited for use on offshore platforms. Little maintenance
is required except for unit or liner replacement due to wear.
The removed oil can be combined with the platform oil production.
Information on this technology at the time demonstrated only that
it was capable of meeting the BPT limits for oil and grease.
E. WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS
1. BPT Technology
The current BPT requirement for these fluids is "no
discharge of free oil" to receiving waters.
Water treatment processes are not provided for each well
fluid. Many well fluids mingle with drilling fluids or produced
water and are co-treated with these waste streams. If they
appear as discrete slugs upon resurfacing, (which can be
determined by close sample monitoring), then one of 4 options
exist32:
Disposal
• Storage
• Reuse
• Treatment and Discharge
Some of these fluids can be reclaimed and reused after
processing. Others such as stimulation or fracturing materials
are mostly lost to the formation. When a well is turned into
production, the fluid lost to the formation usually appears with
the oil or gas and is co-treated with the produced water. This
fluid can often cause upsets in the water treatment equipment.
Fluid not lost to the formation is saved and re-used because of
its high cost.
IX-58
-------
Acids used in stimulation and workover are usually
neutralized by the formation and may return to the surface with
oil or gas. This material either ends up in the produced water
and is treated and disposed of together with the produced water,
or is neutralized separately and discharged.
2. Additional Technology
Because treatment completion and workover fluids are often
commingled with produced fluids, EPA considers Best Available
Technology for this waste stream to be equal to that considered
for produced waters. However, EPA believes that in instances
where fluid slugs (often the method of application) resurface as
discrete slugs, a zero discharge requirement is appropriate.
This zero discharge requirement would involve capturing the slug
plus a 100-barrel buffer on either side of it. These fluids
would be contained and sent onshore for disposal.
F. PRODUCED SAND
EPA has not promulgated effluent limitations guidelines for
produced sands. NSPS and BAT for this waste stream were first
proposed in 1985 with a no discharge limitation of free oil.
The fluids produced with oil and gas may contain small
amounts of sand, which must be removed from lines and vessels.
This may be accomplished by opening a series of valves in the
vessel manifolds that create high fluid velocity around the
valve. The sand is then flushed through a drain valve into a
collector or a 55-gallon drum. Produced sand may also be removed
in cyclone separators when it occurs in appreciable amounts.
IX-59
-------
The sand that has been removed is collected and taken to
shore for disposal; or the oil is removed via solvent wash and
the sand is discharged to surface waters directly.
Field investigations have indicated that some Gulf Coast
facilities have sand removal equipment that flushes the sand
through the cyclone drain valves, and then the untreated sand is
bled into the waste water and discharged overboard.
No sand problems have been indicated by the operators in the
Cook Inlet area. Limited data indicate that California pipes
most of the sand with produced fluids to shore where it is
separated and sent to State approved disposal sites.
At least one system has been developed that will
mechanically remove oil from produced sand. The sand washer
systems consist of a bank of cyclone separators, a classifier
vessel, followed by another cyclone. The water passes to an oil
water separator, and the sand goes to the sand washer. After
treatment, the sand is reported to have no trace of oil, and the
highest oil concentration of the transferred water was less than
1 ppm of the total volume discharged.1
G. DECK DRAINAGE
1. BPT Technology
BPT for deck drainage was promulgated as no discharge of
free oil. This standard is based on control practices used
within the oil producing industry and includes the following:
Installation of oil separator tanks for collection of
deck washings.
IX-60
-------
Minimizing of dumping of lubricating oils and oily
wastes from leaks, drips and minor spillages to deck
drainage collection system.
Segregation of deck washings from drilling and workover
operations.
O&M practices to remove all of the wastes possible
prior to deck washings.
BPT end-of-pipe treatment technology for deck drainage
consists of treating this water with waste waters associated with
oil and gas production. The combined systems may include
pretreatment (solids removal and gravity separation) and further
oil removal (chemical feed, surge tanks, gas flotation). The
system should be used only to treat polluted waters. All storm
water and deck washings from platform members containing no oily
waste should be segregated as it increases the hydraulic loading
on the treatment unit.1
ways:
Discharges from deck drains can be handled in one of several
32
Separate treatment - common on the Gulf Coast and
in Alaska
Combined with produced water and treated - common on
the Gulf Coast
Combined with produced fluids and piped to shore -
common in California
Combined with other wastes, treated, and piped to
shore
Platforms using treatment systems dedicated to the treatment
of deck drainage often use skim piles; skim piles have been used
successfully to meet Gulf Coast and California discharge
regulations which prevent the discharge of free oil. These skim
IX-61
-------
piles average 70 meters in length, with a diameter of 1 meter,
and weigh about 30 tons.
A study of Region II discharges found that for deck drainage
treatment systems to operate properly, three basic components
were necessary: 1) settling tanks of sufficient capacity, 2)
desander (hydrocyclone), and 3) oil-water separation unit (type
not specified)32. If these conditions were met, the effluent oil
and grease concentrations were below a monthly average of 30 mg/L
and a daily maximum of 52 mg/L.
The settling tank should allow sufficient time for the
settling of the settleable suspended solids (primarily muds).
The desander removes additional suspended material which, if not
removed, might plug the oil-water separator unit. Plugging
greatly reduces the efficiency of the oil-water separation unit,
which is used to remove oil and grease from the water prior to
discharge.
A summary of data from Region VI Discharge Monitoring
Reports (DMRs) for April 1981-April 1982, and April 1982-April
1983, indicates that oil and grease concentrations had a monthly
average of 22 mg/L and 28 mg/L, respectively, and monthly
maximums of 51 mg/L and 75 mg/L, respectively32. Other Region VI
DMR data (August 15, 1986 to June 30, 1987) from a single
company's platforms show that the monthly average flow from deck
drainage discharges averaged 700 bbl/month32. Data from the Cook
Inlet, Alaska indicate the most effective system for treatment of
deck drainage wastewater is gas flotation32. Oil and grease
concentrations of deck drainage discharges from 23 Gulf of Mexico
platforms were generally less than 0.1 gallon per day. The same
study reported that oil and grease concentrations from deck
drains was less than 15 ppm.
IX-62
-------
2. BAT
, t
EPA considers Best Available Technology for deck drainage to
be equal to that for produced waters. Deck drainage can be
commingled with produced waters, to meet performance capabilities
of produced water treatment technologies.
H. SANITARY WASTES
There are two alternatives to handling of sanitary wastes
from offshore facilities. The wastes can be treated at the
offshore location, or they may be retained and transported to
shore facilities for treatment. Offshore facilities usually
treat waste at the source. The treatment systems presently in
use may be categorized as physical/chemical and biological.
1. BPT Technology
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 a safety hazard at some locations.
Some facilities have chemical toilets which require hauling of
waste and create odor and maintenance problems. Macerator-
chlorinators have not been used offshore but would be applicable
to provide minimal treatment for small and intermittently manned
facilities. At this time, there does not appear to be a totally
satisfactory system for small operations.
IX-63
-------
The most popular biological system applied to offshore
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 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 ten occupants and are
continuously manned.1
BPT for sanitary wastes from offshore manned facilities with
ten or more people was promulgated as 1 mg/L residual chlorine
(for Sanitary-MlO) and no discharge of floating solids (for
Sanitary M91-M). 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, gravity clarifier, return sludge system, and
disinfection contact chamber or other equivalent system. Studies
of treatability, operational performance, and flow fluctuations
are required prior to application of a specific treatment system
to an individual facility.1
2. Additional Technologies
EPA has not evaluated any additional control beyond BPT for
this waste stream.
I. DOMESTIC WASTES
EPA has not promulgated effluent limitations for domestic
wastes for the offshore oil and gas industry. A standard of no
discharge of floating solids was proposed in 1985 for NSPS.
IX-64
-------
Domestic wastes result from laundries, galleys, showers,
etc. Since these wastes do not contain fecal coliform, which
must be chlorinated, they must only be ground up so as not to
cause floating solids on discharge. Traceration by a comminutor
should be sufficient treatment.
Since these wastes contain no fecal coliform, chlorihation
is unnecessary. Treatment, such as the use of macerators, is
required to guarantee that this discharge will not result in any
floating solids.1
In addition, EPA has determined, based on review of existing
permits, that a control of foam (as no visible foam) is an
appropriate measure for domestic wastes.
J. MINOR DISCHARGES
There are no BPT limitations for the minor waste streams.
EPA is not developing limitations to regulate these discharges.
IX-65
-------
K. REFERENCES
1. Development Document for Interim Final Effluent Limitations
Guidelines and Proposed New Source Performance Standards for
the Oil & Gas Extraction Point Source Category. U.S.
Environmental Protection Agency, September 1976, EPA 440/1-
76-005-a-Group II.
2. ERCE for EPA, "Onshore Disposal of Offshore Drilling Waste,
Capacity and Cost of Onshore Disposal Facilities," March
1991.
3. Report to Congress, "Management of Wastes from the
Exploration, Development and Production of Crude Oil,
Natural Gas and Geothermal Energy," USEPA-OSW, Vol. 12, pg.
3-16, August 12, 1987.
4. Mud Equipment Manual. Handbook II: Disposal Systems. IADC
Manufacturer - User Conference Series on Mud Equipment
Operations, Gulf Publishing Co., 1976.
5. Walk, Haydel & Associates, Inc., "Water-based Drilling
Fluids and Cuttings Disposal Study Update," January, 1989.
6. KRE for EPA, "Offshore and Coastal Oil & Gas Extraction
Industry Study of Onshore Disposal Facilities for Drilling
Fluids and Drill Cuttings Located in the Proximity of the
Gulf of Mexico," March 1987.
7. Jones, M., IMCO Services, Burgbacher, J., Shell Offshore
Inc., Churan, M. and Huise, M., IMCO Services. "Efficiency
of a Single Stage Cuttings Washer with a Mineral-Oil Invert
Emulsion Mud and Its Environmental Significance." Society
of Petroleum Engineers of AIME presented at 68th Annual
Technical Conference in San Francisco, CA, October 5-8,
1983.
8. Bennett, R. B., 1983. "New Drilling Fluid Technology -
Mineral Oil Mud,: paper presented at: IADC/SPE 1983
Drilling Conference, New Orleans, LA.
9. Boyd, P. A., Whitfill, D. L., Cartert, S., and Allamon, J.
P., "New Base Oil Used in Low-Toxicity Muds," SPE 12119,
presented at the 58th Annual Technical Conference and
Exhibition of SPE, San Francisco, CA, October 5-8, 1983.
10. Krol, D. A., Gulf Research & Development Co., "An Evaluation
of Drilling Fluid Lubricants to Minimize Differential
Pressure Sticking of Drill Pipe," presented at Drilling
Technology Conference of International Association of
Drilling Contractors, March 19-21, 1984.
IX-66
-------
11. Swanston, H. W. and H. R. Heffler. "Environmental
Considerations in Waste Disposal from Drilling in the
Shallow Beaufort Sea." The Journal of Canadian Petroleum
Technology. July-September 1977.
12. 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.
13. U.S. EPA, Development Document for Effluent Limitations
Guidelines and Standards for the Offshore Segment of the
Oil and Gas Extraction Point Source Categoryf July 1985,
EPA 440/1-85/055.
14. Engineering Specialties Inc. 1981. Manufacturer's
literature.
15. Forster, R. L., J. E. Moyer and S. I. Firstman. Port
collection and separation facilities for oily wastes,
Vol. I. Collection, treatment and disposal of oily water
wastes from ships and Vol. II General technology U.S.
Department of Commerce, Maritime Administration. NTIS
COM73-11068 and -11069.
15(a). White, Charles E., "Offshore Oil and Gas Extraction,
Produced Water Limitations for Oil and Grease that are
Based on Improved performance of Best Practicable Control
Technology Currently Available", March 4, 1991.
16. Technical Feasibility of Brine Reinjection for the
Offshore Oil and Gas Industry, prepared by Burns and Roe
Industrial Services Corporation, prepared for U.S.
Environmental Protection Agency, Effluent Guidelines
Division and Industrial Environmental Research
Laboratory, May 1981.
17. Revised Preliminary Ocean Discharge Criteria Evaluation,
Gulf of Alaska - Cook Inlet, OCS Lease Sale 88 and State
Lease Sales Located in Cook Inlet, USEPA Region 10,
September 28, 1984.
18. Preliminary Discharge Criteria Evaluation for the
Endicott Development Project, USEPA Region 10, August
1984.
19. ERCE for EPA, "An Evaluation of Technical Exceptions for
Brine Reinjection for the Offshore Oil and Gas Industry,
March 1991.
IX-67
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20. Burns & Roe Industrial Services Corporation, "The Use of
Filtration for Produced Water Treatment," December 2, 1982.
21. Tramier, B., E. deMerville, G. Oldham, T. Pytel, j. Rudd and
H. Van Laar. 1982a. Treatment of Production Water - State
of the Art. International Exploration & Production Forum.
London, England. Technical Review No. 3.
22. ERCE, "The Results of the Sampling of Produced Water
Treatment System and Miscellaneous Wastes at the Conoco,
Inc. - Maljamar Oil Field," Draft, January 1990.
23. 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, March
1990.
24. SAIC, "Produced Water Pollutant Variability Factors and
Filtration Efficacy Assessments From the Three Facility Oil
and Gas Study, March 1991.
25. Chen, Abraham S. C., "Removal of Oil, Grease, and Suspended
Solids from Produced Water Using Ceramic Crossflow
Microfiltration," no date.
26. Gillot, J., "New Ceramic Filter Media for Cross-Flow
Microfiltration and Ultrafiltration," France, April 1986.
27. Goodboy, Kenneth P., "Operational Results of Cross-Flow
Microfiltration for Produced and Sea Water Injection,"
Scotland, November 1, 1989.
28. Letter from Kenneth M. Thomas, Alcoa Separations Technology,
Inc., to Ron Jordan, U.S. EPA, October 10, 1990.
29. Letter from Kenneth M. Thomas, Alcoa Separations Technology
Division, to Karen Troy, U.S. EPA, February 13, 1990.
30. Telephone conversation between Kenneth Thomas, Alcoa
Separations Technology Division, and Ron Jordan, EPA,
October 16, 1990.
31. Battelle, "Fate and Effects of Produced Water Discharges in
Nearshore Marine Waters," for API, August 22, 1988.
32. SAIC for EPA, "Summary of Data Relating to Miscellaneous and
Minor Discharges," Revised February 1991.
IX-68
-------
SECTION X
BPT
On September 15, 1975, the Agency promulgated effluent
limitations guidelines for interim final BPT'(40 FR 42543). The
Agency promulgated final BPT regulations for the offshore
subcategory on April 13, 1979 (44 FR 22069). Table XII-1
presents a summary of the promulgated final BPT requirements.
The technology bases to meet these limitations are described in
Section IX.
The BPT effluent limitations are not affected by this
proposal except with respect to an amendment to the current
definition of "free oil" and the analytical method of compliance
(see Section VI.H). However, this definition change does not
affect the BPT limitation or costs associated with it.
X-l
-------
TABLE X-l
SUMMARY OF PROMULGATED FINAL BPT REQUIREMENTS
Waste Stream
Parameter
BPT Effluent
Limitation
Produced water
Drilling muds
Drilling fluids
Well treatment
fluids
Deck drainage
Sanitary-Mi0
Sanitary-M9IM
Oil and grease
Free oil
Free oil
Free oil
Free oil
Residual chlorine
Floating solids
72 mg/L daily maximum
48 mg/L 30-day avg.
No discharge
No discharge
No discharge
No discharge
1 mg/L (min.)
No discharge
Note: The free oil "no discharge" limitation is implemented by
requiring no oil sheen to be visible upon discharge.
X-2
-------
SECTION XI
REGULATORY OPTIONS CONSIDERED FOR BCT, BAT, AND NSPS
A. INTRODUCTION
*
Following examination of treatment technologies available
for offshore oil and gas wastewaters, EPA developed regulatory
options for each waste stream. Each regulatory option has
associated with it a different level or type of treatment/control
technology and achievable effluent limitations representative of
this technology. Depending on the respective development
criteria for BCT, BAT, and NSPS, the options selected may be
different for each standard. This section presents all of the
regulatory options considered. Later chapters discuss those
selected for BCT, BAT, and NSPS, and reasons for their selection
or exclusion.
B. DRILLING FLUIDS AND CUTTINGS
1. Options Considered
There are fourteen options considered for drilling fluids
and cuttings. Three options are evaluated based on well depth,
seven options are evaluated based on well distance offshore, and
four are applicable to all structures regardless of location and
depth. They are summarized in Table XI-1 and described below.
5/3 All Structures; This option includes four
requirements: 1) toxicity limitation set at 30,000 ppm in the
suspended particulate phase; 2) a prohibition on the discharge of
diesel oil used either for lubricity or spotting purposes; 3) no
discharge of free oil based on the Static Sheen test, and 4)
limitations for cadmium and mercury set in the stock barite at 5
mg/kg and 3 mg/kg, respectively. These requirements are to be
XI-1
-------
TABLE XI-1
SUMMARY OF DRILLING FLUIDS AND CUTTINGS OPTIONS
Option A
5/3 All Structures
Option B
1/1 All Structures
Option C
Zero Discharge Shal-
low; 5/3 Deep
Option D
Zero Discharge Shal-
low; 1/1 Deep
Option E
Zero Discharge
All Structures
Option F
Zero Discharge
Within 4 miles;
5/3 Beyond
Option G
Zero Discharge
Within 6 miles;
5/3 Beyond
Option H
Zero Discharge
Within 8 miles;
5/3 beyond
All structures
All structures
Shallow water
structures
Deep water
structures
Shallow water
structures
Deep water
structures
All structures
• Toxicity > 30,000 ppm (SPP)
• No diesel oil discharge
• No free oil discharge
• 3 mg/kg mercury, 5 mg/kg
cadmium, both in stock
barite
• Toxicity > 30,000 ppm (SPP)
• No diesel oil discharge
• No free oil discharge
• 1 mg/kg mercury, 1 mg/kg
cadmium, in the whole
drilling fluid
Zero discharge
Option A discharge limits
Zero discharge
Option B discharge
limits
Zero discharge
< 4 miles from shore Zero discharge
> 4 miles
Option A discharge
limits
< 6 miles from shore Zero discharge
> 6 miles
Option A discharge
limits
< 8 miles from shore Zero discharge
> 8 miles Option A discharge
limits
XI-2
-------
TABLE.XI-1 (Continued)
SUMMARY OF DRILLING FLUIDS AND CUTTINGS OPTIONS
Option I
Zero Discharge
Within 4 miles;
1/1 Beyond*
Option J
Zero Discharge
Within 6 Miles;
1/1 Beyond
Option K
Zero Discharge
Within 8 Miles;
1/1 Beyond
Option L
BPT All Structures
Option M
Zero Discharge Shallow;
BPT Deep
Option N
Zero Discharge
Within 4 Miles;
BPT Beyond**
< 4 miles from shore Zero discharge
> 4 miles
Option B discharge
limits
< 6 miles from shore Zero discharge
> 6 miles
Option B discharge
limits
< 8 miles from shore Zero discharge
> 8 miles
All structures
Shallow water
structures
Deep water
structures
Option B discharge
limits
BPT for all structures
Zero discharge
BPT
< 4 miles from shore Zero discharge
> 4 miles BPT
* Preferred option for BAT and NSPS
** Preferred option for BCT
XI-3
-------
met by all offshore structures regardless of location or the
depth of the water in which they are located. For BCT, the
regulation of free oil only is considered in this option.
1/1 All Structures; This option also includes four
requirements: 1) the same toxicity limitation as above; 2) the
same discharge prohibition on diesel oil as above; 3) the same
prohibition on the discharge of free oil as above; and 4)
limitations at the point of discharge for cadmium and mercury in
the drilling fluids and cuttings at 1 mg/kg each. The mercury
and cadmium limits are based upon the use of "clean" stock barite
which has been costed for use by the industry and are to be met
by all offshore structures regardless of location or the depth of
the water in which they are located. For BCT, free oil is the
only parameter considered for regulation for this option.
Zero Discharge Shallow; 5/3 Deep; This option
distinguishes between offshore structures located in shallow
water and those located in deep water. For offshore structures
located in shallow water, there is a zero discharge requirement
which is based on recycle/reuse of the drilling fluid portion of
the mud system and/or transport (mostly by barging) of muds
cuttings to shore for treatment and land dispose?. For offshore
structures located in deep water, discharge requirements are the
same as the first option.
Zero Discharge Shallow; 1/1 Deep; This option also makes a
distinction between offshore structures located in shallow water
and those in deep water. It is the same as the zero discharge
shallow - 5/3 deep option except that the cadmium and mercury
requirements are 1 mg/kg each as limitations at the point of
discharge.
XI-4
-------
Zero Discharge All; Zero discharge would apply to all
offshore structures regardless of location or the depth of water
in which they are located.
t
Zero Discharge Within 4 Miles; 5/3 Beyond; Zero discharge
is required for wells drilled at a distance of 4 miles or less
from shore. All structures drilled at a distance greater than 4
miles would be regulated by the discharge limitations in the "5/3
all structures" option.
Zero Discharge Within 6 Miles; 5/3 Beyond; Same as 4 mile
option except the distance criterion is 6 miles from shore.
Zero Discharge Within 8 Miles; 5/3 Beyond; Same as 4 mile
option except the distance criterion is 8 miles from shore.
BPT All Structures; All structures will be subject to BPT
limitations.
Zero Discharge; BPT Deep; All shallow water structures will
be required to meet zero discharge of drilling wastes. All deep
water structures will be subject to BPT limitations.
Zero Discharge Within 4 Miles; BPT Beyond; All structures
located in waters 4 miles or less from shore will be required to
meet zero discharge. All structures greater than 4 miles from
shore will be subject to BPT limitations.
2. Alaskan Waters
Comments were submitted to EPA regarding specific situations
in Alaska which make compliance with a zero discharge requirement
critically difficult.1 Reasons for this primarily relate to the
severe weather conditions. Because of sea ice, tugs and barges
XI-5
-------
can only be used for 4 months in the summer during open-
water/broken ice season. In addition, winter snow and fog
conditions restrict visibility. White-out conditions occur
restricting air and water travel. For these reasons, EPA is
proposing not to consider zero discharge based on barging (under
any options) as applicable to Alaskan waters for either BCT, BAT,
or NSPS. Rather, the discharge options will be considered for
Alaska.
Instead of barging, zero discharge of drilling wastes may be
attained by reinjection of the fluids and ground cuttings. EPA
is aware that this has occurred on a test basis in Alaska;
however, zero discharge based on reinjection is not being
proposed because of lack of sufficient supporting information.
C. PRODUCED WATER
Nine options were considered by EPA for the regulation of
produced waters. Three options are evaluated based on well
depth, three options are evaluated based on well distance
offshore, and three options apply to all platforms regardless of
location and depth. Table XI-2 summarizes the options.
The manner of control involves various combinations of
treatments and/or zero discharge. The treatment technologies
considered in the options described below involve either BPT or
filtration. The limits associated with these technologies are
for oil and grease.
•
Filter and Discharge Shallow; BPT Deep: This option
distinguishes between those offshore structures that are located
in shallow water and those located in deep water. The offshore
structures located in shallow water would have requirements based
on the use of filtration (granular media or membrane separation)
XI-6
-------
TABLE XI-2
REGULATORY OPTIONS FOR PRODUCED WATER
Option
Option A
Filter and Discharge
Shallow; BPT Deep
Applicability
Control Level
Shallow Water Structures - Filter and Discharge*
Deep Water Structures - BPT
Option B
Zero Discharge Shal-
low; BPT Deep
Shallow Water Structures - Zero Discharge
Deep Water Structures - BPT
Option C
Filter and Discharge
All Structures
- All Structures
- Filter and Discharge
Option 'D
Zero Discharge Shal-
low; Filter Deep
Shallow Water Structures - Zero Discharge
Deep Water Structures - Filter and Discharge
Option E
Zero Discharge
All Structures
- All Structures
- Zero Discharge
Option F
Filter and Discharge
Within 4 Miles;
BPT Beyond**
< 4 miles from the shore - Filter and Discharge
> 4 miles from the shore - BPT
Option G
Filter and Discharge
Within 6 Miles;
BPT Beyond
< 6 miles from the shore - Filter and Discharge
> 6 miles from the shore - BPT
Option H
Filter and Discharge
Within 8 Miles;
BPT Beyond
< 8 miles from the shore - Filter and Discharge
> 8 miles from the shore - BPT
XI-7
-------
TABLE XI-2 (Continued)
REGULATORY OPTIONS FOR PRODUCED WATER
Option I
BPT All Structures*** - All Structures - BPT
* Discharge limits for "Filter and Discharge" options are being considered
based on membrane and granular filtration. Within these options, EPA prefers
filtration limits for oil and grease of 13 mg/L daily maximum and 7 mg/L
monthly average, based on membrane filtration. The granular filtration
discharge limits for oil and grease that are being considered are 29 mg/L
daily maximum and 16 mg/L monthly average.
** Preferred BAT and NSPS option
*** Preferred BCT option
XI-8
-------
technology as an add-on to the existing BPT technology (dissolved
gas flotation). The 1985 proposal contained a produced water
filtration option; however, new data have been collected for both
types of filtration—granular media and membrane separation—
since then, and the proposed limits would be based on the new
data. Two sets of limits are considered in this option; however,
only one set, based on membrane separation, is being proposed.
The offshore structures that are located in deep water would be
subject to the current BPT limitations.
Zero Discharge Shallow; BPT Deep; This option also makes a
distinction between those structures located in shallow water and
those in deep water. Under this option, the offshore structures
located in shallow water would be subject to a zero discharge
requirement based on reinjection of the produced water. The
reinjection system would include oil flotation and gas separation
technology (BPT level control), membrane filtration, and an
injection well system. Those offshore structures located in deep
water would be allowed to discharge produced water wastes subject
to the current BPT limitations.
Filter and Discharge All Structures; All structures,
regardless of the water depth in which they are located, would be
required to meet limits based on membrane filtration of the
produced water prior to discharge. Two sets of limits are
considered; however, only one set, based on granular media
filtration, is being proposed.
Zero Discharge Shallow; Filter Deep; This option would
require offshore structures located in shallow water to meet a
zero discharge requirement for the produced water waste stream,
while those structures located in deep water would be required to
meet discharge limits based on membrane filtration.
XI-9
-------
Zero Discharge All Structures; This option would require
all structures to meet a zero discharge requirement based on
reinjection of the produced water.
Zero Discharge Within 4 Miles; BPT Bevond; All wells at a
distance or 4 miles or less from shore would be required to meet
discharge limits based on membrane filtration. Producing wells a
distances greater than 4 miles from shore would be required to
meet the existing BPT limitations only.
Zero Discharge Within 6 Miles; BPT Beyond; This option is
the same as the 4 mile option except that the distance criterion
is 6 miles instead of 4.
Zero Discharge Within 8 Miles; BPT Beyond; This option is
the same as the 4 mile option except that the distance criterion
is 8 miles instead of 4.
BPT All Structures; EPA has included as an option setting
BCT, BAT, and/or NSPS equal to BPT. By doing so, EPA is not
ruling out the possibility that, based on the fluctuating
economic stability of the oil market, compliance with stricter
standards may be unachievable.
D. DECK DRAINAGE
Options being considered as a basis for BAT for this waste
stream are either to establish the requirement equal to the
current BPT limits of no discharge of free oil or to require the
same standards as those sleeted for the produced water waste
stream.
XI-10
-------
E. PRODUCED SAND
Two options are considered lor produced sand: 1)
limitations equal to BPT for no discharge of free oil, or 2)
require zero discharge by barging and treatment/disposal onshore.
F. WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS
Three options are considered for these wastes: 1) BPT limit
of no discharge of free oil, 2) zero discharge of a concentrated
slug of fluids along with a 100-barrel buffer on either side of
the slug, or 3) meet the same requirements as the preferred
option for produced water. In addition, EPA is considering
allowing a discharge for certain treatment or workover fluids
after meeting a pH requirement of 6-9. Some treatment and
workover fluids are composed of seawater and simple acid
solutions that, if not already spent upon resurfacing, require
minimal neutralization prior to discharge.
G. SANITARY AND DOMESTIC WASTES
No additional options for sanitary and domestic wastes have
been developed other than BPT, except for an additional
requirement on domestic wastes which would limit foam in
nonvisible amounts.
XI-11
-------
H. REFERENCES
1. Alaska Oil and Gas Association Comments on Oct. 1988 Federal
Register Notice (53 FR 41356), Anchorage, AK, 11/7/88.
XI-12
-------
SECTION XII
BCT OPTIONS SELECTION AND COSTS
A. METHODOLOGY
BCT limitations for conventional pollutants are
appropriate in instances where the cost of such limitations meet
the following criteria:
1) The removal cost is less than the comparative cost for
removal of conventional pollutants at a typical POTW;
the POTW cost is $0.46 per pound.
2) The ratio of the incremental BAT/NSPS cost divided by
the incremental BPT cost must be less than 1.29; as
such, the cost increase must be less than 129%.
These two criteria represent the BCT cost tests. Each of
the regulatory options for produced waters and drilling wastes
was analyzed according to these cost tests to determine if BCT
limitations are appropriate. Table XII-1 presents the BCT
effluent limitations guidelines according to EPA's preferred BCT
options.
As stated in the BCT methodology that was published in final
form on July 9, 1986 (51 FR 24974), "The pollutants included in
calculating the POTW pollutant removal are BOD and TSS. These
pollutants are also used to calculate the pollutant removal for a
candidate BCT technology, but oil and grease may be included when
appropriate in the context of the industry and technology being
evaluated." For this rulemaking, only TSS and oil and grease
were used in the BCT calculations for produced waters and
drilling wastes. BOD was not used since it is not a contaminant
normally associated with these waste streams. The use of BOD
XII-1
-------
TABLE XII-1
PROPOSED BCT EFFLUENT LIMITATIONS GUIDELINES
Waste Source
BCT Effluent Limitations
Pollutant Parameter
BCT Effluent
Limitation
Produced water
(all structures)
Drilling fluids
and cuttings
A) For facilities
located 4 miles
offshore or less
B) For facilities
located more
than 4 miles
offshore
Well treatment
and completion
fluids
Deck drainage
Produced sand
Sanitary M10
Sanitary M91M
Domestic Waste
Oil and Grease
Free oil
Free oil
Free oil
Free oil
Residual chlorine
Floating solids
Floating solids
72 mg/L daily
maximum, 48 mg/L
monthly average
No discharge
No discharge
No discharge
No discharge
No discharge
Minimum of 1 mg/L
maintained as close
to the concentration
as possible
No discharge
No discharge
XII-2
-------
would result in double counting, since oil and grease would be
the major component of BOD and using both would result in
unreasonably high levels of mass removals of pollutants.
As discussed in Section XIV, EPA's preferred distance from
shore criterion is 4 miles. Because the preferred option was
selected based on the non-water-quality impact factor, options
involving the 6 or 8 mile criterions were not costed for BCT.
The following is a summary of the BCT options and costs for
offshore oil and gas waste streams.
B. DRILLING FLUIDS AND CUTTINGS
1. Options Considered
There are four options considered for drilling fluids and
drill cuttings for BCT. One option is based on water depth, one
option is based on well distance from shore, and two are
applicable to all structures regardless of location or water
depth. All options are directed at controlling the discharge of
the conventional pollutants, hence options in Section XI that
include discharge limitations for other pollutants such as
toxicity and cadmium and mercury are not considered here. They
are summarized in Table XII-2.
The parameter of settleable solids was not included as a
limitations option for consideration because both drilling fluids
and drill cuttings are so high in total solids content, both
settleable and suspended. The only option suitable for the
control of suspended solids is zero discharge. In addition, EPA
is not aware of any control technologies other than zero
discharge that are specifically developed and operated for the
removal of total suspended solids from drilling wastes. Rather,
XII-3
-------
TABLE XII-2
SUMMARY OF BCT DRILLING FLUIDS AND CUTTINGS OPTIONS
Option
BPT All Structures
Zero Discharge
Shallow; BPT Deep
Zero Discharge Within**
4 miles; BPT Beyond
Zero Discharge
All Structures
Applicability
All structures
Shallow water
structures
Control Level
BPT*
Zero discharge
Deep water structures BPT*
< 4 miles from shore Zero discharge
> 4 miles from shore BPT*
All structures Zero discharge
* BPT requirement of "no free oil" determined by static sheen test.
** Option preferred for BCT. BPT would apply to those wells in Alaskan
waters.
XII-4
-------
there are technologies that remove oil and grease related
parameters such as oil content and diesel oil. Therefore, the
only BCT.options more stringent than BPT that are considered are
those involving zero discharge.
2. Options Selection
Cost for BPT for drilling fluids was calculated based on
disposal of oil based muds which had to be disposed onshore
because they failed the sheen test. This is the only cost
attributed to BPT. Furthermore, as described above, oil and
grease related parameters (such as oil content) are normally
measured in drilling wastes and not the oil and grease content,
the pounds of oil content removed is used as a surrogate for oil
and grease in the calculations. The following are annual costs
and conventional pollutant removals for drilling fluids:
Cost - $13,895,000 (1986 dollars)
. TSS Removal - 186,373,000 Ib/yr
Oil Removal - 7,862,000 Ib/yr
Total Conventional Pollutant Removal = 194,235,000 Ib/yr
The cost of conventional pollutant removal for drilling fluids is
$.0715 per pound.
The cost of each regulatory option for drilling fluids was
determined by dividing the "Cost of Pollutant Removal" by the
amount of TSS and oil removal achieved under the option. For
example, the annual cost of removal for zero discharge for all
structures is $235,984,000 (in 1986 dollars). Zero discharge
achieves a removal of 1.443 billion pounds of TSS and 10.0
million pounds of oil. The removal cost is $0.162 per pound.
This is less than the comparable POTW removal cost ($0.46/lb) and
XII -5
-------
the option passes the first test. The second test, the Industry -
Cost Ratio (ICR), is calculated as follows:
BCT cost - BPT cost
ICR =
BPT cost - preBPT cost
.162 - .0715
ICR = =1.27
.0715 - 0
The ICR is less than 1.29, and the option passes the second
portion of the test. As such, BCT limitations are appropriate
under the Zero Discharge regulatory option for drilling fluids.
Table XII-3 presents the results of the BCT cost tests for each
of the appropriate regulatory options for drilling fluids. As
shown, each of the options passes both of the BCT cost tests, and
BCT limitations would be appropriate under each option. However,
due to consideration of non-water-quality environmental impacts,
as discussed in Section XIV, some of these options are not
preferred.
Cost for BPT for drill cuttings was calculated based on
disposal of cuttings from oil based muds which required disposal
onshore because they failed the sheen test. This is the only
cost for BPT for drill cuttings. The following are the annual
costs and pollutant removals:
Cost - $4,852,000
TSS Removal - 51,221,000 Ib/yr
Oil Removal - 7,122,000 Ib/yr
Total Conventional Pollutants Removal = 58,343,000 Ib/yr
XII-6
-------
TABLE XII-3
BCT COST TEST FOR DRILLING FLUIDS
Option
Colt <$/yr)
Ranoval
db/yr)
Raaoval Cot
POTH Taat
(•uit ba <0.46)
(Pax/Fall)
ICR
ICR Tait
(oust ba <1.29)
(Paia/Pall)
I
-o
Zaro Dlaehars* 68,987,200
Shallovi BPT D««p
421.073 ,000
Zaro Dlaeharga
All
4 Mlla Zaro
Dliehar(ai BPT
Bajrond
233,984,000 1,433,000,000
36.601,600
223.360,000
0 . 162
0 . 162
0 . 162
PASS
PASS
PASS
1.27
1 .27
1 . 27
PASS
PASS
PASS
Coit* asprasaad la 1986 dollar*
ICRt Induatry Coat Ratio
-------
The cost per pound of conventional pollutant removal for drill
cuttings is $.083 per pound.
The BCT cost test procedure for drill cuttings is identical
to that described above for drilling fluids.' The results of the
BCT cost test for each regulatory option for drill cuttings are
shown in Table XII-4; as shown, each of the options having any
impact on cost/pollutant removal pass both test criteria, and BCT
limitations would be appropriate under each option. However, for
the same reasons (non-water quality environmental impacts), some
options are preferable to others.
Although zero discharge for all structures was
determined to be available and technically feasible technology,
passes the BCT cost test, and results in the elimination of the
discharge of pollutants, because upon detailed evaluation,
certain non-water quality environmental effects surfaced as a
significant concern, this option was not selected as preferred.
Specifically, a zero discharge requirement for all structures
would result in an enormous amount of solids requiring ship
transportation (barging) and land disposal. EPA conducted an
investigation into both the impacts of barging and the
availability of land for drilling waste disposal. While the
portion of this study concerning land availability estimated that
sufficient land disposal facility capacity is, or would be,
available to support a zero discharge requirement, EPA remains
concerned about the use of the large amount of land that would be
required for this purpose. Additionally, the EPA is currently
conducting a study under the Resource Conservation and Recovery
Act (RCRA) of wastes associated with oil and gas activities to
determine if special requirements are necessary for the treatment
and disposal of such wastes. As part of this study, facilities
which treat and dispose of drilling fluids and drill cuttings
will be evaluated and a determination made as to whether more
XII-8
-------
X
H
H
I
vo
TABLE XII-4
BCt COST TBST FOR DRILL COTTIHGS
POTH T«.t
ICR T«.t
Option Cost (9/yr)
tare Dlaeharga 20,924,71*
Shallow) BPT Daap
Zaro Dl.ehart* 72.203,000
All
4 Mil* tare ll,19f,14S
Raaoval
(Ib/yr)
222, 909,371
769, 193,000
119, 303, 714
Raaoval Co.t
(9/lb)
0 .094
0 .094
0 .094
(mu.t ba <0.4«)
(Pact/Pall) ICR
PASS 0.93
PASS 0.93
PASS 0.93
(nu« t bt
(Pa../
PA
PA
PA
Dl.eharg*i BPT
Beyond
Co.t* •xpr***«d In 1986 dollar*
ZCRt Indu.try Co.t Ratio
-------
stringent requirements are necessary for these facilities. The -
outcome of this effort may have a significant effect on the
future available capacity and/or cost of land disposal for
drilling fluids and drill cuttings.
»
In addition, the evaluation of barging requirements
estimated air emissions associated with fuel requirements
necessary for transport of the fluids and cuttings to shore.
These estimates were unexpectedly high in air emissions and fuel
use in comparison with the other options (see Section XIV).
Thus, while zero discharge is technologically feasible, other
options were explored which allowed discharges for certain
portions of the industry in order to minimize these impacts.
EPA has selected the zero discharge within 4 miles; BPT
Beyond option as a basis for BCT effluent limitations for
drilling fluids and cuttings. This option proposes zero
discharge by barging for new wells drilled at a distance from
shore of 4 miles or less. New wells drilled at a distance of
greater than 4 miles would be allowed to discharge after meeting
BPT requirements for no static sheen, and no discharge of diesel
oil. However, for the Alaska region, new wells would be covered
by BPT only because, as previously discussed in Section XI, the
special climate and safety conditions that exist for parts of the
year make barging especially difficult and hazardous.
C. PRODUCED WATERS
Seven options were considered by EPA for the regulation of
produced waters for BCT. Three options are based on well depth,
one option on platform distance offshore, and three options apply
to all platforms regardless of location and water depth.
XII-10
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The manner of control involves various combinations of
treatment and discharge and/or zero discharge. The treatment and
discharge technologies considered in the options described below
involve either BPT, filtration, or reinjection. The limits
associated with these technologies are for oil and grease. Table
XII-5 summarizes the options.
All regulatory produced water options considered for
BCT regulation fail the BCT cost test. The pollutant parameters
used in this analysis were TSS and oil and grease. It is clear
that in all cases (except for the BPT All option) the ratio of
costs of pollutant removal to pounds of pollutants removed will
be greater than $0.46/lb. The range of results for the first
(POTW) test is $3.47 to $3.71 per pound of conventional pollutant
removal. See Section XIII which presents costs and pollutant
reduction information for produced waters. Thus, EPA is
proposing BCT = BPT for produced waters. This proposal is the
same as that proposed in 1985.
D. DECK DRAINAGE
BPT limitations for deck drainage are for no discharge of
"free oil." Typical BPT technology for compliance with this
limitation is a "skim pile" which facilitates gravity separation
of any floating oil prior to discharge of the deck drainage.
Data available on levels of conventional pollutants in deck
drainage is very limited. The report "Summary of Data Relating
to Miscellaneous and Minor Discharges (Feb. 1991)", contains
concentration data on untreated and treated deck drainage. Using
an average value for untreated deck drainage for TSS and BOD (it
is assumed the skim pile would not realize a removal of BOD or
TSS), and an average value of treated deck drainage for O&G,
yields the following BPT concentration levels:
XII-11
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BPT All Structures**
Filter and Discharge
Within Four Miles;
BPT Beyond
Filter and Discharge
Shallow; BPT Deep
Filter and Discharge
All Structures
Zero Discharge
Shallow; BPT Deep
Zero Discharge
Shallow; Filter Deep
Zero Discharge
All Structures
TABLE XII-5
SUMMARY OF BCT PRODUCED WATER OPTIONS
All structures
BPT
<, 4 Miles from shore Filter and discharge*
> 4 miles from shore BPT
Shallow water
structures
Filter and discharge*
Deep water structures BPT
All structures
Filter and discharge*
Shallow water
structures
Zero discharge
Deep water structures BPT
Shallow water
structures
Zero discharge
Deep water structures Filter and discharge*
All structures
Zero discharge
* Discharge limits for 'Filter and Discharge" options are being considered based
on membrane filtration. The discharge limits for oil and grease are 13 mg/L
daily and 7 mg/L monthly average.
** Proposed option preferred by EPA.
XII-12
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TSS - 133 mg/L
BOD - 299 mg/L
O&G - 27 mg/L
Three regulatory options are conceivable for deck drainage.
They are:
Filtration/discharge
Filtration/reinjection
BPT equal to no discharge of free oil
If the filtration/discharge option were employed, the deck
drainage could be subject to the same limitations on O&G as
produced water; data from the three facility study indicated an
effluent level after filtration of 11.33 mg/L of O&G and 21.17
mg/L of TSS (see Table IX-3). No data is given for BOD removal
across a filter, but 50 percent would be a reasonable assumption.
In "Cost/Contaminant Removal - Produced Water," by ERCE, Nov.
1990, it is projected that an incremental treatment cost for
produced water would be $3.36 per thousand gallons. (Calculated
by dividing industry cost by total flow and then by 42 gal/bbl).
Using this removal and cost for deck drainage yields a removal
cost of $1.05 per pound (see calculations below) or 2.28 times
the equivalent POTW cost ($0.46/lb). (This ratio would be
somewhat less for membrane filtration technology, but it is
expected to remain considerably higher than $0.46/lb as well.)
As such, based on this data, BCT limits would not be appropriate
using the first cost test.
XII-13
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SAMPLE CALCULATION FOR
DECK DRAINAGE BCT COST
CALCULATION
Deck Drainage; Filter/Discharge
BPT Level BAT Level
TSS 133 21
BOD 299 150
O&G 27 11
Total 565 182
Cone = (383 mg/L) x (3.8 liter/gallon)(1000 gal)(lb/454,000 mg)
=3.21 lbs/1000 gallons
Cost = $3.36/1000 gallons
BCT Cost = $3.36/3.21 Ib - $1.05/lb
Deck Drainage/Zero Discharge
Cone = 565 mg/L (3.8) (1000) (1/454,000)
=4.73 lb/1000 gal
BCT Cost = $0.95/lb
It can be concluded, however, that the cost to provide BAT
treatment capacity for deck drainage (which included dissolved
air floatation/filtration) would be considerably more expensive
than the cost for BPT treatment. BPT treatment consists of a
XII-14
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skim pile and the annual cost to operate a skim pile is probably •
on the order of a few pennies per thousand gallons. The cost to
operate a filtration unit is $1.13 per thousand gallons and this
does not include the operating cost of the DAF portion of the
treatment unit. As the second cost test for BCT limits the
incremental cost to 129% of the BPT cost, this option would
doubtlessly fail this test.
If the filtration/reinjection option were employed, the
costs and conventional pollutant removals would increase compared
to the filtration/discharge option. Using the waste
characterization from (4) above and 100% removal, along with
costs for reinjection of produced water ($4.49 per thousand
gallons), yields a cost per pound of $0.95 for removal of
conventional pollutants. This option would fail the first cost
test. This is the same conclusion as reached in the
filter/discharge analysis and is subject to the same
uncertainties regarding the accuracy of the data.
The conclusions reached above for filtration/discharge
option regarding the second cost test would also hold for the
reinjection option. As the second test limits the incremental
cost to 129% of the BPT cost, the option would doubtlessly fail
this test.
Thus, EPA is proposing BCT = BPT for deck drainage. This is
the same as that proposed in 1985.
E. PRODUCED SAND
BPT limitations have not been promulgated for produced sand.
In the absence of BPT limitations, EPA is considering the current
permit requirements for produced sand which is no discharge of
free oil. EPA has not performed a BCT cost analysis on this
XII-15
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option, because it is assumed no incremental costs will be
incurred since the limitation is currently in effect. Therefore,
BPT for produced sand is being proposed as equal to no discharge
of free oil.
F. WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
EPA is not changing the 1985 proposal which set BCT equal to
BPT for treatment fluids. No additional costs have been
performed, however, due to a lack of sufficient data on TSS
concentration, both in treated and untreated wastes.
G. SANITARY WASTE/DOMESTIC WASTE
Sanitary wastes are human body wastes from toilets and
urinals. BPT requirements for discharge are for a free chlorine
content residual exceeding 1 mg/L.
Domestic wastes result from laundries, galleys and sinks.
BPT limits require their discharge does not result in floating
solids. Treatment using macerators is usually sufficient to
ensure that the discharge complies with BPT limitations.
Limited data in the report, "Summary of Data Relating to
Miscellaneous and Minor Discharges" has composition data for
combined domestic/sanitary wastewater. BOD ranged from 270 -770
mg/L with an average of 588 and TSS ranged from 14 - 543 mg/L
with an average of 515.
Treatment options for domestic/sanitary waste as part of
BAT/NSPS that would reduce conventional pollutant discharges
beyond BPT limits are:
• On-platform biological oxidation
XII-16
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Onshore disposal
Given the high cost of offshore operations, it would
probably be less costly to transport these wastes to shore than
to install a treatment unit. No cost data is available on
transport costs for shipment to shore. As muds/cuttings can be
transported to shore and disposed of for $36 to $51 a barrel,
onshore disposal of sanitary waste should be less costly by an
amount equal to the fee charged by the onshore disposal facility.
This cost equals $7 to $10 per barrel. Using the low cost of $26
per barrel and average BOD and TSS levels reported earlier, the
cost is $67 per pound of conventional pollutants in the
domestic/sanitary waste. Obviously, this greatly exceeds the
POTW cost of $0.46 per pound and requiring transfer to shore
would not be justified.
Possibly, some on-platform treatment process could achieve a
lower cost per pound of conventional pollutant removal than
onshore disposal, but it is highly unlikely that it could compete
with a POTW (which is designed to achieve the same result on a
massive scale) in terms of operational cost. Thus, EPA is not
changing the 1985 proposal which set BCT = BPT for sanitary and
domestic waste.
XII-17
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SECTION XIII
BAT AND NSPS OPTIONS COSTS
A. INTRODUCTION
The options being considered for BAT and NSPS are all of
those listed in Section XI except for the two that involve
combinations of zero discharge and BPT limitations. Prior to a
selection of a preferred option, the costs, pollutant reductions
benefit, and other impacts must be considered. This section
presents costs and pollution reductions associated with BAT and
NSPS treatment/control options for drilling wastes and produced
waters. The next section (Section XIV) discusses non-water
quality environmental impacts. The sections following that
present EPA's selected options.
Technology costs contained herein represent the additional
investment required beyond those costs associated with BPT
technologies. The cost methodology is based-on a model approach
which describes typical industry characteristics. These models
and cost figures developed from them are discussed below.
Data in this document are taken from two reports, entitled:
1) "Offshore Oil and Gas Industry BAT and NSPS Analysis of
Implementation - Cost and Contaminant Removal - Drilling Waste,"
ERCE, 2/1991, and 2) "Offshore Oil and Gas Industry BAT and NSPS
Analysis of Implementation - Cost and Contaminant Removal -
Produced Water," ERCE, 2/1991.
B. DRILLING WASTES
1. Data Base and Cost Scenarios
In order to evaluate regulatory options for drilling waste
(muds and cuttings) associated with oil and gas production, a
XIII-1
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database and electronic spreadsheets were developed to facilitate
the comparison of these options. The database consisted of:
Projections of the number of wells that will be drilled
over the next 15-year period in each geographic region.
• Characteristics of a "model well" describing industry
norms in terms of well depth, volume of waste
associated with drilling activity, use of additives to
aid in drilling, and length of time to drill a well.
Characteristics of drilling waste specifying pollutant
concentration and physical properties of the waste
specific to certain drilling scenarios.
Failure rates of drilling waste with respect to certain
environmental compliance tests (e.g., static sheen,
toxicity tests).
• Disposal costs for land disposal of drilling waste.
The data were entered into electronic spreadsheets and used
to predict industry-wide compliance costs and pollutant removals
associated with various regulatory scenarios. No distinction was
made between BAT and NSPS wells in the evaluations, because the
vast majority of the wells would be considered new sources. Each
of the analyses was conducted for the four geographic regions
where drilling was projected (Gulf of Mexico, Pacific Coast,
Atlantic Coast, and Alaska). Costs for both the "constrained"
and "unconstrained" growth profiles for NSPS were computed;
however, only the costs for the unconstrained scenario are
included here.
XIII-2
-------
The impact of regulatory options was generally manifested in
one of two ways: substitution of less toxic drilling materials
for materials typically used, or transport and disposal of drill
waste on land. A number of regulatory scenarios were analyzed
for drilling fluids (muds) and drill cuttings to quantify
pollutant reduction and compliance cost. The following scenarios
were analyzed for drilling fluids:
1) BPT - This established a baseline of costs and
pollutant discharges under BPT regulations which had to
be factored into the cost/benefit analysis for BAT
options. BPT prohibits the discharge of muds
containing free oil.
2) BPJ - This established an updated baseline for costs
and pollutant removals which included constraints
imposed in existing general permits issued for offshore
areas where drilling was active. BPJ (in addition to
BPT) prohibits the discharge of oil-based drilling
fluids. In addition, BPJ includes a prohibition on the
discharge of diesel oil, a no discharge of free oil
using the static sheen test, and toxicity limitations
of 30,000 ppm. (See Section III for a description of
current permit requirements.)
3) BAT/NSPS limits equal to BPJ ("least cost BAT")
4) BAT/NSPS limits requiring zero discharge of all
drilling fluids
5) BAT/NSPS limits requiring zero discharge of all
drilling fluids from shallow water wells; BAT/NSPS
limits equal to "least cost BAT" for deep water wells.
XIII-3
-------
6) BAT/NSPS limits requiring zero discharge of all
drilling fluids from wells within 4 miles of shore;
BAT/NSPS limits equal to "least cost BAT" for wells
greater than 4 miles from shore.
7) BAT/NSPS limitations of cadmium and mercury levels in
barite supplies used in drilling fluids were evaluated
in conjunction with options 3, 5, and 6 above. Two
levels were evaluated: a limit of 5 and 3 mg/L on Cd
and Hg, respectively, in the stock barite (equivalent
to levels in current barite supplies) and a limit of l
mg/L of each in the drilling fluid.
Electronic spreadsheets were developed for each of the four
geographical regions which analyzed each of the cases specified
above. The spreadsheets are contained in floppy disk form in the
record for this rulemaking.
A similar set of evaluations was performed for drill
cuttings:
1) BPT - Prohibition of discharge of cuttings containing
"free oil."
2) BPJ - BPJ is the same as BPT for cuttings in terms of
compliance costs and pollutant removal. Material
substitution and associated cost/benefit is allocated
to the drilling fluid analysis.
3) BAT/NSPS limitations prohibiting the discharge of
cuttings containing diesel oil or from drilling with
oil-based mud ("Least Cost" BAT) in addition to BPT
limitations. These limitations are termed "least cost
XIII-4
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BAT" because many of the limitations are similar to
those contained in general permits.
4) BAT/NSPS limitations requiring zero discharge of all
drill cuttings.
5) BAT/NSPS limitations requiring zero discharge of
cuttings from shallow water wells; "least cost"
BAT/NSPS for deep water wells.
6) BAT/NSPS limits requiring zero discharge of all drill
cuttings from wells within 4 miles of shore; "least
cost BAT" for wells greater than 4 miles from shore.
7) BAT/NSPS limitations for cadmium and mercury were
evaluated for 5/3 mg/kg in the barite or 1/1 mg/kg in
the whole drilling fluids for options 3, 5, and 6.
2. Basis for Analysis and Assumptions
a) Drilling Activity
Estimates of well drilling activity for the period 1986-2000
are presented in Sections III and IV. Estimates were performed
on the shallow/deep classification and also distance-from-shore
classification. Costs are presented only for the unconstrained
profile.
b) Model Well Characteristics
In order to predict the cost to implement regulatory options
and quantify the associated pollutant reductions, characteristics
of typical or average wells were defined. The "model well"
characteristics were entered into the electronic spreadsheet and
XIII-5
-------
used to predict waste volumes, physical and chemical nature of
drill waste, drilling practices, and use of mud additives. Table
XIII-1 defines the "model well" characteristics used in the
analysis.
c) Drilling Waste Compliance Failure Rates
Based on permit data and information compiled by the API,
estimates were made regarding the likelihood of drilling waste
associated with the "model well" failing either the static sheen
or toxicity test procedures (see Table XIII-2).
d) Drill Waste Onshore Disposal Cost
For drilling muds, three estimates of onshore disposal cost
were developed: the first two assume costs for disposal under
certain wave height conditions using a dedicated boat to receive
waste; the third assumes retrofit of the platform to provide
waste storage between shipments. Because the third cost was
lower, EPA assumed 80% of platforms would be modified and 10%
would incur each of the higher costs. The "composite" cost was
$36.83 per barrel of drilling fluids and $51.03 per barrel of
cuttings. This cost includes all costs associated with land
disposal of drilling wastes.
e) Order of Costing
In evaluating the cost of regulatory options, certain
assumptions were made. For the "least cost BAT" option, it was
assumed that all drilling operations would utilize material
substitution rather than have to take waste onshore for disposal.
This includes substituting mineral oil for diesel and using
"clean" barite. For zero discharge, however, such material
substitution was not utilized. For cases where a waste may
XIII-6
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TABLE XIII-1
MODEL WELL CHARACTERISTICS
1) Average Well Depth and Drilling Waste Volume
Veil Depth Waste Volume - BBLS
Region fftl ' (muds/cuttings/total1
Gulf of Mexico 10.523 6926/1471/8397
California 7.911 6047/1262/7309
Alaska 8.922 6385/1345/7730
Atlantic 14.874 9476/2577/12053
2) Typical Drilling Scenario
a) Stuck drill pipe incidents • 22Z of veils experience stuck pipe;
59Z use diesel pills to free pipe; 41Z use mineral pills to free
pipe; typical incident occurs *t 8,000 of well depth.*
b) Lubricity - 12Z of wells utilise lubricity agents in mud; 69Z use
mineral oil for lubricity; 31Z use diesel oil for lubricity.*
c) Drilling time • 35 days are needed to drill, average well; of this
20 days are spent drilling.
d) Deep wells - 30.8Z of wells are greater than 10,000 feet deep;
assume use of oil-based mud from 10,000 to 14,000 feet; assume
stuck pipe occurs in 22Z of cases 112,000 feet.7
3) Diesel/Mineral Oil Usage
a) Oil for lubricity equals 3Z by volume of mud.
b) Oil for pill is equal to 100 bbls; 50Z is retained in mud and 50Z
is in cuttings.
c) Concentrations of organic priority pollutants in diesel and
mineral oil are specified (see Attachment 1).
d) Cost to substitute mineral oil for diesel oil is $2/gallon.
4) Clean/Dirty Barite
a) Bg/Cd levels in 'clean* barite are assumed to be 1 mg/1 each; for
•dirty* barite levels are 3 mg/1 and 5 mg/1, respectively.
b) Cost to substitute clean barite is $13.50 per ton of barite.
c) Cuttings contain 88 Ibs of barite per barrel.
5) Pollutant Concentration of Drill Muds/Cuttings
Based on analysis of drilling muds and cutting, levels of metals,
conventional pollutant and organic priority pollutants are specified for
different types of drilling muds (e.g., with/without lubricity) and
drill cuttings (refer to Attachment 1 for actual compositions).
XIII-7
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TABLE XIII-2
TOXICITY/STATIC SHEEN FAILURE RATES
Fail Sheen Fail Toxicity
Drill Waste (%) (%)
Water-based mud; no oil 0 1
Water-based mud; with spot 0 33
Water-based mud; with lubricity 0 33
Water-based mud; with spot and
lubricity 0 56
Oil-based mud 100 N/A
Cuttings - water-based mud 0 N/A
Cuttings - oil-based mud 100 N/A
XIII-8
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require onshore disposal due to failure of sheen or toxicity
tests, the impact of the sheen test was evaluated and the impact
of toxicity regulations was assessed on that segment of the well
population still eligible for offshore disposal.
f) Contaminant Removal
In determining pollutant removals, specific pollutants were
selected for evaluation based on their consistently significant
presence in offshore oil and gas wastes. Removals are considered
direct or incidental. The priority pollutants, conventionals,
oil, and nonconventionals, listed in the Tables on contaminant
removals are pollutants directly removed by the technologies
being evaluated. For the priority pollutants, pollutant removals
were calculated on the sum total of concentrations for benzene,
naphthalene, fluorene, phenanthrene, phenol, cadmium, mercury,
antimony, arsenic, beryllium, chromium, copper, lead, nickel,
selenium, silver, thallium, and zinc. The nonconventionals
evaluated consisted of classes of organics including the
alkylated homologs for benzene, naphthalene, biphenyl, fluorene,
and phenanthrene, the alkylated phenols for ortho-cresol, meta +
para-cresol, C2 phenols, C3 phenols, and C4 phenols, and total
dibenzothiophenes. An additional category labeled "incidental
removal" was included to measure removals of pollutants by
technologies not necessarily intending to remove them. These
pollutants are the same as the priority pollutant metals and
include cadmium, mercury, antimony, arsenic, beryllium, chromium,
lead, nickel, selenium, silver, zinc, and thallium.
3. Results of Analysis
An analysis of each regulatory option was conducted to
determine:
XIII-9
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• Number of wells affected
• Cost incurred by industry to comply with the
regulations
• Volume and percent of drilling waste requiring onshore
disposal
Direct and incidental pollutant removal
The full details of each analysis for each geographic region
are presented in the spreadsheets included as Attachment 1 to the
drilling waste cost report mentioned at the beginning of this
section. Summary tables of each option have been prepared and
are included here. To aid the reader, Table XIII-3 identifies
the regulatory option with the corresponding table containing the
results of the analysis. Tables XIII-4A through XIII-4I present
the results of the analysis for drilling fluids and Tables XIII-
5A through XIII-5H for drill cuttings.
As shown, two baselines are presented. BPT represents the
costs/pollutant removals that would be incurred by well drilling
under current BPT regulations. BPJ represents the costs/
pollutant removals that would be incurred by well drilling under
current general permit limitations as they are currently
enforced. It should be noted that costs/pollutant removals for
BPJ and BAT options are all incremental to BPT. (Note also that
BPJ is identical to BPT for drill cuttings.)
In evaluating the options, it was assumed that drilling
operations would take advantage of material substitution to
minimize the likelihood of incurring the cost of onshore
disposal. As such, for the "least cost" BAT options, mineral oil
was substituted where diesel was normally used and "clean" barite
XIII-10
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TABLE XIII-3
REGULATORY OPTIONS AND CORRESPONDING ANALYSIS RESULTS
Drilling Fluids
Baseline Conditions:
BPT Table 4A
BPJ Table 41
BAT/NSPS Regulatory Options Combined with 3/5 mg/1 Limits on Cd/Hg
Levels in Barite Supply:
1) "Least Cost" BAT Table 4B
2) Zero Discharge Table 4C
3) Shallow Water Wells - Zero Discharge
Deep Water Wells - "Least Cost" BAT Table 4D
4) Wells <4 miles from shore - Zero Discharge
Wells >4 miles from shore - "Least Cost" BAT Table 4G
BAT/NSPS Regulatory Options Combined with 1/1 mg/1 Limits on Cd/Hg
Levels in Whole Drilling Fluid:
1) "Least Cost" BAT Table 4E
2) Zero Discharge N/A
3) Shallow Water Wells - Zero Discharge Table 4F
Deep Water Wells - "Least Cost" BAT
4) Wells <4 miles from shore - Zero Discharge
Wells >4 miles from shore - "Least Cost" BAT Table 4H
XIII-ll
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TABLE XIII-3 (Continued),
REGULATORY OPTIONS AND CORRESPONDING ANALYSIS RESULTS
Drill Cuttings
Baseline Conditions:
BPT Table 5A
BPJ (Same as BPT) Table 5A
BAT/NSPS Regulatory Options Combined with 3/5 mg/1 Limits on Cd/Hg
Levels in Barite Supply:
1) "Least Cost" BAT Table 5B
2) Zero Discharge Table 5C
3) Shallow Water Wells - Zero Dischage
Deep Water Wells - "Least Cost" BAT Table 5D
4) Wells <4 miles from shore - Zero Discharge
Wells >4 miles from shore - "Least Cost" BAT Table 5G
BAT/NSPS Regulatory Options Combined with 1/1 mg/1 Limits on Cd/Hg
Levels in Barite Supply:
1) "Least Cost" BAT Table 5E
2) Zero Discharge N/A
3) Shallow Water Wells - Zero Discharge Table 5F
Deep Water Wells - "Least Cost" BAT
4) Wells <4 miles from shore - Zero Discharge
Wells >4 miles from shore - "Least Cost" BAT Table 5H
XIII-12
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TABLE XIII-4A
ANNUAL POLLUTANT REMOVALS AND COST
DRILLING FLUIDS - BPT BASELINE
X
M
H
H
1
H
U>
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1b/yr)
Oil Removal (1b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
220
12,157,000
330,000
6.8
30,000
223,000
6,226,000
132,000
163,059,000
California
73
1,207,000
33,000
2.1
7,000
49,000
1,379,000
13,000
16,191,000
Location
Alaska
3.7
127,000
3,000
3.7
600
3,000
86,000
1,000
1 ,704,000
Atlantic
4.9
404,000
11,000
10.2
800
6,000
171,000
4,000
5,419,000
Total
302
13,895,000
377,000
38,000
281,000
7,862,000
150,000
186,373,000
-------
TABLE XIII-4B
ANNUAL POLLUTANT REMOVALS AND COST*
"LEASE COST" BAT WITH 5/3 Hg/Cd LIMITS
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBUyr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1 b/yr)
Oil Removal (1b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
270
16,764,000
421,000
8.7
21,200
583,000
3,150,000
145,000
160,000,000
California
90
4,402,000
109,000
6.8
6,700
183,000
961 ,000
37,000
42,000,000
Location
Alaska
4.5
242,000
6,000
7.4
400
9,000
50,000
2,000
2,000,000
Atlantic
6.0
621 ,000
16,000
14.8
500
15,000
87,000
6,000
6,000,000
Total
371
22,029,000
552,000
-
28,800
790,000
4,248,000
190,000
210,000,000
*AII costs/removals were calculated incremental to BPT
-------
TABLE XIII-4C
ANNUAL POLLUTANT REMOVALS AND COST*
DRILLING FLUIDS - ZERO DISCHARGE
X
H
H
H
I
H
O1
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBUyr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1 b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
715
176,388,000
4,952,000
102.6
15,200
602,000
7,400,000
479,000
1,108,000,000
California
237
51,553,000
1,435,000
89.7
4,700
185,000
2,300,000
130,000
275,000,000
Location
Alaska
12.0
2,746,000
77,000
95.1
200
10,000
100,000
3,000
15,000,000
Atlantic
16.0
5,297,000
152,000
140.9
400
17,000
200,000
16,000
45,000,000
Total
980
235,984,000
6,616,000
-
20,500
814,000
10,000,000
628,000
1 ,443,000,000
'All costs/removals were calculated incremental to BPT
-------
TABLE XIII-4D
ANNUAL POLLUTANT REMOVALS AND COST* - DRILLING FLUIDS
SHALLOW WELLS - ZERO DISCHARGE; DEEP WELLS -
"LEAST COST" BAT WITH 5/3 Hg/Cd LIMITS
X
H
H
H
Ov
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBUyr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1 b/yr)
Nonconventionals (1b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (ib/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
699
78,046,000
2,097,000
43.5
18,900
466,000
4,755,000
388,000
533,000,000
California
105
6,340,000
162,000
10.1
6,600
179,000
1,014,000
43,000
59,000,000
Location
Alaska
19.0
2,177,000
59,000
72.9
300
5,500
100,000
9,000
12,000,000
Atlantic
6.0
621,000
16,000
14.8
500
15,000
87,000
6,000
8,000,000
Total
829
87,184,000
2,334.000
26,300
665,500
5,956,000
446,000
612,000,000
* All Costs/removals were calculated incremental to BPT
-------
TABLE XIII-4E
ANNUAL POLLUTANT REMOVALS AND COST* - DRILLING FLUIDS
"LEAST COST" BAT WITH 1/1 Hg/Cd LIMITS
X
H
H
1
H
vj
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1b/yr)
Oil Removal (1b/yr)
Incidental Pollutant Removal (1 b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
715
24,444,000
421 ,000
8.7
27,000
583,000
3,150,000
143,000
160,000,000
California
237
6,956,000
109,000
6.8
8,600
183,000
964,000
37,000
42,000,000
Location
Alaska
12.0
371 ,000
6,000
7.4
500
9,000
50,000
2,000
2,000,000
Atlantic
16.0
793,000
16,000
14.8
600
15,000
87,000
6,000
6,000,000
Total
980
32,564,000
552,000
-
73,300
790,000
4,251 ,000
188,000
210,000,000
* All costs/removals were calculated incremental to BPT
-------
TABLE XIII-4F
ANNUAL POLLUTANT REMOVALS AND COST* - DRILLING FLUIDS
SHALLOW WELLS - ZERO DISCHARGE; DEEP WELLS -
"LEAST COST* BAT WITH 1/1 Hg/Cd LIMITS
X
H
H
H
H
00
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1 b/yr)
Nonconventionals (1b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1 b/yr)
Gulf of
Mexico
715
83,206,000
2,097,000
43.5
22,600
450,000
4,290,000
385,000
533,000,000
California
237
8,799,000
162,000
10.1
8,400
179,000
1,013,000
43,000
59,000,000
Location
Alaska
12.0
2,220,000
59,000
72.9
300
6,000
102,000
9,000
12,000,000
Atlantic
16.0
793,000
16,000
14.3
600
15,000
87,000
6,000
8,000,000
Total
980
95,018,000
2,334,000
31 ,900
650,000
5,492,000
443,000
612,000,000
*AII Costs/removals were calculated incremental to BPT
-------
TABLE XIII-4G
ANNUAL POLLUTANT REMOVALS AND COST* - DRILLING FLUIDS
WELLS < 4 MILES FROM SHORE - ZERO DISCHARGE; WELLS > 4 MILES
FROM SHORE - "LEAST COST" BAT WITH 5/3 Hg/Cd LIMITS
X
H
H
H
1
t .
H1
VO
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1b/yr)
Oil Removal (1b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of .
Mexico
270
16,674,000
421 ,000
8.7
21,200
583,000
3,150,000
145,000
160,000,000
California
237
6,099,000
109,000
6.8
8,700
183,000
961 ,000
37,000
42,000,000
Location
Alaska
12.0
63,000
0
0.0
459
8,000
0
0
0
Atlantic
0.0
0
0
0.0
0
0
0
0
0
Total
-
22,926,000
530,000
-
30,360
724,000
4,111,000
182,000
202,000,000
"All Costs/removals were calculated incremental to BPT
-------
to
o
TABLE XIII-4H
ANNUAL POLLUTANT REMOVALS AND COST* - DRILLING FLUIDS
WELLS < 4 MILES FROM SHORE - ZERO DISCHARGE; WELLS > 4 MILES
FROM SHORE - 'LEAST COST" BAT WITH 1/1 Hg/Cd LIMITS
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBUyr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1b/yr)
Oil Removal (1Wyr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
715
40,334,000
874,000
18.1
25,000
547,000
3,458,000
209,000
287,000,000
California
237
20,808,000
507,000
31.7
7,300
152,000
1 ,357,000
86,000
117,000,000
Location
Alaska
12.0
2,209,000
59,000
73.0
300
6,000
102,000
9.000
12,000,000
Atlantic
16.0
793,000
16,000
14.3
600
15,000
87,000
6,000
8,000,000
Total
980
64,144,000
1 ,456,000
-
33,200
720,000
5,004,000
310,000
424,000,000
•All Costs/removals were calculated incremental to BPT
-------
TABLE XIII-4I
ANNUAL POLLUTANT REMOVALS AND COST4
DRILLING FLUIDS - BPT BASELINE
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBUyr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1 b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
270
16,764,000
421 ,000
8.7
21,200
503,000
3,150,000
145,000
160,000,000
California
237
6,099,000
109,000
6.8
8,700
183,999
961 ,000
37,000
42,000,000
Location
Alaska
12.0
63,000
0
0.0
459
8,000
0
0
0
Atlantic
0.0
0
0
0.0
0
0
0
0
0
Total
-
22,926,000
530,000
30,360
774,000
4,111,000
182,000
202,000,000
*AII costs/removals were calculated incremental to BPT
-------
ro
TABLE XIII-5A
ANNUAL POLLUTANT REMOVALS AND COST
DRILL CUTTINGS - BPT BASELINE
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1 b/yr)
Nonconventionals (1b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
220
4,158,000
81,400
ND
13,300
214,000
5,966,000
8,100
44,200,000
California
73
495,000
9,700
ND
1,670
44,000
919,000
1,800
5,267,000
Location
Alaska
3.7
78,000
1,500
ND
170
2,900
80,000
100
554,000
Atlantic
10.0
121,000
2,400
ND
420
6,000
157,000
200
1 ,200,000
Total
306.7
4,852,000
95,000
15,560
266,900
7,122,000
10,200
51 ,221 ,000
ND = No Data
-------
TABLE XIII-5B
ANNUAL POLLUTANT REMOVALS AND COST• - DRILL CUTTINGS
"LEAST COST" BAT WITH 5/3 Hg/Cd LIMITS
H
H
H
to
No. of Wells Affected
Cost of Pollution Removal ($/yr)* *
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1 b/yr)
Nonconventionals (1 b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1 b/yr)
Gulf of
Mexico
0
0
0
0.0
0
0
0
0
0
California
0
0
0
0.0
0
0
0
0
0
Location
Alaska
0
0
0
0.0
0
0
0
0
0
Atlantic
0
0
0
0.0
0
0
0
0
0
Total
0
0
0
0.0
0
0
0
•o
0
* All costs/removals were calculated incremental to BPT
* * Cost associated with substitution of mineral oil for diesel oil is included in cost for drilling fluids.
-------
TABLE XIII-5C
ANNUAL POLLUTANT REMOVALS AND COST*
DRILL CUTTINGS - ZERO DISCHARGE
Location
Gulf of
Mexico
California
Alaska
Atlantic
Total
X
H
H
H
.-,-. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
715
237
12.0
16.0
1,048,000
299,100
16,100
980
53,666,000 15,200,000 1,235,000 2,104,000 72,205,000
211,000 1,574,200
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1 b/yr)
Nonconventionals (1b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (Ib/yr)
Conventionals - TSS Removal (1b/yr)
•-
8,220
116,000
3,226,000
72,400
571 ,000,000
—
3,210
23,000
627,000
19,000
163,000,000
—
140
1,100
39,000
9,100
8,800,000
—
210
3,200
103,000
22,400
22,400,000
—
1 1 ,780
143,300
3,995,000
122,900
765,200,000
'All costs/removals were calculated incremental to BPT
-------
Ol
TABLE XIII-5D
ANNUAL POLLUTANT REMOVALS AND COST* - DRILL CUTTINGS
SHALLOW WELLS - ZERO DISCHARGE; DEEP WELLS -
"LEAST COST" BAT WITH 5/3 Hg/Cd LIMITS
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1 b/yr)
Oil Removal (1b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
ND
19,857,000
388,000
-
2,300
11,300
317,000
24,800
205,000,000
California
ND
612,000
12,000
-
140
900
25,000
700
6,400,000
Location
Alaska
ND
895,000
11,700
-
30
360
9,900
700
6,300,000
Atlantic
ND
0
0
-
0
0
0
0
0
Total
-
21 ,364,000
411,700
-
2,470
12,560
351 ,900
»
26,200
217,700,000
"All Costs/removals were calculated incremental to BPT
ND = No data
-------
TABLE XIII-5E
ANNUAL POLLUTANT REMOVALS AND COST* - DRILL CUTTINGS
"LEAST COST" BAT WITH 1/1 Hg/Cd LIMITS
X
H
H
H
to
a\
No. of Wells Affected
Cost of Pollution Removal ($/yr)**
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1b/yr)
Oil Removal (1bfyr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
0.0
0
0
. -
0
0
0
0
0
California
0.0
0
0
-
0
0
0
0
0
Location
Alaska
0.0
0
0
-
0
0
0
0
0
Atlantic
0.0
0
0
-
0
0
0
0
0
Total
0.0
0
0
-
t~
0
0
0
• o
0
* All costs/removals were calculated incremental to BPT
"Cost associated with Barite Supply and substitution of mineral oil for diesel oil is included in costs for drilling fluids.
-------
TABLE XIII-5F
ANNUAL POLLUTANT REMOVALS AND COST* - DRILL CUTTINGS
SHALLOW WELLS - ZERO DISCHARGE; DEEP WELLS -
"LEAST COST" BAT WITH 1/1 Hg/Cd LIMITS
X
M
H
H
1
to
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1 b/yr)
Nonconventionals (1 b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
ND
19,857,000
388,000
-
2,860
1 1 ,400
317,000
24,500
205,000,000
California
ND
612,000
12,000
—
100
900
23,700
700
6,400,000
Location
Alaska
ND
895,000
12,000
—
30
270
7,600
700
6,300,000
Atlantic
ND
0
0
-
0
0
0
0
0
Total
-
21,364,000
412,000
-
2,990
12,570
348,300
25,900
217,700,000
*AII Costs/removals were calculated incremental to BPT
ND = No data
-------
I
to
oo
TABLE XIII-5G
ANNUAL POLLUTANT REMOVALS AND COST* - DRILL CUTTINGS
WELLS < 4 MILES FROM SHORE - ZERO DISCHARGE; WELLS > 4 MILES
FROM SHORE - "LEAST COST" BAT WITH 5/3 Hg/Cd LIMITS
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
-
5,367,000
104,000
-
630
3,900
85,800
6,700
55,400,000
California
_
4,589,000
89,800
-
1,020
6,800
188,300
5,700
48,200,000
Location
Alaska
-
895,000
11,700
-
30
360
9,900
700
6,300,000
Atlantic Total
-
0 10,851,000
0 205,500
- -
0 1,680
0 11,060
0 284,000
0 13,100
0 109,900,000
'All Costs/removals were calculated incremental to BPT
-------
TABLE XIII-5H
ANNUAL POLLUTANT REMOVALS AND COST* - DRILL CUTTINGS
WELLS < 4 MILES FROM SHORE - ZERO DISCHARGE; WELLS > 4 MILES
FROM SHORE - "LEAST COST" BAT WITH 1/1 Hg/Cd LIMITS
X
H
H
1
VO
No. of Wells Affected
Cost of Pollution Removal ($/yr)
Volume of Drilling
Fluid Barged (BBL/yr)
% of Total Drilling Fluid Barged (%)
Priority Pollutant Removal (1b/yr)
Nonconventionals (1 b/yr)
Oil Removal (1 b/yr)
Incidental Pollutant Removal (1b/yr)
Conventionals - TSS Removal (1b/yr)
Gulf of
Mexico
-
5,367,000
104,000
-
780
3,900
85,800
6,600
55,400,000
California
-
4,589,000
89,600
-
500
6,400
178,000
5,600
48,200,000
Location
Alaska
-
895,000
11,700
-
30
270
7,600
700
6,300,000
Atlantic
-
0
0
-
0
0
0
0
0
Total
-
10,841,000
205,300
-
1,310
10,570
271 ,400
12,900
109,900,000
* All Costs/removals were calculated incremental to BPT
-------
was used in formulating drilling fluids. The cost of the
material substitution was justified as the cost was lower than
onshore disposal. For the zero discharge options, material
substitution had no cost benefit and was not practiced. The two
options which distinguish between shallow/deep and near shore
wells are hybrids of the first two: shallow water wells and near
shore wells have a zero discharge limitation on both drill fluids
and cuttings while deep water and distant from shore wells must
meet "least cost" BAT limitations.
Costs are presented on an annual basis only; no capital
costs are presented because no capital costs were identified for
any of the drilling fluids and drill cuttings options.
The use of a distance from shore designation with more
stringent limitations was evaluated as an alternative to the
original shallow/deep water distinction. Initially, a distance
from shore of either 4, 6, or 8 miles was evaluated as the cutoff
point for zero discharge limitations. The favored option of the
three distance designations was based on a 4-mile distance, and
the associated cost/benefit summary is presented in Tables XIII-
4G,H and XIII-5G,H.
Table XIII-6 summarizes the combined costs for drilling
fluids and drill cuttings for each regulatory option based on the
information in Tables XIII-4 and XIII-5.
C. PRODUCED WATER
Compliance costs for the regulatory options presented in
Section XI are presented here based on the use of membrane
filtration and or injection as technologies incremented to BPT.
costs for the use of granular media filtration, rather than
membrane filtration, arc presented in Appendix 1 of this
XIII-30
-------
TABLE mi-6
ANNUAL COMPLIANCE COST/POLLUTANT REMOVALS TOR REGULATOR! OPT10HS -
DRILLING FLUIDS AMD DRILL CUTTIHGS COMBINED
Coit of pollution raaoval
-------
document. Membrane filtration is the preferred option because it-
surpasses granular media filtration in both performance, and
cost/space benefits.
1. Data Base and Cost Scenarios
In order to evaluate regulatory options for discharge
limitations on produced water associated with oil and gas
extraction, a database and electronic spreadsheets were developed
to facilitate the comparison of these options. The database
consisted of:
• Industry profile data on the number and type of
platforms and produced water discharge rates
• Projected future production activity
Produced water contaminant levels associated with BPT
treatment and with BAT/NSPS treatment options
• Cost to implement the BAT/NSPS treatment technology
options
The data were entered into the electronic spreadsheets and used
to predict industry-wide implementation costs and pollutant
removals.
Three treatment scenarios and various combinations of them
were evaluated for both BAT and NSPS; they are:
Filtration and surface discharge of all produced water
for both shallow and deep water wells
XIII-32
-------
• Filtration and zero discharge to surface water for both-
shallow and deep water wells by deep well injection at
the platform location
(For shallow water wells only) - Filtration and zero
discharge to surface water by deep well injection
either at the platform or, where less costly, by piping
to shore for treatment/reinjection
Additionally, for the filtration/surface water discharge
case, an alternative to dividing platforms among shallow water
and deep water designations was considered. This alternative
differentiated wells based on distance from shore and divided the
industry into those wells within 4 miles from shore and those
outside the 4-mile perimeter. All costs for filtration were
performed based on membrane filtration technology. See Appendix
1 for granular media filtration costs.
An analysis was conducted for each option under BAT and
NSPS, which defined the cost and the pollution reduction on a
regional basis. A separate file was established for each case in
the spreadsheets, which are part of the rulemaking record.
2. BAT
a) Industry Profile
Because calculation of cost/pollutant reduction on a
platform-by-platform basis was considered impractical from a data
collection standpoint, the industry was characterized as
consisting of a platform population divided among "model
platforms." These "model platforms" were considered typical of
the industry and were differentiated based on the number of well
slots on the platform. For each "model platform" it was possible
to predict the number of producing wells, the quantity of
XIII-33
-------
produced water generated (average and peak flow), and the cost to-
implement a produced water treatment sys":-^m. Thus, by dividing
the industry among these "model platforms," estimates of cost and
pollutant reduction could be derived.
The model industry profile is presented in Table XIII-7.
The platform population is divided into shallow and deep water
wells and into three well categories: 1) oil facilities, 2) oil
and gas facilities, and 3) gas facilities. These facilities are
allocated among four geographic regions: 1) Gulf of Mexico, 2)
Pacific Coast, 3) Atlantic Coast, and 4) Alaska. The wells in
each region are then divided among the "model platforms" to most
accurately mirror data contained in the rulemaking record
regarding well population and type. The total number of
structures shown in this table corresponds to the tables in
Sections III and IV as they relate to the "unrestricted" profile
growth scenario.
A second industry categorization was developed based on
differentiating between wells within 4 miles of shore and those
outside the 4-mile cutoff. These data are presented in Table
XIII-8. For the structure types listed in Table XIII-8, average
and maximum produced water rates would be the same as those given
in Table XIII-7. Table XIII-8A is a summary of BAT produced
water flowrates.
b) Contaminant Removal
Contaminant removals associated with BAT options are
determined by comparing the effluent levels after treatment by
the BAT treatment system (either filtration or reinjection)
versus the effluent levels associated with a typical BPT
XIII-34
-------
TABLE XIII-7
"MODEL" PROFILE OP EXISTING PRODUCTION WELLS/SHALLOW AND DEEP WELLS
Total .Number
Total Number Of Structures
Structure Of Structures This Size Now
Type This Type Injecting
SHALLOW WATER
OIL FACILITIES
Gulf of Mexico Gulf la 62
Gulf Ib 6
Gulf 4 36
Gulf 6 10
Gulf 12 9
Gulf 24 3
Gulf 40 0
Gulf 58 0
Pacific Coast Pacific 16 0
Pacific 40 0
Pacific 70 0
Atlantic Coast Atlantic 24 0
Alaska -
Cook Inlet 24 0
Beaufort Sea Platform 48 0
Beaufort Sea Gravel Island 48 0
Navarin Platform 48 0
Norton Platform 34 0
Sub-Totals: 126 0
OIL and GAS FACILITIES
Gulf of Mexico Gulf la 207
Gulf Ib 84
Gulf 4 77
Gulf 6 47 2
Gulf 12 39
Gulf 24 43
Gulf 40 0
Gulf 58 0
Pacific Coast Pacific 16 5
Pacific 40 0
Pacific 70 5
Atlantic Coast Atlantic 24 0
Alaska -
Cook inlet Cook Inlet 24 0
Sub-Totals: 507 2
GAS FACILITIES
Gulf of Mexico Gulf la 349
Gulf Ib 175
Gulf 4 82
Gulf 6 51
Gulf 12 16
Gulf 24 3
Pacific Coast Pacific 16 0
Atlantic Coaat Atlantic 24 0
Alaska -
Cook Inlet 12 0
Total Number
Producing
Wella/Struc.
1
1
4
6
10
18
32
50
14
33
60
20
20
40
40
40
28
-
1
1
4
6
10
18
32
50
14
32
60
20
20
-
1
1
4
6
10
18
14
20
10
Avg. Flow
Prod. Water
kkb/year/
Structure
#
90
107
443
665
994
1,939
3,605
5,486
2,358
5,213
9,324
4,283
9,247
15,965
16,740
16,740
11,248
-
95
111
456
685
1,034
2,000
3,604
5,631
2,358
5,213
9,324
4,419
9,247
-
6
5
20
28
54
89
112
219
41
Max. Flow ,
Prod: Water
bbl/day/
Structure
421
461
1,871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
18,610
37,449
71,257
72,763
72,763
49,586
-
434
468
1 ,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
18,849
37,449
-
68
68
272
408
680
1,224
1,190
2,550
2,550
Sub-Totals: 676 0 -
TOTALS ALL SHALLOW
FACILITIES:
1,309
XIII-35
-------
TABLE XIII-7 (Continued)
"MODEL" PROFILE OF EXISTING PRODUCTION WELLS/SHALLOW AND DEEP WELLS
Total' Number
Total Number Of Structures
Structure Of Structures This Size Now
Type This Type Injecting
DEEP WATER
OIL FACILITIES
Gulf of Mexico Gulf la 2
Gulf Ib A 1
Gulf 4 5
Gulf 6 8 1
Gulf 12 13 1
Gulf 24 2
Gulf 40 1
Gulf 58 0
Pacific Coast Pacific 16 0
Pacific 40 0
Pacific 70 0
Atlantic Coast Atlantic 24 0
Alaska -
Cook Inlet 24 0
Beaufort Sea Platform 48 0
Beaufort Sea Gravel Island 48 0
Navarin Platform 48 0
Norton Platform 34 0
Sub-Totals: 35 3
OIL and GAS FACILITIES
Gulf of Mexico Gulf la 13 1
Gulf Ib 11
Gulf 4 34
Gulf 6 79 5
Gulf 12 179 8
Gulf 24 153 2
Gulf 40 2
Gulf 58 0
Pacific Coast Pacific 16 3
Pacific 40 6
Pacific 70 7
Atlantic Coast Atlantic 24 0
Alaska -
Cook Inlet 24 0
Sub-Totals t 487 16
CAS FACILITIES
Gulf of Mexico Gulf la 41
Gulf Ib 75 1
Gulf 4 82
Gulf 6 106 1
Gulf 12 88
Gulf 24 36
Pacific Coast Pacific 16 1
Atlantic Coast Atlantic 24 0
Alaska -
Cook inlet Cook Inlet 12 0
Sub-Totals : 429 2
TOTALS ALL DEEP FACILITIES: 951 21
TOTALS ALL FACILITIES! 2,260 23
Total Number
Producing
Wells/Struc.
1
1
4
6
10
18
32
50
14
33
60
20
20
40
40
40
28
-
1
1
4
6
10
18
32
50
14
32
60
20
20
1
1
4
6
10
18
14
20
10
-
-
-
Avg. Flow
Prod. Water
kkb/year/
Structure
90
107
443
665
994
1,939
3,605
5,486
2,358
5,213 .
9,324
4,283
9,247
15,965
16,740
16,740
11,248
-
95
111
456
685
1,034
2,000
3.604
5,631
2,358
5,213
9,324
4,419
9,247
-
6
5
20
28
54
89
112
219
41
-
-
.
Max. Flow
Prod. Water
bbl/day/
Structure
421
461
1,871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
18,610
37,449
71,257
72,763
72,763
49,586
-
434
468
1,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
18,849
37,449
-
68
68 .
272
408
680
1,224
1,190
2,550
2,550
-
-
-
XIII-36
-------
TABLE XIII-8
"MODEL" PROFILE OF EXISTING PRODUCTION WELLS
ACCORDING TO DISTANCE FROM SHORE
Number of Structures
X
H
H
1
u>
-J
Structure
Type
Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific 16
Pacific 40
Pacific 70
Atlantic
Alaska
Oil Only
£ 4 Mi.
26
1
23
0
0
0
0
0
0
0
0
Oil Only
> 4 Mi.
38
9
18
18
22
5
1
0
0
0
0
No existing
Oil and Gas
< 4 Mi.
27
13
10
2
3
8
0
0
7
0
4
facilities
No facilities that do
Oil and Gas Gas Only Gas Only
> 4 Mi. £ 4 Mi. > 4 Mi. <
193
82
101
124
215
188
2
0
1
.6
8
not already
53
22
8
1
0
0
0
0
0
0
0
re-inject
337
228
156
156
104
39
0
0
1
0
0
produced water
Total
4 Mi.
106
36
41
3
3
8
0
0
7
0
4
Total
> 4 Mi.
568
319
275
298
341
232
3
. 0
2
6
8
Total
674
355
316
301
344
240
3
0
9
6
12
TOTAL
2,260
-------
TABLE XIII-8A. BAT - PRODUCED WATER FLOWRATES
1. Regional produced water rates with shallow water designation
based on water depth at drill site.
Water Rate (MMBBLS/YR)
Region
Gulf of Mexico
Pacific
Alaska
Atlantic
Total
Shallow
277.003
58.41
0
0
330.413
Deep
594.511
103.732
0
0
698.243
Total
866.514
162.142
0
0
1028.656
2. Regional produced water rates based on distance from shore at
drill site (<4 miles).
Water Rate (MMBBLS/YR1
Region
Gulf of Mexico
Pacific
Alaska
Atlantic
Total
< 4 Miles
42.292
53.802
0
0
96.094
> 4 Miles
825.592
108.34
0
0
933.932
Total
867.884
162.142
0
0
1030.026
XIII-38
-------
treatment. Data used to calculate removals are given in Table
XIII-9. BPT data are based on the Thirty Platform Study
performed by EPA in 1985. Filtration system effluent
concentrations are estimated primarily from vendor performance
information. Electronic spreadsheets were developed to calculate
contaminant removals for all regulatory options on a regional
basis using the flow and contaminant removal data. Pollutant
removal quantities were calculated by multiplying the average
produced water rate for each model platform by the difference in
contaminant levels for BPT and BAT. Pollutant removal quantities
were then summed for each well category and for each geographic
region. The contaminant removal spreadsheets are presented in
Appendix 4, Table 4A, for BAT membrane pollutant removals. A
summary of the contaminant removals per option is given later in
Table XIII-12.
c) Implementation Cost
The costs to install a BAT treatment system for each of the
model platforms was estimated based on the maximum produced water
flow rate over the life of the project and the cost of a
treatment system designed to provide the needed capacity. Data
were entered into the spreadsheets which defined system cost for
five systems over a range of flow rates (200-40,000 barrels per
day); the spreadsheet graphed these data to provide a
relationship between peak water flow rate and system cost; the
spreadsheet then determined the cost for each model platform
based on its peak water flow rate. The cost to implement the BAT
option was determined by summing the costs for each model
platform.
XIII-39
-------
TABLE XIII-9.
WASTEWATER CONCENTRATION AFTER
BPT TREATMENT AND BAT OPTIONS FOR MEMBRANE FILTRATION
Contaminant
Benzene
2,4-dimethylphenol
Ethylbenzene
Naphthalene
Toluene
Bis(2-ethylhexyl)
phthalate
Phenol
m-xylene
p-cresol
n-alkanes
2-butanone
Steranes
Triterpanes
Radium
Aluminum
Arsenic
Boron
Barium
Copper
Iron
Manganese
Titanium
Zinc
BPT Effluent
(ue/1)
BAT - Filter1
(ug/1)
1829
14.3
505
138
1545
101
953
153
364
1642
1670
63
76
0.004 (equiv.)
123
309
22540
21372
113
4466
161
8.5
2360
91 100
0.7 • all
25
6.9
77
5.1
48
7.7
18
82
84
3.2
3.8
0.0036 (equiv.)
74
185
22410
19847
68
3196
153
5.1
24
BAT - Rein lection
100Z removal of .
all contaminants
Organics removal equal to 95Z based on membrane filtration performance data
on dissolved oil and grease. Cu, As, Al, Ti removal equal to 40Z based on
general filtration data. Ra removal equal to 102 based on incidental
removal. Zn removal equal to 99Z based on improved performance of membrane
filters compared to performance of deep bed filters as per three-facility
study. Ba, B, Mg removal based on data from three-facility study.
XIII-40
-------
Filtration/Surface Water Discharge:
This option includes the cost of installing a membrane
filter to reduce levels of pollutants prior to discharge to
surface water. It assumes that the water is first treated with
BPT treatment; BPT treatment is considered to be a Dissolved Air
Flotation (DAF) unit or the equivalent, but the cost of BPT
treatment is not included in the implementation cost. The cost
of a filtration system over a range of design flow rates is
presented in Table XIII-10. Table XIII-10 also presents
estimates of annual cost for the filtration systems over the same
flow range, geographical area multipliers which take into account
the difference in capital costs for oil production in areas other
than the Gulf of Mexico, and assumptions used in deriving costs
under specific circumstances.
Filtration/Reinjection (Zero Discharge):
This option includes the cost of installing a membrane
filter to reduce levels of TSS prior to deep-well injection of
the produced water and hardware associated with the injection
system. It is assumed that the produced water is first treated
with BPT treatment (DAF or equivalent). The cost of a
filtration/reinjection system over a range of design flows is
presented in Table XIII-11. Table XIII-11 also presents annual
costs over the same range of flows, geographic area multipliers
which take into account the difference in capital costs for oil
production in areas other than the Gulf of Mexico, cost to pipe
and treat the water at an onshore facility, costs of injection
well drilling, and assumptions used for deriving costs under
specific circumstances.
XIII-41
-------
TABLE XIII-10. COST DATA FOR MEMBRANE FILTRATION/SURFACE WATER DISCHARGE SYSTEM
FOR PRODUCED WATER TREATMENT
1. Capital Cost Versus Flowrate
Flowrate (BPD)
Component
Chemical Feed /Storage
Filtration
Piping
Platform Addition
Generators
Sub-Total* <
Ins. I Bonding (42)
TOTALS
200
54,000
64,500
17,775
0
0
136,275
5,451
141,726
1,000
54,000
115,500
25,425
23,571
0
218,496
8,748
227,236
5,000
54,000
256,500
31,050
25,285
0
366,835
14,673
381,500 .
10,000
54,000
310,500
36,450
27,000
0
427,950
17,118
445,068
40,000
72,000
564,000
63,600
36,429
0
736,029
29,441
765,470
2* AnTiw 1 Cost Versus Flowr&te
Flowrate (BPD)
Component
Labor
Maintenance
Chemicals
Energy
Sludge Disposal
TOTALS
3. Geographic Area Multiplier
200
32,800
4,252
65
1,200
5,500
43,817
Gulf of
Pacific
Atlantic
Alaska •
Alaska •
1,000
32,800
6,817
320
3,300
12,700
55,937
Mexico
Coast
• Cook Inlet
• Other
5,000
32,800
11,445
1,600
5,900
56,000
107,745
10,000
32,800
13,352
3,200
7,800
108.900
166,152
1.0
1.6
1.6
2.0
3.5
40,000
32,800
22,964
12,000
12,000
424,000
504,564
4. Assume for Gulf Ib platforms ii. sh*..low water, four platforms combine effluent and treat at single
facility with appropriate capacity.
XIII-42
-------
TABLE XIII-11.
COST DATA FOR MEMBRANE FILTRATION/REINJECTION SYSTEM
FOR PRODUCED WATER TREATMENT
1. Capital Coat Versus Flowrate
Component
Chemical Feed/Storage
Filtration
Injection System
Platform Addition
Generators
Sub-Totals :
Ins. & Bonding (41)
TOTALS
2. Annual Coat Versus Plewrate
Component
Labor
Maintenance
Chemicals
Energy
Sludge Disposal
TOTALS
3. Geographic Area Multiplier
200 1,000
54,000 54,000
64,500 115,500
68,600 109,800
0 0
0 23,571
187,100 302,871
7,484 12,115
194,584 314,986
200 1,000
32,800 32,800
5,838 9,450
65 320
1,200 3,300
5,500 12,700
45,483 58,578
Gulf of Mexico
Pacific Coast
Atlantic
Alaska - Cook ]
Alaska - Other
Flowrate (BPD)
5,000
•
54,000
256,500
139,100
0
25,285
474,885
18,995
493,880
Flowrate (BPD)
5,000
32,800
14,816
1,600
5,900
56,000
111,116
1.0
1.6
1.6
Inlet 2.0
3.5
10,000
54,000
310,500
228,300
0
27,000
619,800
24,792
644,592
10,000
32,800
19,338
3,200
7,800
108,700
171,838
40,000
72,000
564,000
527,900
0
36,429
1,200,329
48,013
1,248,342
40,000
32,800
37,450
12,800
12,000
424,000
519,050
4. Assume 372 of shallow wells woj?.d treat produced water onshore and reinject water onshore. The capital
and operating costs incurred for such an approach would be as follows' ("Pipeline-to-Shore" cost based on
average distance of formulas). Note - These costs were not revised from original onshore treatment
costs.
a) Capital Cost of Onshore Filtration/Rein lection System
Flowrate (BPD)
Component
Filter System
Reinjeetion System
Pipe-to-Shore
Chemical Feed /Storage
Generators
Sub-Totals :
Installation (30Z)
Engineering (10X)
Contingency (15Z)
Insurance/Bonding (41)
200
43,000
68,600
800,000
36,000
0
947,600
284,280
94,760
142,140
37,904
1,000
77,000
109,800
800,000
36,000
14,857
1,037,657
311,297
103,766
155,649
41,506
5,000
171,000
130,100
800,000
36,000
16,857
1,153,957
346,187
115,396
173,094
46,158
10,000
207,000
228,300
1,084,000
36,000
18,000
1,573,300
471,990
157,330
235,995
62,932
40,000
376,000
527,900
1,309,440
48,000
23,714
2,285,054
685,516
228,505
342,758
91,402
TOTALS
1,506,684 1,649,875 1,834,792 2,501,547 3,633,236
XIII-43
-------
TABLE XIII-11. (Cont'd). COST DATA FOR HLTRATION/REINJECTION SYSTEM
FOR PRODUCED WATER TREATMENT
b) Annual cost for Onshore Filtration/Rein lection System
Flowrate (BPD)
200 1,000 5,0.00 10,000 40,000
Component
Labor
Maintenance
Chemicals
Energy
32,800
28,428
19
343
32,800
31,130
91
943
32,800
34,619
457
1,686
32,800
47,199
914
2,229
32,800
68,552
3,657
3,429
TOTALS 61,589 64,964 69,562 83,142 108,437
5. Cost to Drill Offshore In lection Well - Based on drilling a 3,500 foot deep well. Cost is on
regionized basis and is derived from API Drill Cost Survey
Well Cost ($)
Oil/Oil and Gas Gas Only
Alaska 1,174,145 811,825
Pacific 937,930 2,524,130
Gulf of Mexico 1,191,295 1,428,200
Atlantic 1,673,000 1,673,000
.6. Coat to Drill Onshore In lection Well - Estimated at 155,000; based on API drill cost data
7. Coat to Convert Dry Hole to In lection Well - It is assumed that drill slots on model platforms that
are not used for production wells represent dry holes that can be converted to water injection wells;
cost is estimated at $240,000. (This does not agree with data in record - Vol. 17, Document E-27.)
8. Injection capacity of well is 6,000 BPD
9. Assume for Gulf Ib platforms in shallow water; four platforms combine effluent and treat at single
facility (either onshore or offshore) with appropriate capacity.
XIII-44
-------
d) Results
The implementation costs for contaminant removal are
*
presented in detail in spreadsheets. The results are summarized
in Table XIII-12. This table includes the information necessary
to determine costs for the various combinations comprising the
options presented in section XI, using membrane filtration for
the filtration options. Table XIII-13 summarizes the costs
according to the specific BAT regulatory options.
3. NSPS
a) Industry profile
Projections were made regarding new source wells likely to
begin production during the 15-year period 1986-2001 assuming a
selling price of oil at $21 per barrel. As in BAT, the projected
number of wells was divided among the same "model platform", it
was possible to predict the number of producing wells, the
quantity of produced water generated, and the cost to implement a
produced water treatment system.
The industry profile of new sources is presented in Table
XIII-14. These profile numbers are the same as those presented
in Sections III and IV according to the "unrestricted" growth
projections. As in BAT, the platform population is divided into
shallow and deep water wells and into three well categories: 1)
oil facilities, 2) oil and gas facilities, and 3) gas facilities.
These facilities are allocated among four geographic regions: 1)
Gulf of Mexico, 2) Pacific Coast, 3) Atlantic Coast, and 4)
Alaska. Additionally, as in BAT, an alternative designation for
shallow water wells was evaluated. Using a designation based on
distance from shore (<4 miles), the industry profile of NSPS
XIII-45
-------
TABLE Xlll-12. SUMMARY OF BAT IMPLEMENTATION COSTS AMD CONTAMINANT REMOVAL
FOR MEMBRANE FILTRATION SYSTEMS
of Platforms
Pollutant Reduction (lb/yr)
Capital Annual '
Coat ($) Cost ($/yr) Conventional Metals Organics
Filter/Surface Water Discharge*
Shallow Water 1,309 172,830,302 44,248,123 11,006,227
Deep Water 951 258,659,704 59,959,511 23,599,504
All Facilities 2,260 423,510,006 104,287,634 34,604,731
248,502 510,243
582,591 1,115,356
831,093 1,625,599
Filtration/Reinlection*
Shallow Water 1,309 1,258,707,237 76,194,925 18,100,909
Deep Water 951 1,099,597,169 84,474,055 38,591,292
All Facilities 2,260 2,358,304,406 160,668,900 56,692,201
254,566 574,779
595,407 1,254,608
849,973 1,829,387
Filter/Reinlect Onshore/Offshore for Shallow Wells*
Shallow Water 1,309 1,304,721,714
Filter/Surface Water Discharge
Welle < 4 Miles from Shore 208
Wells ~ 4 Miles from Shore 2,052
All Facilities 2,260
35,250,039
388,856,446
424,106,486
66,382,241
8,384,563
95,957,656
104,342,210
18,100,909 254,566 574,779
3,234,044
31,417,812
34,651,855
73,550 140,067
758,753 1,487,384
832,303 1,627,450
*Shallow designation based on water depth at drill site.
XIII-46
-------
TABLE XIII-13. SUMMARY OF IMPLEMENTATION COSTS FOR MEMBRANE FILTER SYSTEMS
AND CONTAMINANT REMOVAL - BAT
Pollutant Redaction (Ib/yr)
Capital Annual
t of Platforms Cost ($) Coat ($/yr) Conventional
Metals Organico
1,309 172,850,302 44,248,123 11,006,000
1,309 1,258,707,237 76,194,925 18,101,000
Filter Shallow/
BPT Deep
Reinject Shallow/
BPT Deep
Filter and Discharge All 2,260 423,510,006 104,287,634 34,605,000
2,260 1,517,366,941 136,154,436 41,700,000
Reinject Shallow/
Filter Deep
Reinject All
4 Mile/BPT Deep
2,260 2,358,304,406 160,668,900 56,693,000
208 35,250,039 8,384,563 3,234,000
249,000 510,000
255,000 575,000
831,000 1,626,000
837,000 1,690,000
850,000 1,829,000
74,000 140,000
TABLE XIII-13A. SUMMARY OF IMPLEMENTATION COSTS FOR MEMBRANE FILTER SYSTEMS
AND CONTAMINANT REMOVAL - NSPS
Pollutant Reduction (Ib/yr)
I of Platforms
Capital Annual
Cost ($) Cost ($/yr) Conventional
Metals Organic8
Filter Shallow/
BPT Deep
Reinject Shallow/
BPT Deep
Filter and Discharge All
Reinject Shallow/
Filter Deep
Reinject All
4 Mile/BPT Deep
393 104,874,421 22,108,417 6,599,000
393 607,540,177 35,937,583 10,894,000
851 300,853,708 61,717,562 27,404,000
C51 803,519,464 75,626,728 31,698,000
851 1,300,307,478 89,509,755 44,850,000
162 63,827,101 12,696,327 1,367,000
142,000 312,000
145,000 346,000
673,000 1,326,000
677,000 1,359,000
688,000 1,465,000
35,000 71,000
XIII-47
-------
TABLE XIII-14
"MODEL" PROFILE 0? NEW SOURCE PRODUCTION WELLS: SHALLOW AND DEEP
Total
Struc-
Structure tures for the
Type 15- Year Period
SHALLOW WATER
OIL FACILITIES
Gulf of Mexico Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast Pacific 16
Pacific 40
Pacific 70
Atlantic Coast Atlantic 24
Alaska -
Cook Inlet 24
Beaufort Sea Platform 48
0
0
0
0
0
0
0
0
0
0
0
0
0
Beaufort Sea Gravel Island 48 2
Navarin Platform 48
Norton Platform 34
Sub-Totals:
OIL and GAS FACILITIES
Gulf of Mexico Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast Pacific 16
Pacific 40
Pacific 70
Atlantic Coast Atlantic 24
Alaska -
Cook inlet Cook Inlet 24
Sub-Totals :
CAS FACILITIES
Gulf of Mexico Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast Pacific 16
Atlantic Coast Atlantic 24
Alaska -
Cook Inlet 12
Sub-Totals :
TOTALS ALL SHALLOW
FACILITIES:
0
0
2
12
63
19
34
8
12
0
1
2
0
0
0
151
53
100
53
29
5
0
0
0
240
393
Total Number
Producing
Wells/Struc.
1
4
6
10
18
32
50
14
33
60
20
20
40
40
40
28
-
1
4
6
10
18
32
50
14
32
60
20
20
-
1
4
6
10
18
14
20
10
-
'
Total
Producing
Wells .
0
0
0
0
0
0
0
0
0
0
0
0
0
80
0
0
80
12
252
114
340
144
384
0
14
64
0
0
0
1,324
53
400
318
290
90
0
0
0
1,151
2,555
Avg. Flow
Prod. Water
kbbl/year
•
114
469
703
1,071
2,056
3,696
5,767
2,579
5,720
10,128
4,664
9,247
17,100
17,766
17,766
12,054
-
117
480
720
1,105
2,109
3,782
5,893
2,579
5,720
10,128
4,664
9,247
-
5
18
27
49
81
98
204
40
-
-
Max. Flow
Prod. Water
bbl/day
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
19,224
37,449
73,405
74,503
74,503
51,169
-
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28,171
51,979
19,224
37,449
-
68
272
408
680
1,224
1,190
2,550
2,550
-
-
XIII-48
-------
TABLE XIII-14 (Continued)
"MODEL" PROFILE OF NEW SOURCE PRODUCTION WELLS: SHALLOW AND DEEP
Total Struc-
Strueture tures for the
Type 15-Tear Period
DEEP WATER
OIL FACILITIES
Gulf of Mexico Gulf Ib 0
Gulf 4 0
Gulf 6 0
Gulf 12 0
Gulf 24 0
Gulf 40 0
Gulf 58 0
Pacific Coast Pacific 16 0
Pacific 40 0
Pacific 70 0
Atlantic Coast Atlantic 24 0
Alaska -
Cook. Inlet 24 0
Beaufort Sea Platform 48 0
Beaufort Sea Gravel Island 48 0
Navarin Platform 48 0
Norton Platform 34 0
Sub-Total* t 0
OIL and CAS FACILITIES
Gulf of Mexico Gulf Ib 0
Gulf 4 26
Gulf 6 15
Gulf 12 50
Gulf 24 54
Gulf 40 15
Gulf 58 0
Pacific Coast Pacific 16 12
Pacific 40 52
Pacific 70 0
Atlantic Coast Atlantic 24 3
Alaska -
Cook Inlet 24 1
Sub-Totals: 228
GAS FACILITIES
Gulf of Mexico Gulf Ib 11
Gulf 4 46
Gulf 6 36
Gulf 12 67
Gulf 24 47
Pacific Coast Pacific 16 17
Atlantic Coast Atlantic 24 5
Alaska -
Cook inlet Cook Inlet 12 1
Sub-Totals: 230
TOTALS ALL DEEP FACILITIES: 458
TOTALS ALL FACILITIES: 851
Total Number
Producing
Wells/Struc.
1
4
6
10
18
32
50
14
33
60
20
20
40
40
40
28
-
1
4
6
10
18
32
50
14
32
60
20
20
-
1
4
6
10
18
14
20
10
-
-
-
Total
Producing
Wells
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
104
90
500
972
480
0
168
1,664
0
60
20
4,058
11
184
216
670
846
238
100
10
2,275
6,333
8,888
Avg. Flow
Prod. Water
kbbl/year
•
114
469
703
1,071
2,056
3,696
5,767
2,579
5,720
10,128
4,664
9,247
17,100
17,766
17,766
12,054
-
117
480
720
1,105
2,109
3,782
5,893
2,579
5,720
10,128
4,664
9,247
-
5
18
27
49
81
98
204
40
-
-
Max. Flow
Prod. Water
bbl/day
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
19,224
37,449
73,405
74,503
74,503
51,169
-
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28.171
51,979
19,224
37,449
-
68
272
408
680
1,224
1,190
2,550
2,550
-
-
-
XIII-49
-------
platforms within 4 miles from shore and those outside the 4-mile
perimeter is given in Table XIII-15. Flowrates are extracted
from the original data base and presented in Table XIII-16.
t
b) Contaminant Removal
Contaminant removals for NSPS are based on the same effluent
levels for BAT and are presented in Table XIII-9. The removals
are determined by comparing the effluent levels after treatment
by the NSPS technology versus effluent levels using BPT.
Detailed contaminant removals for new sources are present in
Tables 4B in Appendix 4. These removals are summarized later in
Table XIII-20.
c) Implementation Cost
The cost to install a NSPS treatment system for each of the
"model platforms" was estimated based on the maximum produced
water flow rate over the life of the project and the cost of a
treatment system designed to provide the needed capacity. Data
were entered into the spreadsheet which defined system cost for
five systems over a range of flow rates (200-40,000 barrels per
day). The spreadsheet graphed this information to provide a
relationship between peak water flow rate and system cost; the
spreadsheet then determined the cost for each model platform
based on its produced water flow rate. The cost to implement the
treatment option was determined by summing the costs for each
model platform.
XIII-50
-------
TABLE XIII-15
"MODEL" PROFILE OF NEW SOURCE PRODUCTION WELLS
ACCORDING TO DISTANCE FROM SHORE
All Platforms
Region Model
Gulf
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Pacific
Pacific 16
Pacific 40
Total
76
235
123
180
114
27
30
54
Oil & Gas Gas
12
89
34
84
62
27
13
54
64
146
89
96
52
0
17
0
Total
23
60
43
14
0
0
0
20
< 4 Miles
Oil & Gas
0
27
15
14
0
0
0
20
Gas
23
33
28
0
0
0
0
0
Total
53
175
80
166
114
27
30
34
> 4 Miles
Oil & Gas Gas
12
62
19
70
62
27
"
13
34
41
113
61
96
52
0
17
0
I
UI
H
Atlantic
Atlantic 24
3
Alaska
Cook Inlet
24/12
B. Gravel
Island*
* Oil only
-------
Shallow
150.472
14.019
35.532
0
Deep
258.091
330.054
9.287
15.012
Total
408.563
344.073
44.819
15.012
TABLE XIII-16. NSPS - PRODUCED WATER FLOWRATES
1. Regional produced water rates with shallow water designation
based on water depth at drill site.
Water Rate (MMBBLS/YR^i
Region
Gulf of Mexico
Pacific
Alaska
Atlantic
Total 200.023 612.444 812.467
2. Regional produced water rates based on distance from shore
at drill site (<4 miles).
Water Rate fMMBBLS/YR^
Region < 4 Miles > 4 Miles Total
Gulf of Mexico 40.695 368.028 408.723
Pacific 114.400 229.593 343.993
Alaska 35.532 9.287 44.819
Atlantic 0 15.012 15.012
Total 190.627 621.84 812.467
XIII-52
-------
Filtration/Surface Water Discharge:
This option includes the cost to install a membrane filter
to reduce levels of pollutants prior to discharge to surface
water. The cost assumes the water is first treated to BPT levels
with a DAF (or equivalent) unit but does not include the cost for
BPT treatment. The capital and cost for a filter system over a
range of design flows is presented in Table XIII-17.
Geographical area multipliers, which take into account the
difference in capital costs for oil production in areas other
than the Gulf of Mexico, are the same as those presented in Table
XIII-10.
Filtration/Reinjection (Zero Discharge):
This option includes the cost of installing a membrane
filter to reduce levels of TSS prior to deep well injection of
the produced water and the hardware associate; with the injection
system. It is assumed that the produced water is first treated
with BPT treatment (DAF or equivalent), but the cost of the BPT
treatment is not included in the implementation costs. The
capital and annual cost of a filtration/reinjection system over a
range of design flows is presented in Table XIII-18. Table XIII-
18 also presents the capital and annual cost to pipe the produced
water to shore for filtration/reinjection over a range of design
flows and assumptions used in deriving costs under specified
circumstances. Geographic area multipliers presented earlier in
Table XIII-10 were used to take into account the difference in
capital costs for oil production in areas other than the Gulf of
Mexico.
XIII-53
-------
TABLE XIII-17. COST FACTORS FOR HSPS MEMBRANE FILTRATION/SURFACE WATER DISCHARGE
TREATMENT SYSTEMS
1. Capital Coat
Flewratc (BPD)
Component
Chemical Feed /Storage
Filtration
Piping
Generator s
Sub-Totals :
Ins. « Bonding (4X)
TOTALS
200
54,000
64,500
17,775
38,142
174,417
6,977
181,394
1,000
54,000
115,500
25,425
45,856
240,781
9,631
250,412
5,000
1
54,000
256,500
46,575
49,285
406,360
16,234
422,614
10,000
54,000
310,500
54,675
55,285
474,460
18,978
493,438
40,000
72,000
564,000
95,400
87,856
852,026
32,770
852,026
2. Annual Coat
Flowrate (BPD)
Component
Labor
Maintenance
Chemicals
Energy
Sludge Disposal
TOTALS
200
32,800
5,442
65
1,200
5,500
45,007
1,000
32,800
7,512
320
3,300
12,700
56,632
5,000
32,800
12,678
1,600
5,900
56,000
108,978
10,000
32,800
14,803
3,200
7,800
108,900
167,303
40,000
32,800
25,561
12,800
12,000
424,000
507,161
3. Geographic Area Multiplier
Gulf of Mexico
Pacific Coaat
Atlantic
Alaska - Cook Inlet
Alaska - Other
1.0
1.6
1.6
2.0
3.5
4. Assume for Gulf Ib platforms in shallow water, four platforms combine effluent and treat at single
facility with appropriate capacity.
XIII-54
-------
d) Results
Spreadsheets were developed for regulatory options based on
»
the alternative technology costs. Table XIII-19 summarizes the
results of the analysis in terms of implementation costs and
contaminant removals for various regulatory scenarios using
membrane filtration.
The cost benefit analyses for the regulatory options are
presented in Table XIII-20 for NSPS in terms of number of
platforms affected, capital and annual compliance costs, and
annual pollutant removals.
XIII-55
-------
TABLE XIII-18. COST DATA FOR NSPS MEMBRANE FILTRATION/REINJECTION STSTEM
FOR PRODUCED WATER TREATMENT
1. Capital Coat Versus Flowrate
Flowrate (BPP)
Component
Chemical Feed/Storage
Filtration
Injection System
Generator*
Sub-Totals i
Ins. & Bonding (41)
TOTALS
2. Annual Cost Versus Flowrate
Component
Labor
Maintenance
Chemicals
Energy
Sludge Disposal
TOTALS
200 1,000 5,000 10,000
54,800 5 A, 800 54,800 54,800
64,500 115,500 256,500 310,500
68,600 109,000 139,100 228,300
38,142 45,856 49,285 55,285
225,242 325,156 498,885 648,085
9,010 13,006 19,955 25,923
234,252 338,162 518,840 674,008
Flowrate (BPD)
200 1,000 5,000 10,000
32,800 32,800 32,800 32,800
7,028 10,145 15,565 20,220
65 320 1,600 3,200
1,200 3,300 5,900 7,800
5,500 12,700 56,000 108,900
46,593 59,265 111,865 172,920
3. Assume 37Z of shallow wells would treat produced water onshore and reinject water onshore
and operating costs incurred tar such an approach would be as follows ( "Pipaline-to-Shore
average distance of formulas). Note - These costs were not revised from original onshore
costs.
a) Capital Cost of Onshore Filtration/Reinfection System
Component
Filter System
Reinjection System
Pipe-to-Shore
Chemical Feed /Storage
Generators
Sub-Total* l
Installation (302)
Engineering (10Z)
Contingency (151)
Insurance /Bonding (4Z)
Flowrate (BPD)
200 1,000 5,000 10,000
43,000 77,000 171,000 207,000
68,600 109,800 130,100 228,300
800,000 800,000 800,000 1,084,000
36,000 36,000 36,000 36,000
0 14,857 16,857 18,000
947,600 1,037,657 1,153,957 1,573,300
284,280 311,297 346,187 471,990
94,760 103,766 ' 115,396 157,330
142,140 155,649 173,094 235,995
37,904 41,506 46,158 62,932
40,000
72,000
564,000
527,900
87,856
1,251,756
50,070
1,301,826
40,000
32,800
39,055
12,800
12,000
424,000
520,655
. The capital
* cost based on
treatment
40,000
376,000
527,900
1,309,440
48,000
23,714
2,285,054
685,516
228,505
342,758
91,402
TOTALS
1,506,684 1,649,875 1,834,792 2.501,547 3,633,236
XIII-56
-------
TABLE Xlll-18. (Cont'd). COST DATA FOR NSPS MEMBRANE FILTRATION/REINJECTION SYSTEM
FOR PRODUCED WATER TREATMENT
b) Annual cost for Onshore Filtration/Rein lection System
Plowrate (BPD)
200 1,000 5,000 10,000 40,000
Component
Labor
Maintenance
Chemicals
Energy
32,800
45,201
19
343
32,800
49,496
91
943
32,800
55,044
457
1,686
32,800
75,046
914
2,229
32,800
108,997
3,657
3,429
TOTALS 78,363 89,330 89,987 110,989 148,883
4. Cost to Drill Offshore Inlection Well - Based on drilling a 3,500 foot deep well. Cost is on
regionized basis and is derived from API Drill Cost Survey
Well Cost (S)
Oil/Oil and Gas Gas Only
Alaska 1,174,145 811,825
Pacific 937,930 2,524,130
Gulf of Mexico 1,191,295 1,428,200
Atlantic 1,673,000 1,673,000
5. Cost to Drill Onshore In lection Well - Estimated at 155,000; based on API drill cost data
6. Coat to Convert Dry Hole to In lection Well - It is assumed that drill slots on model platforms that
are not used for production wells represent dry holes that can be converted to water injection wells;
cost is estimated at $240,000. (This does not agree with data in record - Vol. 17, Document E-27.)
7. Injection capacity of well is 6,000 BPD
XIII-57
-------
TABLE XIII-19. SUMMARY OF NSPS IMPLEMENTATION COSTS AND CONTAMINANT REMOVAL
FOR MEMBRANE FILTRATION SYSTEMS
t of Platforms
Pollutant Reduction (Ib/yr)
Capital Annual
Cost ($) Cost ($/yr) Conventional Metals Organics
Filter/Surface Water Discharge*
Shallow Water 393 104,874,421 22,108,417 6,599,182
Deep Water 458 195,979,287 39,689,145 20,804,900
All Facilities 851 300,853,708 61,717,562 27,404,083
141,781 311,935
531,058 1,013,579
672,839 1,325,514
Filtration/Reinlection*
Shallow Water
Deep Water
All Facilities
393
458
851
607,540,177
692,767,301
1,300,307,478
35,937,583
53,572,172
89,509,755
10,894,109
33,955,399
44,849,507
145,452 346,267
542,299 1,118,697
687,751 1,464,964
Filter/Reinlaet Onshore/Offshore for Shallow Wells*
Shallow Water 393 .643,480,443
Filter/Surface Water Discharge**
Wells < 4 Miles from Shore 162
Wells ~ 4 Miles from Shore 689
All Facilities 851
63,827,101
237,026,608
300,853,708
33,220,199
12,696,327
49,021,235
61,717,562
10,894,109 145,452 346,267
6,362,449
21,041,633
27,404,083
136,751 311,935
536,087 1,013,579
672,839 1,325,514
•Shallow water designation based on water depth at drill site.
XIII-58
-------
TABLE XIII-20
SUMMARY OF IMPLEMENTATION COSTS FOR MEMBRANE FILTER SYSTEMS
AND CONTAMINANT REMOVAL - NSPS
Pollutant Reduction (1b/yr)
#of
Platforms
X
H
H
H
Ul
VO
Filter Shallow/
BPT Deep
Reinject Shallow/
BPT Deep
Filter and Discharge All
Reinject Shallow/
Filter Deep
Reinject All
4 Mile/BPT Beyond
393
393
851
851
851
162
Capital
Cost ($)
104,874,421
607,540,177
300,853,708
803,519,464
1 ,300,307,478
63,827,101
Annual
Cost ($/yr)
22,108,417
35,937,583
61,717,562
75,626,728
89,509,755
12,696,327
Conventional
6,599,000
10,894,000
27,404,000
31 ,698,000
44,850,000
1 ,367,000
Metals
142,000
145,000
673,000
677,000
688,000
35,000
Organics
312,000
346,000
1 ,326,000
1 ,359,000
1 ,465,000
71,000
-------
SECTION XIV
NON-WATER QUALITY ENVIRONMENTAL IMPACTS
The elimination or reduction of one form of pollution may
aggravate other environmental problems. In recognition of this,
Sections 304(b) and 306 of the Act require the Agency to consider
the non-water quality environmental impacts (including energy
requirements) of certain regulations. In compliance with these
provisions, the Agency has considered the effect of these
regulations on air pollution, solid waste generation, water
scarcity, and energy consumption.
This section discusses the non-water quality environmental
impacts associated with the proposed regulations for each waste
stream, and also includes an analysis of safety related concerns.
A. ENERGY REQUIREMENTS AND AIR EMISSIONS
1. Drilling Waste
Zero discharge options which require drilling waste to be
transported to shore and disposed on land have an associated
energy consumption and result in air emissions of pollutants.
EPA performed an evaluation of these impacts.1 The method of
calculating energy consumption and associated air emissions is
patterned after the method used in the report "Water-Based
Drilling Fluids and Cuttings Disposal Study Update -
Calculations," January 1989.2 This report was prepared by Walk-
Haydel and submitted as part of API's 1988 comments. The report
used an EPA source to calculate air emissions associated with the
various types of equipment used to handle the waste.3
Sources of air pollution from offshore activities include
leaks, oil-water separators, dissolved air flotation units,
XIV-1
-------
painting apparatus, and storage tanks, but more significantly
diesel or gas engines for generating power, either on the
structures or for the purpose of transportation to and from the
structures.
»
For drilling fluids and drill cuttings, the only technology
under consideration that has significant energy consumption
impact is the use of barges to transport waste solids to shore
and land transportation for land disposal of these wastes.
The calculation method ascribed a fuel usage to each of the
activities associated with handling the drilling waste,
including:
Cranes to off-load waste from rig
• Supply boats to transport waste to shore
• Trucks to transport waste to disposal site
• Tractor/dozer to facilitate land disposal.
The calculation basis for Gulf, California, and Atlantic wells
was based on a 100-mile round trip between the drill platform and
the off-loading point. Trucking distance was assumed to be 40
miles per round trip. Factors for Alaska were developed for both
North and South Alaska and assumed significantly greater shipping
distances. Waste volumes of muds/cuttings requiring disposal
were derived from the report "Analysis of Implementation Cost and
Contaminant Removal - Drilling Waste," November 9, 1990, prepared
by ERCE.
Fuel requirements and air emissions associated with each
option are shown in Table XIV-1. Material barged for the
discharge options (5/3 All and 1/1 All) are those that would
XIV-2
-------
TABLE XIV-1
DRILLING WASTE FUEL REQUIREMENTS AND
AIR EMISSIONS ASSOCIATED WITH REGULATORY OPTIONS
OPTION
X
H
<
1
w
a
VoJUfflQ Of BtfQBQ
WiMt (10* bbl/yr)
Pint Requhemeiits
(bbtfyr)
Guff Emissions
(lons/yr)
CO
HC
NOx
8O2
Cftnf . Emissions
(tons/yr)
CO
HC
NOx
SO2
AlssKa Emissions
(tons/yr)
CO
HC
NOx
SO2
Atlantic Emissions
(tons/yr)
CO
HC
NOx
SO2
Total Emissions
(tons/yr)
Zero
kM^^MMlA
vcnvgv
8.190
818.029
850.0
286.0
3309.0
218.0
181.0
94.0
1092.0
71.0
89.0
26.0
296.0
18.0
21.0
9.0
116.0
8.0
6352
5/3
ALL
552.0
79.817
32.2
26.6
233.7
18.3
9.1
8.3
69.0
4.8
14.0
9.4
94.9
5.7 .
1.2
0.7
7.2
0.5
532
Zero Discharge Zero Discharge Zero Discharge
1/1 Within 4 Miles; Within 4 Miles; Shallow; 5/3
ALL 1/1 Beyond 5/3 Beyond Deep
652.0
79.817
32.2
26.6
233.7
18.3
9.1
8.3
69.0
4.8
14.0
9.4
94.9
5.7
1.2
0.7
7.2
0.5
532
1,596
173,360
49.8
69.0
472.6
30.7
30.8
45.4
313.8
20.2
14.0
9.4
94.9
5.7
1.2
0.7
7.2
0.5
1166
1.596
173,360
49.8
69.0
472.6
30.7
30.8
45.4.
313.8
20.2
14.0
9.4
94.9
5.7
1.2
0.7
7.2
0.5
1166
2,746
293.535
224.0
125.0
1397.0
91.2
16.4
11.9
11.2
7.3
84.8
13.6
145.0
8.8
1.2
0.7
7.2
0.5
2116
Zero Discharge
Shadow: 1/1
Deep
2,746
293,535
224.0
125.0
1397.0
91.2
16.4
11.9
11.2
7.3
54.8
13.6
145.0
8.8
1.2
0.7
7.2
0.5
2116
Source: 1
-------
normally require barging (i.e., do not comply with effluent
limits). As can be seen by the table, a zero discharge
requirement, whether applicable to some or all of these
structures, significantly increases the amount of barged material
and resulting fuel consumption and air emissions. However, the 4
mile options lessen these impacts considerably. Values for the
drilling wastes are representative of new sources only because of
the temporary nature of drilling activities.
An example of the detailed calculations for computing the
fuel requirements and air emissions for drilling waste
treatmentoptions is included in Appendix 2. Additional
calculations are included in this rulemaking's record.
Air emissions are calculated for sulfur dioxide (S02),
carbon dioxide (C02) , hydrocarbons (HC), and nitrogen oxides
(NOX) . These calculations are incremental to BPT and assume all
oil-based drilling fluids and drill cuttings have either been
substituted for or are being disposed of by shipment to land.
2. Produced Water
Energy requirements and air pollution associated with
produced water treatment were calculated using the same
methodology used by API in their comment submission.* The
methodology for calculation of energy requirements was considered
reasonable, and the API used EPA data for calculation of air
pollutant emissions associated with gas turbine operation. It
was assumed gas turbines were used to generate electricity to
power the produced water treatment equipment.
Two treatment scenarios were evaluated: filtration/surface
water discharge and filtration/reinjection. Both energy
requirements and associated air emissions are directly
XIV-4
-------
proportional to the volume of produced water requiring treatment.
Produced water rates were derived from the produced water
spreadsheets in the report "BAT and NSPS Analysis of
Implementation Cost and Contaminant Removal - Produced Water,"
11/15/90. The annual produced water rates are shown in Tables
XIV-2 and XIV-3.
Energy requirements for filtration/reinjection were based on
a 50 psi pressure drop across the filtration unit and an
injection pressure of 1800 psi with the energy derived from a
natural gas turbine. An 80% motor efficiency and a 20% energy
conversion efficiency were assumed. The same basis was used for
filtration/discharge; a pressure drop of 50 psi across the
filtration unit was assumed. A sample calculation for
determining energy requirements for produced waters is included
in Appendix 3.
Tables XIV-4 and XIV-5 present the regional energy
requirements in detail for each treatment option for BAT and
NSPS, respectively. As shown in these tables, a zero discharge
requirement based on filtration and reinjection greatly increases
air emissions. This is due primarily to the energy required of
reinjection equipment in order to pump fluids into formations.
Where options are listed involving filtration in Tables XIV-
4 and XIV-5, calculations were based on the use of granular media
filtration. However, the energy consumption required by the use
of membrane filtration, and thereby emissions also, is not
expected to differ significantly from that of granular media
filtration. This is because while the pressure drop across a
membrane filter is in the range of 20 to 30 psia6 (which is less
than that for granular media filtration), the energy required for
recirculation of the retentate will most likely make up for this
difference. At any rate, the energies consumed by either
XIV-5
-------
TABLE XIV-2
BAT - PRODUCED WATER FLOWRATES
1. Regional produced water rates with shallow water designation
based on water depth at drill site.
i
Water Rate fMMBBLS/Ym
Region Shallow Deep Total
Gulf of Mexico 277.003 594.511 866.514
Pacific 58.41 103.732 162.142
Alaska 0 0 0
i
Atlantic 0 0 0
Total 330.413 698.243 1028.656
2. Regional produced water rates with shallow water designation
based on distance from shore at drill site (<4 miles).
Water Rate fMMBBLS/YRl
Region
Gulf of Mexico
Pacific
Alaska
Atlantic
Total . 96.094 933.932 1030.026
Shallow
42.292
53.802
0
0
Deep
825.592
108.34
*
0
0
Total
867.884
162.142
0
0
XIV-6
-------
TABLE
NSPS - PRODUCED WATER FLOWRATES
1. Regional produced water rates with shallow water designation
based on water depth at drill site.
Water Rate fMMBBLS/YRl
Region Shallow Deep Total
Gulf of Mexico 150.472 258.091 408.563
Pacific 14.019 330.054 344.073
Alaska 35.532 9.287 44.819
Atlantic 0 15.012 15.012
Total 200.023 612.444 812.467
2. Regional produced water rates with shallow water designation
based on distance from shore at drill site (<4 miles).
Water Rate fMMBBLS/YRI
Region Shallow Deep Total
Gulf of Mexico 40.695 368.028 408.723
Pacific 114.400 229.593 343.993
Alaska 35.532 9.287 44.819
Atlantic 0 15.012 15.012
Total 190.627 621.84 812.467
XIV-7
-------
TABLE XIV-4
BAT - NATURAL GAS ENERGY REQUIREMENTS
FOR PRODUCED HATER TREATMENT
1. Energy requirements with well designation based on water
depth at drill site.
Energy Requirements (109 scf/yr)
Filtration/Discharge Filtration/Reinjection
Region (shallow/deep/totali /shallow/deeo/total1
Gulf of Mexico .0907.191/.281 3.32/7.08/10.40
California .019/.033/.052 0.70/1.25/1.95
Alaska 0/0/0 0/0/0
Atlantic 0/0/0 0/0/0
Total .109/.224/.333 4.02/8.33/12.35
2. Energy requirements with well designation based on distance
from shore at drill site.
Energy Requirement (109 scf/yr)
Filtration/Discharge Filtration/Reinjection
Region (<4miles/>4miles/total\ (<4miles/>4miles/total\
Gulf of Mexico .014/.268/.282 0.51/9.92/10.43
California .017/.035/.052 0.65/1.30/1.95
Alaska 0/0/0 0/0/0
Atlantic 0/0/0 0/0/0
Total .031/.303/.334 1.16/11.22/12.38
Source: 1
XIV-8
-------
TABLE XIV-5
NSPS - NATURAL GAS REQUIREMENTS
FOR PRODUCED WATER TREATMENT
1. Energy requirements with well designation based on water
depth at drill site.
Energy Requirements (109 scf/yr)
Filtration/Discharge Filtration/Reinjection
Region (shallow/deep/total) (shallow/deep/total)
Gulf of Mexico .0497.083/.132 1.81/3.10/4.91
California .005/.107/.112 0.17/3.96/4.13
Alaska .012/.003/.015 0.43/0.11/0.54
Atlantic 0 /.005/.005 0 /O.18/0.18
Total .066/.198/.264 2.41/7.35/9.76
2. Energy requirements with well designation based on distance
from shore at drill site.
Energy Requirement (109 scf/yr)
Filtration/Discharge Filtration/Reinjection
Region f<4miles/>4miles/total> I<4miles/>4miles/total)
Gulf of Mexico .011/.102/.113 0.49/4.42/4.91
California .037/.075/.112 1.37/2.76/4.13
Alaska .Q12/.003/.015 0.43/0.11/0.54
Atlantic 0 /.005/.005 0 /O.18/0.18
Total .060/.185/.245 2.29/7.47/9.76
Source: 1
XIV-9
-------
filtration method are overshadowed by the energy required for
injection.
The following factors were used to calculate air emissions:3
»
Emission Factor
Parameter ftons/vr per 109 scf 1
Particulates 7.016
NOX 206.5
C02 57.5
HC 21.0
SOX 0.33
Using these emission factors and the energy consumption rates
presented in Tables XIV-4 and XIV-5, air pollution emission rates
for regulatory options were estimated.
The impact of the regulatory options on air emissions rates
is presented in detail in Tables XIV-6 through XIV-11, according
to each option. As shown, the 4 Mile/BPT Beyond option requires
the least amount of energy and, thus, produces the least amount
of emissions. A summary of both emissions and fuel requirements
for each regulatory option is given in Table XIV-12.
3. 6 and 8 Mile Regulatory Options
EPA performed a preliminary analysis which compared
environmental impacts associated with the 4, 6, and 8 mile
options for both drilling wastes and produced waters. EPA
concluded from this preliminary analysis that the 6 and 8 mile
options are not appropriate and, thus, were eliminated from
further consideration early in EPA's regulatory
optionsdevelopment. This preliminary analysis is discussed
further below.
XIV-10
-------
TABLE XIV-6
OPTION A AIR EMISSIONS FOR PRODUCED WATER
Shallow Wells - Filter/Discharge
Deep Wells - BPT
Emission Rates (tons/yr)
BAT
Gulf of Mexico
California
Alaska
Atlantic
TOTAL
NSPS
Gulf of Mexico
California
Alaska
Atlantic
TOTAL
Participates NOX
C02
SOX
0.64
0.13
0
0
0.77
Particulates
0.35
0.04
0.09
0
0.48
19
4.0
0
0
23
NOX
10
1.0
2.5
0
13.5
5.1
1.1
0
0
6.2
GRAND
C02
2.8
0.3
0.7
0
3.8
1.9
0.4
0
0
2.3
TOTAL -
H£
1.0
0.1
0.2
0
1.3
0.03
0.01
0
0
0.04
32.31
SOX
0.016
0.002
0.004
0
0.022
GRAND TOTAL - 19.10
Source: 1
XIV-11
-------
TABLE XIV-7
OPTION B AIR EMISSIONS FOR PRODUCED WATER
Shallow Wells - Zero Discharge (Filtration/Reinjection)
Deep Wells - BPT
Emission Rates (tons/yr)
BAT Participates NOX C02 HC SOX
Gulf of Mexico 23 686 191 70 1.1
California 5 144 40 15 0.23
Alaska 0 0 0 00
Atlantic 0 0000
TOTAL 28 830 231 85 1.3
GRAND TOTAL » 1175.30
NSPS Particulates NOX C02 -HC
Gulf of Mexico 13 373 104 38 0.59
California 1.2 35 10 3.6 0.6
Alaska 3.0 89 25 8.8 0.14
Atlantic 0 0000
TOTAL 17.2 497 139 50 0.79
GRAND TOTAL - 703.99
Source: 1
XIV-12
-------
TABLE XIV-8
AIR EMISSIONS FOR PRODUCED WATER
TREATMENT FOR FILTRATION/DISCHARGE ALL OPTION
Emission Rates (tons/yr)
BAT
Gulf of Mexico
California
Alaska '
Atlantic
TOTAL
Particulates NOX
2.0
0.36
0
0
2.3
NSPS
Gulf of Mexico
California
Alaska
Atlantic
TOTAL
Particulates NOX
0.93
0.79
0.11
0.03
1.85
C02
HC
SOX
58
11
0
0
69
16
3.0
0
0
19
5.9
1.1
0
0
7.0
0.09
0.02
0
0
0.11
Grand Total: 97.41
SOX
27
23
3.1
1.0
55
7.6
6.4
0.9
0.3
15
2.8
2.4
0.3
0.1
5.5
0.044
0.037
0.005
0.002
0.09
•Grand Total: 77.44
Source:
XIV-13
-------
TABLE XIV-9
OPTION D AIR EMISSIONS FOR PRODUCED WATER TREATMENT
Shallow Water Structures - Zero Discharge
•
Deep Water Structures - Filter/Discharge
BAT
Gulf of Mexico
California
Alaska
Atlantic
TOTAL
NSPS
Gulf of Mexico
California
Alaska
Atlantic
TOTAL
Emission Rates (tons/yr)
Particulates NOX
C02
fiC
SOX
13
1.9
0
0
15
391
57
0
0
448
109
16
0
0
125
40
5.8
0
0
46
0.62
0.09
0
0
0.71
GRAND TOTAL •= 1239.55
Particulates NOX
C02 HC SOX
4.2
10
3.0
0.03
17
122
298
89
1.0
510
34
83
25
0.3
142
12
30
9.1
0.1
51
0.19
0.48
0.14
0.001
0.81
GRAND TOTAL «= 720.81
Source:
XIV-14
-------
TABLE XIV-10
AIR EMISSIONS FOR PRODUCED WATER
TREATMENT FOR FILTRATION/REINJECTION ALL OPTION
Emission Rates (t'ons/yr)
BAT Particulates NOX C02 HC SOX
Gulf of Mexico 73 2149 598 218 3.4
California 14 402 112 41 0.64
Alaska 0 0000
Atlantic 0 0000
TOTAL 87 2551 710 259 4.0
Grand Total: 3611.0
NSPS Particulates NOX C02 HC SOX
Gulf of Mexico 34 1013 282 103 1.6
California 29 853 238 87 1.4
Alaska 3.8 111 31 11 0.18
Atlantic 1.3 37 10 3.8 0.06
TOTAL 69 2015 561 205 3.2
Grand Total: 2853.2
Source: 1
XIV-15
-------
TABLE XIV-11
AIR EMISSIONS FOR PRODUCED HATER TREATMENT
< 4 MILES - FILTRATION/DISCHARGE
> 4 MILES - BPT
Emission Rates (tons/yr)
BAT
Particulates NOX
C02
Gulf of Mexico
California
Alaska
Atlantic
TOTAL
NSPS
Gulf of Mexico
California
Alaska
Atlantic
TOTAL
SOX
.098
.119
0
0
.217
Particulates
.077
.260
.084
0
.042
2.9
3.5
0
'0
6.4
NOX
2.3
7.6
3.4
0
13.3
.63
.77
0
0
1.44
Grand
C02
.81
2.71
.68
0
4.40
.29
.36
0
0
.65
Totals
££
.23
.78
.25
0
1.26
.005
.006
0
0
.011
8.72
SOX
.004
.012
.004
0
.020
Grand Totals 19.02
Sources 1
XIV-16
-------
TABLE XIV-12
NON-WATER QUALITY ENVIRONMENTAL IMPACTS FOR PRODUCED WATERS
REGULATORY OPTIONS*
Fuel Requirements
(109 Bcf/year)
Zero Discharge
Within 4 Miles/
BPT Beyond
0.031
0.06
Total Emissions
(tons/year)
Option
Filter Shallow/
BPT Deep
Zero Discharge
Shallow/BPT Deep
Filter and Dis-
charge All
Zero Discharge
Shallow/Filter
Deep
Zero Discharge All
BAT
0.109
4.02
0.333
4.24
12.35
NSPS
0.066
2.41
0.264
2.608
9.76
BAT
32.31
1175.30
97.41
1239.55
3611.00
NSPS
19.10
703.99
77.44
720.81
2853.20
8.72
19.02
*Assuming an "unconstrained" industrial growth profile.
XIV-17
-------
a) Drilling Wastes
The 6 and 8 mile options associated with drilling wastes are
the same as those for the 4 mile option except that the distance
criterion is 6 or 8 miles: facilities located 6 (or 8) miles or
less from shore are subject to zero discharge of drilling wastes;
facilities located outside of 6 (or 8) miles are subject to
discharge limitations for toxicity and cadmium and mercury, and
no discharge of diesel oil and free oil.
Fuel consumption and emissions calculations were developed
for the following zero discharge cases (calculations for
discharges outside of these mile boundaries were not included):5
Wells within 4 miles of the coast
• Wells within 6 miles of the coast
• Wells within 8 miles of the coast
The major differences between these new cases and the zero
discharge scenario involve the number of wells drilled and the
length of the supply boat trip. The calculations assume that the
percentage of wells within 4, 6, and 8 miles of the coast are
10%, 11%, and 19%, respectively.7 Also, these calculations
assume that the average well drilled within 4 to 8 miles from the
coast requires a boat run of 50 miles instead of 100 miles.
All of the fuel consumption and emission calculations follow
the methodology used in the 1989 Walk, Haydel report, entitled
"Water-based Drilling Fluids and Cuttings Disposal Study
Update."2
XIV-18
-------
Table XIV-13 gives a summary of these calculations. A
significant decrease in impacts is evident between the 8 mile and
4 mile options. However, a negligible difference is evident
between the 4 mile and 6 mile options. EPA prefers the 4 mile
option because it significantly reduced impacts from the 8 mile
option, while differences between the 4 and 6 mile options are
insignificant.
b) Produced Waters
A preliminary analysis was also performed to determine the
energy requirements and air pollution associated with produced
water treatment for the 4, 6, and 8 mile options.8 These options
require granular media filtration and discharge within 4, 6, or 8
miles and BPT beyond 4, 6, or 8 miles. Values were calculated
using the same methodology as used by API in their
commentsubmission (walk, Haydel reports attached to API comments,
Report No. 12 and 13, Volume 54 of record). The methodology for
calculation of energy requirements was considered reasonable and
the API used EPA data for calculation of pollutants associated
with gas turbine operation.
Two BAT/NSPS treatment options were evaluated: filtration/
surface water discharge and filtration/reinjection. Produced
water rates are the same as those in Tables XIV-2 and XIV-3.
Energy requirements for reinjection were based on an injection
pressure of 1800 psi and the energy derived from a natural gas
turbine. An 80% motor efficiency and a 20% energy conversion
efficiency were assumed. The same basis was used for filtration
but pressurization to 50 psi was assumed.
Table XIV-14 presents the energy requirements and air
pollution emissions associated with the turbine operation for
each 4, 6, and 8 mile option. The same factors used to
XIV-19
-------
TABLE XIV-13
FUEL REQUIREMENTS AND AIR EMISSIONS ASSOCIATED WITH
THE 4,6, AND 8 MILE DRILLING HASTE OPTIONS
Air Emission .Fuel Requirements
Option (tons/yr) (bbl/yr)
Zero Discharge
Within 4 Miles 477 72,550
Zero Discharge
Within 6 Miles 528 79,213
Zero Discharge
Within 8 Miles 909 136,217
Sources 5
XIV-20
-------
TABLE XXV-14
COMPARISON OF FUEL REQUIREMENTS AND AIR EMISSIONS
FOR THE 4, 6, AND 8 MILE OPTIONS FOR PRODUCED WATERS
Air Emission
(tons/yr)
Filtration Within
4 Miles; BPT Beyond 4.08 3.23
Filtration Within
6 Miles; BPT Beyond 7.09 5.637
Filtration Within
8 Miles; BPT Beyond 14.09 11.173
Natural Gas
Requirements
(109 scf/yr)
Option
BAT
NSPS
BAT
NSPS
0.014
0.025
0.049
0,0143
0.0143
0.021
Source: 8
XIV-21
-------
calculate air emissions for the other produced water options (see-
Section XIV.A.2) are used in these calculations.
As can be seen from this table, the difference between the
impacts from the 4 and 8 mile options is generally 3-1/2 times
larger for the 8 mile option than it is for 4 miles. The
difference between the 4 and 6 mile options is much less. Thus,
EPA prefers the 4 mile option over the 6 and 8 mile options for
the same reasons as evidenced for the drilling waste options.
4. Constrained vs. Unconstrained Growth Scenarios
All calculations for energy requirements and air emissions
were performed assuming an unrestricted (unconstrained)
industrial growth pattern for offshore oil and gas extraction
facilities (see Section III). The constrained (or reduced)
industrial growth scenario was developed to account for the
presidential moratorium on oil and gas leasing and development
off California and in the North Atlantic. Thus, the
unconstrained scenario is changed to reflect this by assuming no
new offshore platforms in California state and federal waters or
in the Atlantic and the emissions and fuel requirements for the
California and Atlantic regions are subtracted from the totals
developed for the unconstrained scenarios.
For drilling fluids, the decrease in impacts for the Zero
Discharge All option when eliminating all California and Alaska
structures, is approximately 25%, or 4760 tons/yr of emissions
(instead of 6352), and 613,522 bbl/yr of fuel required instead of
818,029. A minor reduction is evidenced by the elimination of
these structures when evaluating the Zero Discharge Shallow
Structures options. The decrease in impacts is only 3%. This is
because most of the structures in California and the Atlantic are
XIV-22
-------
in deep waters and their contribution even in the unconstrained .-
scenario due to zero discharge in shallow waters is minimal.
Subtracting contributions of emissions and fuel requirements
for the California and Atlantic regions from the impact estimates
results in a wider range of percent reductions for the produced
water regulatory options than for drilling wastes. This is
because the impacts associated with controls in deep waters
contribute more to the total impacts for produced water than for
drilling fluids. Thus, eliminating California and Atlantic
facilities (mostly deep water facilities) from shallow water
options may have a significant or minimal effect depending on the
controls required in deep waters. For example, a minimal percent
decrease in impacts, 7-8%, is evidenced for the Shallow Water
(either Discharge or Zero Discharge)/BPT Beyond options when
these facilities are excluded. However, a larger decrease
results, 59%, when considering the Zero Discharge Shallow/Filter
and Discharge Deep option. This is because California structures
located in deep waters significantly contribute to the impacts
associated with the filter and discharge technology.
Whatever the option, it is obvious that impacts will be
reduced should the constrained scenario more accurately reflect
the future growth of the oil and gas industry. The potential for
reduction may average some 20% for drilling fluids and 37% for
produced waters across all options considered.
B. SOLID WASTE GENERATION
Although the regulatory options will not generate additional
solids, some of the options (particularly those requiring zero
discharge for drilling fluids and cuttings) would require
disposal of solid wastes. EPA conducted a study to determine the
availability of land disposal sites should a zero discharge
XIV-23
-------
requirement be imposed. Estimates of drilling waste requiring
onshore disposal are as follows:
ONSHORE DISPOSAL OF OFFSHORE DRILLING WASTE*
Shallow/Deep Zero Discharge
El
Region
Gulf of Mexico
California
Alaska
EPA
Data Base
2,484
174
71
Revised
API Data
7,025
712
345
EPA
Data Base
6,004
1,734
93
Revised
API Data
16,978
7,092
452
*Thousands of barrels per year
The range of waste volumes is due to the difference in the
two data sets used.
The available onshore disposal capacity in the Gulf of
Mexico region, California, and Alaska was estimated based on data
from earlier studies and discussions with individuals familiar
with local disposal options. The situation in each region is as
follows:
Gulf of Mexico - Disposal facilities in the Gulf can be
classified into three categories: facilities permitted to accept
nonhazardous muds/cuttings that are currently processing offshore
waste; facilities permitted to accept nonhazardous muds/cuttings
but that currently do not process offshore wastes, as the
combined transportation/disposal cost would be higher than that
charged by firms in the first category; and hazardous waste
treatment/disposal facilities. The facilities permitted for
nonhazardous muds/cuttings disposal have adequate capacity to
handle the volume of waste requiring onshore disposal (30.7 MM
BBLS/yr combined capacity). During any transition period needed
to gear up underutilized or unutilized facilities, hazardous
waste disposal sites could handle the excess.
XIV-24
-------
California - In California, there are two options for
onshore disposal of offshore drilling wastes: 1) if nonhazardous,
treatment by stabilization and disposed in a Class III
(nonhazardous) landfill; and 2) disposal at a Class I hazardous
waste landfill as either a hazardous or nonhazardous waste.
The available disposal capacity of these two landfill types
is 7.48 MM BBLS/yr which is greater than the highest projected
waste generation rate. The capacity of facilities employing
stabilization/Class III disposal is estimated at 3.4 MM BBLS/yr.
This capacity is sufficient for all but the "zero discharge" case
using the higher industry estimate of waste volume per well. It
is reasonable to assume, however, that stabilization capacity
would expand to meet the demand, as the cost is significantly
lower than disposal at a Class I hazardous disposal facility.
Alaska - There are currently no permitted commercial
facilities accepting offshore drilling waste for onshore
disposal. There also does not appear to be any offshore drilling
waste which requires onshore disposal in Alaska. Should offshore
wastes require onshore disposal, options exist for permitting
environmentally safe onshore disposal facilities. These
facilities could be either onshore pits, permitted by the
offshore operator under the same restrictions as applied to
onshore drilling operators, or commercial facilities that are
permitted to dispose of oily waste on land.
As the information illustrates, approximately 8 million
barrels per year of drilling fluids and drill cuttings would
require disposal under a zero discharge condition for all
structures. The information further estimates a projected 42
million barrels per year in available land disposal capacity for
drilling wastes.9 Thus, land capacity is projected to support a
XIV-25
-------
zero discharge requirement. However, the 8 million barrels per .
year is a substantial portion of the existing capacity
(approximately 15 million barrels per year).
Table XIV-12 also indicates that the Agency's preferred
regulatory option (4 Mile; 1/1 Beyond) would require the
transport of approximately 1.6 million barrels per year of
drilling waste to shore for disposal. This represents less than
0.5 percent of the volume of all the drilling wastes (coastal,
onshore and offshore combined) that are generated and disposed
onshore. Furthermore, this amount represents only 3.5 percent of
the 42 million barrels per year of available land disposal
capacity.
Those drilling wastes that are generated offshore and
transported to shore for disposal under the preferred option
would be deposited in land disposal units similar to those used
to manage a portion of onshore-generated drilling wastes. These
land disposal units would generally be located relatively near
the coast where the wastes are brought to shore. While there are
currently no federal requirements for the onshore disposal of
drilling wastes under the Resource Conservation and Recovery Act
("RCRA") (see EPA's "Regulatory Determination for Oil and Gas
Geothermal Exploration, Development and Production Wastes" at 53
FR 25446), there are existing State program requirements in the
Gulf Coast and California Coast areas where the wastes would be
brought to shore. EPA is developing a tailored program for the
management of exploration and production wastes under RCRA
Subtitle D.
XIV-26
-------
C. CONSUMPTIVE WATER LOSS
Since no water is added to any of the unit operations, no
consumptive water loss is expected as a result of the proposed
regulations.10
D. SAFETY
The industry claims that injuries and fatalities due to
hauling additional volumes of muds/cuttings to shore would
increase. Based upon available information, it is likely that
the number of accidents would increase if the volume of waste
transported to shore increased. However, it is difficult to
determine quantitatively the increase in accidents and fatalities
due to lack of data.
Industry comments that statistics show the number of crane-
related injuries is significant in offshore drilling and
production operations. By requiring drilling wastes to be
disposed onshore, the number of injuries or deaths related to
crane usage would increase. One of several estimates shows
crane-related accident incidents to increase 6% per year.11
However, in comparison with other industries such as oil and gas
field services, construction, and general water transportation, a
6% increase would still keep the amount of incidents for oil and
gas extraction operations considerably lower than these other
industries (see Table XIV-15).
E. UNDERGROUND INJECTION OF PRODUCED WATER
EPA's Office of Solid Waste conducted a study on the impact
of disposal of produced water in injection wells and found that
injection wells used for the disposal of produced water have the
potential to degrade fresh groundwater in the vicinity if they
XIV-27
-------
TABLE XIV-15
INJURIES AND ILLNESS CASES
PER 100 FULL-TIME WORKERS
Industry 1984 1985 1986 1987
Oil and Gas Field Services* 15.2 15.8 13.4 14.0
Oil and Gas Extraction* 11.8 10.1 8.1 8.3
Construction
General Building 15.4 15.2 14.9 14.2
Heavy Construction 14.9 14.5 14.7 14.5
Special Trade 15.8 ' 15.4 15.6 15.0
Manufacturing 10.6 10.4 10.6 11.9
Lumber and Wood Products 19.6 18.5 18.9 18.9
Transportation 8.7 8.4 8.2 8.4
Water Transportation 13.2 13.0 12.7 12.9
*A11 but 0.1-0.2 of cases due to injuries for oil and gas
industry. Seems to be consistent in other industries as well.
Source: 11
XIV-28
-------
are inadequately designed, constructed, or operated.12 Highly
mobile chloride ions can migrate into freshwater aquifers through
corrosion holes in injection tubing, casing, and cement.
However, tight controls exist for injection practices to mitigate
*
these potential problems. The federal Underground Injection
Control (UIC) program requires mechanical integrity testing of
all Class II injection wells every 5 years. All states meet this
requirement, although some states have requirements for more
frequent testing.
Many states have primacy for the UIC program. Both the
criteria used for passing or failing an integrity test for a
Class II well and the testing procedure itself can vary. There
is considerable variation in the actual construction of Class II
wells in operation nationwide, both because many wells in
operation today were constructed prior to the enactment of
current programs and because current state programs vary
significantly. State requirements for new injection wells can be
quite extensive. However, state requirements for construction of
injection wells prior to the enactment of the UIC program have
evolved over time, and construction ranges from injection wells
in which all groundwater zones are fully protected with casing
and cementing to shallow injection wells with one casing string
and little or no cement.12
As discussed in Section VI, EPA also evaluated the
conditions along the U.S. coast to determine technical factors
which would preclude injection brine produced by offshore oil and
gas operations.13 The report concluded that, in general, brine
reinjection is technically feasible in all coastal and offshore
areas of the U.S. However, exceptions to reinjection may be
necessary because of possible contamination of underground
drinking water sources, potential seismic activity, and unknown
geologic areas.
XIV-29
-------
F. REFERENCES
1. Memo from Peter Crampton, ERCE, to Offshore Oil and Gas
File, "Estimate of Fuel Requirements and Air Emissions
Associated With BAT/NSPS Options," Dec. .18, 1990.
2. Walk, Haydel and Associates, "Water-based Drilling Fluids
and Cuttings Disposal Study Update, January 1989, p. 105.
3. EPA Compilation of Air Pollutant Emission Factors, AP-42,
Supplement 15, January 1984.
4. Walk-Haydel and Associates, reports attached to API
Comments, Report Nos. 12 and 13, Volume 54, of Record.
5. Memo from Kyle Webb, ERCE, to Marvin Rubin, EPA, "Fuel
Requirements and Emissions Generated in Connection with
Onshore Disposal of Muds and Cuttings," July 25, 1990.
6. Goodboy, Kenneth P., "Operational Results of Cross-Flow
Microfiltration for Produced and Sea Water Injection",
Scotland, November 1, 1989.
7. Letter from Maureen F. Kaplan, ERG, Inc., to Marvin Rubin,
EPA, July 19, 1990.
8. Memo from Peter Crampton, ERCE, to Marvin Rubin, EPA,
"Energy Requirements and Air Pollution Associated with
Produced Water Treatment Options," June 11, 1990.
9. ERCE, Onshore Disposal of Offshore Drilling Waste - Capacity
and Cost of Onshore Disposal Facilities. March 1991.
10. Proposed Development Document for Effluent Limitations
Guidelines and Standards for the Offshore Segment of the Oil
and Gas Extraction Point Source Category, July 1985, pp.
280-282.
11. ERCE, "Comparison of Safety Information - Onshore Oil and
Gas versus Other Industries," March 1991.
12. U.S. EPA-OSW, "Report to Congress - Management of Wastes
from the Exploration, Development, and Production of Natural
Gas and Geothermal Energy, Executive Summary, December 1987,
pp 12-13.
13. ERCE, "An Evaluation of Technical Exceptions for Brine
Reinjection for the Offshore Oil and Gas Industry," March
1991.
XIV-30
-------
SECTION XV
BEST AVAILABLE TECHNOLOGY OPTIONS SELECTION
A. BAT EFFLUENT LIMITATIONS GUIDELINES
After analysis of technical feasibility, pollution reduction
capability, costs, and non-water-quality impacts, EPA has
selected a preferred regulatory option for each offshore oil and
gas waste stream. All options considered for regulatory control
are presented in Section XI. The focus of BAT limitations is on
removal of toxics and nonconventionals instead of conventionals.
The cost analysis and benefits from pollutant removal may result
in control options other than those chosen as appropriate for
BCT. Table XV-1 presents the BAT effluent limitations guidelines
associated with the options preferred by EPA. The discussions
that follow place particular emphasis on control of toxic
pollutants. Reasons for not selecting certain options are
discussed in this section also.
B. DRILLING FLUIDS AND DRILL CUTTINGS
1. Options Considered
All the options listed in Section XI were considered for BAT
for drilling wastes except the last two, which involve
combinations of zero discharge and BPT. The discharge options
which include limitations for cadmium, mercury, toxicity, and no
discharge of diesel oil and free oil are directed primarily at
limiting toxic pollutants where discharges are allowed.
The 5/3 All Structures option includes four requirements:
1) toxicity limitation set at 30,000 ppm in the suspended
particulate phase; 2) a prohibition on the discharge of diesel
oil used either for lubricity or spotting purposes; 3) no
discharge of free oil based on the Static Sheen test, and 4)
XV-1
-------
Waste Source
TABLE XV-1
PROPOSED BAT EFFLUENT LIMITATIONS GUIDELINES
BAT Effluent Limitations
BAT Effluent
Pollutant Parameter Limitation
Produced water
A) For facilities
located 4 miles
offshore or less
Oil & grease
B) For facilities
located more
than 4 miles
offshore
Drilling fluids
and cuttings
A) For facilities
located 4 miles
offshore or less
B) For facilities
located mor
than 4
offshore
Oil & grease
Toxicity
Free oil
Diesel oil
Mercury
Cadmium
Well treatment
completion, and
workover fluids
The maximum for any
one day shall not
exceed 13 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 7 mg/L
The maximum for any
one day shall not
exceed 72 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 48 mg/L
No discharge
Minimum 96-hour
LC50 of the SPP
shall be 3% by
volume
No discharge*
No discharge in
detectable amounts
1 mg/kg dry weight
maximum in the
whole drilling fluid
1 mg/kg dry weight
maximum in the
whole drilling fluid
Zero discharge of
fluids slug plus
100-barrel buffer,
on either side
XV-2
-------
TABLE XV-1 (Continued)
PROPOSED BAT EFFLUENT LIMITATIONS GUIDELINES
BAT Effluent Limitations
Waste Source
Pollutant Parameter
BAT Effluent
Limitation
Deck Drainage
(during production)
A) For facilities
located 4 miles
offshore or less
Oil & grease
B) For facilities
located more
than 4 miles
offshore
Deck drainage
(during drilling)
Produced sand
Sanitary M10
Sanitary M91M
Domestic Waste
Oil & grease
Free oil
The maximum for any
one day shall not
exceed 13 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 7 mg/L
The maximum for any
one day shall not
exceed 72 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 48 mg/L
No discharge
Zero discharge
None
None
None
* Based on Static Sheen Test
XV-3
-------
limitations for cadmium and mercury set in the stock barite at 5-
mg/kg and 3 mg/kg, respectively. These requirements are to be
met by all offshore structures regardless of the depth of the
water in which they are located.
t
The discharge prohibitions on diesel oil and free oil will
serve as "indicators" of toxic pollutants. The discharge of
diesel oil, either as a component in an oil-based drilling fluid
or as an additive to a water-based drilling fluid, would be
prohibited under this option. 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 use mineral oil instead of diesel oil for lubricity and
spotting purposes. Mineral oil is a less toxic alternative to
diesel oil and is available to serve the same operational
requirements. Low toxicity mineral oils are also available as
substitutes for diesel oil and continue to be developed for use
in drilling fluids. Free oil is proposed to-be used as an
"indicator" pollutant for control of priority pollutants also,
including benzene, toluene, ethylbenzene, and naphthalene.
The purpose of the toxicity limitation for any drilling
fluids which are to be discharged is to encourage the use of
generic or water-based drilling fluids and the use of low-
toxicity drilling fluid additives (i.e., product substitution)
(see Sections VII and VIII). Where the toxicity of the spent mud
system exceeds the LC50 toxicity limitation, the method of
compliance with this option would be to transport the spent fluid
system to shore for either reconditioning for reuse or land
disposal.
The toxicity limitation would apply to any periodic blowdown
of drilling fluid as well as to bulk discharges of drilling fluid
XV-4
-------
systems. The term "drilling fluid systems" refers to the major
types of muds 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 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 1,000 to 2,000
barrels of spent drilling fluids occur when such mud 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, four such
determinations 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% of actual well footage (not total vertical depth) has
been drilled and up to an 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, e.g., if the
bioassay test is failed, the operator could then anticipate and
plan for transport of the spent drilling fluid system to shore in
order to comply with the effluent limitation. However, the
operator is not precluded from discharging a spent mud system
XV-5
-------
prior to receiving analytical results. Nonetheless, the operator
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 at any time.
Cadmium and mercury would be regulated at a level of 5 and 3
mg/kg, respectively, in the stock barite. Note: this is not an
effluent limit to be measured at the point of discharge but a
standard pertaining to barite composition. These two toxic
metals would be regulated to control the metals content of the
barite component of any drilling fluid discharges. The method of
compliance with these limitations is also product substitution.
This involves use of barite from sources that either do not
contain these metals or contain the metals at low enough levels
such that resultant levels in discharges of the drilling fluid do
not exceed the limitations.
The causes for noncompliance with the specific requirements
of this option could include: inability to use a drilling fluid
that can meet the proposed toxicity limitation, such as the need
for an oil-based mud or a potassium/polymer mud with oil
additives because of operational reasons; the need to add
lubricity agents or other specialty additives to a mud system to
meet particular operational requirements; or the unavailability
of barite containing low toxic metals levels.
As previously noted, BPT effectively prohibits the discharge
of oil-based drilling fluids, and less toxic water-based fluids
are available substitutes. Although the potassium/polymer mud
represents the most toxic water-based fluid allowed for
discharge, it is seldom used for offshore drilling purposes.
XV-6
-------
It is also recognized that the availability of barite stocks
containing low levels of trace metals could be limited at any
given time due to market conditions. However, the Agency
investigated the availability of "clean barite" and estimated
that sufficient sources of such barite do exist and can be
directed to offshore drilling use in those cases where an
operator intends to discharge drilling fluids (see Section XVII).
Mineral oil is an available alternative to diesel oil for
use as a lubricant or spotting fluid. Although there are
specialty additives for which less toxic substitutes have not
been identified, the toxicity limitation is applied to the
discharge of the entire drilling fluid system and not to
individual components.
The Agency has considered the costs of product substitution
and finds them to be acceptable for this industry, resulting in
no barrier to future entry. These standards are not expected to
have any adverse non-water quality environmental impacts or
appreciably increase energy requirements.
Thus, the Agency believes that only a limited number of
offshore drilling operations would not be allowed to discharge
spent drilling fluids due to violation of one or more of the
requirements of this option.
The 1/1 All Structures option includes the same four
requirements as the 5/3 All option except for the cadmium and
mercury limitations. The cadmium and mercury limits are based on
their concentrations in the drilling fluids, as opposed to the
5/3 All option where the limits are based on their concentration
in the stock barite. Compliance is based upon the use of "clean"
stock barite which has been costed for use by the industry and
XV-7
-------
are to be met by all offshore structures regardless of the depth -
of the water in which they are located.
In addition to the discharge limitations options for all
structures, a zero discharge requirement is listed as an option,
either for all structures or for portions of the industry. Zero
discharge is included as a BAT option in order to eliminate the
discharge of toxic pollutants.
Note: Three options for drilling fluids and cuttings were
proposed in 1985. The new options, 5/3 All and Zero Discharge
All, are the same as two of those proposed in 1985. The third
option proposed in 1985 was the "clearinghouse" approach. This
option was not considered appropriate for reasons discussed in
Section IX.B.
2. Options Selection
EPA has selected the 4 Mile - 1/1 Beyond option as a basis
for BAT effluent limitations for drilling fluids and cuttings.
Selection of this option is based on the same consideration of
non-water quality environmental impacts that are summarized in
the section of this document describing the BCT options selection
(Section XII). This option proposes zero discharge by barging
for new wells drilled at a distance from shore of 4 miles or
less. New wells drilled at a distance of greater than 4 miles
would be allowed to discharge after meeting requirements for
toxicity, cadmium adn mercury at 1/1 mg/kg, no static sheen, and
no discharge of diesel oil. However, for the Alaska region, new
wells would be covered by the l/l All option because the special
climate and safety conditions that exist for parts of the year
make barging especially difficult and hazardous (see Section XI).
XV-8
-------
EPA prefers the 1 mg/kg cadmium and 1 mg/kg mercury
discharge limitations above the 5/3 cadmium and mercury barite
limitations because a) it represents "best available technology,"
and b) EPA believes it more appropriate to develop effluent
standards based on point source discharge limitations than on the
regulation of raw materials (barite in this case).
C. PRODUCED WATER
1. Options Considered
All BAT options considered for produced waters are the same
as those for BCT and are listed in Section XI. For BAT, these
options are intended to control the toxic pollutants. The manner
of control involves various combinations of treatments and/or
zero discharge. The treatment technologies considered in the
options involve either BPT or filtration. The limits associated
with these technologies are for oil and grease. As described in
Section VIII, oil and grease is being limited under BAT as an
indicator pollutant controlling the discharge of toxic
pollutants.
In 1985, three BAT options were considered for produced
waters. These were: 1) improved BPT technology, 2) granular
media filtration, and 3) zero discharge. Membrane filtration is
being considered instead of granular media because of improved
performance and cost. EPA is not considering improved
performance of BPT technology in this current rulemaking because
of the problems associated with the analysis of effluent
limitations representative of this technology. Zero discharge
was not selected for reasons discussed later in this section.
XV-9
-------
2. Selected Options
EPA has selected for BAT proposal the Filter within 4 miles;
BPT Beyond option. This option requires all structures located
at or within 4 miles from shore to meet discharge limitations
based on membrane filtration, and all structures located outside
of 4 miles to meet BPT limitations.
EPA has determined this option to be economically and
technically feasible. EPA chose not to require filtration for
all structures because of the potential adverse effects on oil
and gas production.
EPA is proposing, for this option, effluent limitations
based on membrane filtration. This is a demonstrated technology
and EPA has acquired sufficient data on it to develop a
justifiable standard. The effluent limits developed for membrane
filtration are 13 mg/L daily maximum not to be exceeded, and 7
mg/L monthly average.
The 4 mile distance was selected as part of the preferred
option based on the attempt to minimize the loss of oil and gas
production and to be consistent with the distance used for the
drilling waste proposed option. Both depth and distance were
evaluated as a way of minimizing this impact. Reinjection for
all production structures would result in a production loss in
barrels of oil equivalents (BOEs) in addition to generating
unacceptable non-water-quality environmental impacts due to
excessive fuel use and air emissions from the large pumps
necessary to reinject fluids. Reinjection does eliminate
potential discharge of radionuclides, particularly radium 226 and
228. These radionuclides have been measured at elevated levels
(as high as several thousand picocuries per liter) in produced
water discharges on coastal and near shore offshore areas in the
XV-10
-------
Gulf of Mexico. Data are not available at this time on how
extensive elevated levels of radionuclides are, particularly
further offshore in the Gulf of Mexico. Options involving zero
discharge based on reinjection may receive further consideration
as more data on radionuclides are obtained.
EPA did not select zero discharge based on reinjection
because, at this time, there are questions concerning its
applicability to all structures. Although reinjection may be
technically feasible in general, depending on geological
conditions, specific structures would not be able to reinject.
In addition, air emissions and fuel requirements associated with
reinjection equipment (pumps) are high. In addition, EPA is
concerned with production loss due to reinjection.
Another set of limitations was considered based on
performance of the granular media filtration technology. EPA
chose to propose produced water limitations as its preferred
option based on membrane filtrations due to its better
performance and projected lower cost relative to granular
filtration systems.
It is emphasized here that EPA believes the "Filtration All"
and granular media filtration technology options remain live
alternatives. EPA is continuing its data gathering efforts on
membrane filtration, and this information, together with
additional cost and removal efficiency values, will be analyzed
to further evaluate the filtration options.
D. DECK DRAINAGE
Deck drainage consists of platform and equipment runoff due
to storm events and wastewater as a result of platform and
equipment washdown/cleaning practices. Options being considered
XV-11
-------
as a basis for BAT for this waste stream are either to establish-
the requirement equal to the current BPT limits f no discharge
of free oil (with compliance measured by the st^ ..ic sheen test)
or to require the same standards as those selected for the
produced water waste stream. In many instances the deck drainage
waste stream has similar pollutant characteristics as produced
water and is commingled, and therefore treated, with the produced
water waste stream. Due to the similarity and commingling of
waste streams, the same BAT options presented for the produced
water waste stream are considered for the deck drainage waste
stream. No separate evaluations have been conducted for the
economic analyses of the options for deck drainage. The volumes
of deck drainage are minimal compared to the volumes of produced
water and the deck drainage waste stream is not a continuous flow
waste stream. Thus, the capacity of the produced water treatment
system would not have to be increased to accommodate the deck
drainage volumes so it is expected that no additional costs would
be incurred. In the case of the models used to cost produced
water treatment systems, EPA believes the normal safety margins
included in costing these systems will accommodate the minimal
costs that may be associated with intermittent treatment for deck
drainage. Thus, the economic impact analysis for produced water
is considered to include the necessary deck drainage volumes for
treatment to comply with the options considered.
EPA has selected as the basis for effluent limitations for
deck drainage the produced water discharge option based on
filtration for facilities at 4 miles and less from shore and the
BPT produced water oil and grease limitations for facilities
greater than 4 miles from shore. This is because deck drainage
is similar in pollutant characteristics and can be commingled and
treated with produced water.
XV-12
-------
There are, however, certain situations where effluent
limitations based on filtration may not be appropriate for deck
drainage. For example, deck drainage occurs on drilling
platforms where a production well may not exist; therefore, the
produced water treatment may not be in place either. Thus, EPA
is proposing that the produced water 4 Mile/BPT Beyond option be
applicable to deck drainage during the production phase of the
oil and gas extraction operation, and where filtration technology
is not installed, the BPT limits on free oil will apply.
E. PRODUCED SAND
Produced sand consists of particulate material (sand) from
the producing formation which comes to the surface along with the
crude oil and/or gas and produced water, and is separated by the
produced water desander (setting/screening device) and treatment
system. This waste stream would also include sludges generated
by any chemical polymer use in the filtration portion of the
produced water treatment system. There are two options being
considered for this waste stream: 1) establish the requirement
equal to the current BPT limits of no discharge of free oil or 2)
require zero discharge.
The technology basis for these options are water or solvent
wash of produced sands prior to discharge, or transport of
produced sand to shore for land disposal. The method of
determining compliance with the free oil prohibition is by the
static sheen test discussed earlier.
•
The prohibition on the discharge of free oil or the zero
discharge requirement for produced sand would act as an indicator
to reduce or eliminate the discharge of any toxic pollutants in
the free oil to surface waters. Because this waste stream is of
low volume and because most facilities currently practice either
XV-13
-------
washing or land disposal, the Agency did not attribute any
compliance costs to this proposed option except for nominal
compliance monitoring expenses to perform the static sheen test
to determine the presence of free oil.
»
The zero discharge option would also impose nominal impacts
because the volume of sand in most locations would be minimal and
would be barged to shore infrequently and as part of the barging
of other materials for disposal.
The option selected for proposal is zero discharge for all
facilities based on the minimal volume involved in this waste and
represents the best technology which is both economically and
technically feasible. However, the free oil limitation (current
BPT) option is still being considered as a basis for the final
rule if information is made available to show that the volumes of
produced sand are significantly higher.
F. WELL TREATMENT AND COMPLETION FLUIDS
Well treatment and completion fluids consist of fluids used
down the hole to enhance recovery or complete a well during
production. These wastes either stay in the hole or come up with
the produced water. There are three options being considered for
these wastes: 1) establish the requirements equal to the current
BPT limit of no discharge of free oil, 2) require zero discharge
of the fluids slug and a 100-barrel buffer on either side of the
fluids slug, or 3) zero discharge.
The prohibition on the discharge of free oil or the zero
discharge requirement are both intended to reduce or eliminate
the discharge of toxic pollutants. The method of compliance with
the free oil prohibition for BPT would be the static sheen test.
This is a no cost option.
XV-14
-------
The zero discharge of the fluids slug would require
capturing 100-barrel buffers on either side of the slug, plus the
slug, and barging it to shore.for land disposal. Zero discharge
is another option for those fluids that are not commingled with
produced water. For those fluids that cannot be segregated from
the produced water waste stream, the produced water limitations
would apply.
The costs to meet these requirements are nominal. Volumes
are low, and captured fluids, if no discharge is required, can be
stored and barged to shore for disposal along with other
materials already being transported. Costs to meet requirements
where the fluids are commingled with produced waters are nominal
in comparison to produced water flows and costs.
For cases where the fluids resurface as a discrete slug, EPA
has selected zero discharge of the slug plus a 100-barrel buffer
on either side of it as the preferred option. Where the fluids
are diffused with the produced waters, the preferred option for
produced waters will apply.
G. DOMESTIC AND SANITARY WASTES
The Agency is not proposing to establish BAT effluent
limitations for these waste streams, because there have been no
toxic or nonconventional pollutants of concern identified in
sanitary or domestic wastes.
XV-15
-------
SECTION XVI
NEW SOURCE PERFORMANCE STANDARDS
The basis for new source performance standards under Section
306 of the Act is the best available demonstrated technology.
New facilities have the opportunity to design and implement the
best and most efficient processes and waste treatment
technologies. Therefore, 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.
The Agency has investigated several control and treatment
options as a basis for NSPS to reduce the discharge of pollutants
in waste streams generated by the offshore segment of this
industry. All options considered and selected relative to all
waste streams (except domestic wastes, as discussed later) are
the same for NSPS as for either BCT or BAT so the discussion will
not be repeated here. Table XVI-1 presents the New Source
Performance Standards for EPA's preferred options. No additional
demonstrated technologies were identified other than those
included in the BAT and BCT options. Costs and impacts have been
considered separately from those of BAT, as is discussed in
Section XIII.
The options being considered for domestic wastes are
different only in that a no discharge of foam is being proposed
in addition to the BCT proposed requirements of no discharge of
floating solids. The no discharge of foam requirement is based
on current permit requirements.
For drilling fluids and drill cuttings, the preferred option
for proposal is the same as BAT, Zero Discharge Within 4 Miles;
1/1 Beyond, and is based upon the same factors. These factors
XVI-l
-------
Waste Source
TABLE XVI-1
PROPOSED NSPS EFFLUENT LIMITATIONS GUIDELINES
" NSPS Effluent Limitations
NSPS Effluent
Pollutant Parameter Limitation
Produced water
A) For facilities
located 4 miles
offshore or less
Oil & grease
B) For facilities
located more
than 4 miles
offshore
Drilling fluids
and cuttings
A) For facilities
located 4 miles
offshore or less
B) For facilities
located more
than 4 miles
offshore
Oil & grease
Toxicity
Free oil
Diesel oil
Mercury
Cadmium
Well treatment
completion, and
workover fluids
The maximum for any
one day shall not
exceed 13 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 7 mg/L
The maximum for any
one day shall not
exceed 72 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 48 mg/L
No discharge
Minimum 96-hour
LC50 of the SPP
shall be 3% by
volume
No discharge*
No discharge in
detectable amounts
1 mg/kg dry weight
maximum in the
whole drilling fluid
1 mg/kg dry weight
maximum in the
whole drilling fluid
Zero discharge of
fluids slug plus
100-barrel buffer
on either side
XVI-2
-------
TABLE .XVI-1 (Continued)
PROPOSED NSPS EFFLUENT LIMITATIONS GUIDELINES
NSPS Effluent Limitations
Waste Source
Pollutant Parameter
NSPS Effluent
Limitation
Deck Drainage
(during production)
A) For facilities
located 4 miles
offshore or less
B) For facilities
located more
than 4 miles
offshore
Deck drainage
(during drilling)
Produced sand
Sanitary M10
Sanitary M91M
Domestic Waste
Oil & grease
Oil & grease
Free oil
Residual chlorine
Floating solids
Floating solids
Foam
The maximum for any
one day shall not
exceed 13 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 7 mg/L
The maximum for any
one day shall not
exceed 72 mg/L; the
average of daily values
for 30 consecutive days
shall not exceed 48 mg/L
No discharge
Zero discharge
Minimum of 1 mg/L
No discharge
No discharge
No visible discharge
* Based on Static Sheen Test
XVI-3
-------
are the minimization of potential non-water quality environmental
impacts due to the large volume of solids requiring land disposal
and the air emissions and fuel use associated with transportation
of the solids to land. It is estimated that only about four
percent of the new wells drilled will be on existing structures
(platforms).
Section 306(b)(1)(B) of the Clean Water Act requires EPA, in
establishing new source performance standards, to take into
account any non-water quality environmental impacts and energy
requirements incident to the rules. Non-water quality
environmental impacts and energy requirements have played an
important role in EPA's selection of its preferred NSPS option
for control of drilling fluids and drill cuttings.
The most stringent option considered by the Agency, zero
discharge of drilling fluids and drill cuttings for all
structures (based on transport of spent drilling wastes to shore
for recovery, reconditioning for reuse or land disposal) was
determined to be technologically and economically achievable.
However, a zero discharge requirement applicable to all
structures would cause an enormous amount of solids (estimated at
8.2 million barrels per year) to be barged to shore for land
disposal. In developing this proposal, EPA studied the non-water
quality environmental impacts caused by the barging of this
quantity of drilling waste to land and the availability of
appropriate landfill sites for its ultimate disposal. (See
Section XIV).
EPA's evaluation of the non-water quality environmental
impacts of barging focused on the air emissions that would result.
from the transport of 8.2 million barrels of drilling fluids and
drill cuttings to shore. Air emissions from sources on the OCS
XVI-4
-------
are a matter of longstanding concern to the Agency, Congress and .
states adjoining OCS areas where oil and gas operations take
place. Section 801 of the Clean Air Act Amendments of 1990
(codified as new §328 of the Clean Air Act) reflects this
concern. This new provision requires EPA to "establish
requirements to control air pollution" from OCS sources located
offshore of the states along the Pacific, Arctic and Atlantic
coasts and along the Gulf coast off the State fo Florida. The
air pollution control requirements that are to be established
persuant to new §328 must "attain and maintain Federal and State
ambient air quality standards" and comply with the provisions of
Title I, Part C of the Clean Air Act, which relate to the
prevention of significant deterioration. For sources located
within 25 miles of the seaward boundary of these states, the
requirements "shall be the same as would be applicable if the
source were located in the corresponding onshore area."
"Platform and drill ship exploration, construction,
development, production processing and transportation" and
"emissions from any vessel servicing or associated with and OCS
source" are identified in new §328 as specific air pollutant
sources of concern.
In addition, new §328 of the Clean Air Act requires the
Secretary of the Interior, in consultation with the Administrator
of EPA, to "assure coordination of air pollution control
regulation for Outer Continental Shelf emissions and emissions in
adjacent onshore areas" for portions of the Gulf coast OCS off
the states of Texas, Louisiana, Mississippi and Alabama.
The Agency has estimated that the air emissions associated
with barging to attain zero discharge of drilling fluids and
drill cuttings would be 6,352 short tons of particulates, nitrous
oxides, carbon dioxide, hydrocarbons and sulphur oxides per year.
XVI-5
-------
This estimate was unexpectedly high in comparison to other
options, which ranged from 532 short tons for the 5/3 All and 1/1
All options to 2,116 short tons for the Zero Discharge Shallow;
5/3 Deep and the Zero Discharge Shallow; 1/1 Deep options.
In examining energy requirements, EPA estimated the amount
of diesel fuel that would be required to operate the barging
systems associated with the options under consideration. The
amount of fuel that would have to be expended to attain zero
discharge was estimated at 818,029 barrels per year. This figure
also is significantly higher than the fuel use estimates
associated with the other options, which ranged from 79,517
barrels per year for the 5/3 All and 1/1 All options to 293,535.
barrels per year for the Zero Discharge Shallow; 5/3 Deep and the
Zero Discharge Shallow; 1/1 Deep Options.
Finally, EPA studied the availability of land for drilling
waste disposal in connection with its evaluation of the control
options for drilling fluids and drill cuttings. The study
estimated the available capacity of all existing landfills in the
Gulf of Mexico region and California. The Agency concluded that
sufficient capacity is, or would be, available to support a zero
discharge requirement. However, the 8.2 million barrels of
drilling wastes that would be generated annually as a result of
the zero discharge requirement represents 51 percent of the
capacity of the existing landfills in the Gulf area and
California. (There are currently no landfills in Alaska that
accept these wastes.) EPA is concerned about the use of this
segment of existing landfill capacity for the disposal of
drilling wastes. These concerns are compounded by the fact that
EPA is currently conducting a study under the Resource
Conservation and Recovery Act (RCRA) of wastes associated with
oil and gas activities to determine whether additional, more
stringent requirements are necessary for the treatment and
XVI-6
-------
disposal of such wastes. The outcome of this effort might have a.-
significant effect on the future available capacity and/or cost
of land disposal for drilling wastes and drill cuttings.
Thus, while zero discharge is technologically and
economically achievable, EPA determined that the non-water
quality environmental impacts and energy requirements associated
with this option are significant enough to rule out the selection
of this option as preferred.
The volume of drilling wastes that would have to be
transported to shore for disposal as a result of the 4 Mile Zero
Discharge; 1/1 Beyond option is 1.6 million barrels annually, a
reduction of approximately 80 percent as compared to zero
discharge. This reduces the impacts on landfill capacity
accordingly. The fuel requirements associated with this option
are 173,360 barrels per year, also a reduction of 80 percent.
Annual air emissions are reduced by about 82 percent, from 6,352
short tons to 1,166 short tons compared to the zero discharge
option. EPA believes these non-water quality environmental
impacts associated with the 4 Mile Zero Discharge; 1/1 Beyond
option are reasonable. The 4 Mile Zero Discharge; 1/1 Beyond
option also has the advantage of eliminating discharges of
drilling fluids and drill cuttings from the sensitive marine
areas within four miles of shore while subjecting discharges
seaward of that area to stringent controls. The other distance
options (6 and 8 miles), as well as the shallow/deep options, do
not appreciably reduce non-water quality environmental impacts
compared to the 4 mile option, and insufficient information is
available to evaluate 3 miles.
For NSPS produced water, in addition to the proposed option
of Filtration Within 4 Miles; BPT Beyond which is the same as the
BAT proposal, and the Filtration All Structures option which is
XVI-7
-------
also being strongly considered, zero discharge at 4 miles or less
in conjunction with BPT or filtration beyond 4 miles are being
considered for NSPS. For the reinjection options, the generation
of additional air emissions due to the increased use of high
pressure pumping is significant, although selecting a 4 miles and
less from shore option requiring zero discharge based on
reinjection will minimize the air emissions impact to some
extent. This technology option would reduce overall discharge of
pollutants and eliminate within 4 miles of shore the discharge of
radionuclides, specifically radium 226 and 228. Preliminary
information shows that elevated levels of these radionuclides are
present in produced water, with some of the highest measurements
coming from oil and gas production areas along the Gulf of Mexico
coast. EPA may consider reinjection technology options further
based on obtaining additional data, further characterizing the
radionuclides in produced water discharges, and identifying
geographic areas where there are pollutants of concern in
produced water.
For well treatment, completion and workover fluids that
resurface as a discrete slug, NSPS is proposed as zero discharge
of the slug plus a 100-barrel buffer on either side of the slug.
In the case where these fluids are diffused with the produced
water, the limits of the preferred option for produced water
(Filtration Within 4 Miles; BPT Beyond) will apply. However, EPA
has not ruled out a pH limitation of 6-9 for spent or treated
acid treatment or workover fluids. This will be considered after
additional data gathering prior to promulgation.
NSPS for deck drainage is proposed to be equal to BPT limits
prohibiting discharge of free oil. Zero discharge is proposed as
NSPS for produced sand. NSPS for sanitary wastes is being
XVI-8
-------
proposed equal to current BPT. NSPS for domestic wastes is
proposed equal to BPT plus a requirement of no discharge of
visible foam.
XVI-9
-------
SECTION XVII
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)(1) 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.
However, the Administrator may prescribe BMPs only where he finds
that they are needed to prevent a "significant amount" of toxic
or hazardous pollutants from entering navigable waters.
In the offshore oil and gas industry, there are various
types of wastes that may be affected by the application of BMPs
in NPDES permits. These include deck drainage and leaks and
spills from various sources. The amount of contaminated deck
drainage can be decreased considerably if proper segregation is
practiced. "Clean" deck drainage should be segregated from
sources of contamination. Many sources exist on an offshore
platform where leaks or spills could occur. The areas should be
managed so that all leaks and/or spills are contained and not
discharged overboard.
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
offshore operation are:
1) Separation of waste crankcase oils from deck drainage
collection systems.
XVII-1
-------
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) Elimination of oil drainage from pump bearings and/or
seals by directing the drainage 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 the drilling fluid
that has been contaminated by the spotting oil. Once
segregated, the contaminated drilling fluid can be
disposed of in an environmentally acceptable manner.
Proper initial engineering of the various systems is
essential to proper operation and ease of maintenance. The use
of spare equipment is a requirement for continual operation when
breakdowns occur. Selection of proper treatment chemicals, to
ensure optimum pollutant removals, is essential. Alarms should
be provided to make the operator aware of off-normal conditions
so that corrective action can be taken.
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.
XVII-2
-------
6) Careful application of drill pipe dope to minimize
contamination of receiving water and drilling muds. Pipe dope
can contribute high amounts of lead and probably other metals to
discharged muds.
XVII-3
-------
SECTION XVIII
GLOSSARY AND ABBREVIATIONS
Act - The Clean Water Act.
Air/Gas Lift - Lifting of liquids by injection of air or gas
directly into the well.
Annulus or Annular Space - The space between the drill stem and
the wall of the hole or casing.
AOGA - Alaskan Oil and Gas Association.
API - American Petroleum Institute.
API Gravity - Gravity (weight per unit of volume) of crude oil as
measured by a system recommended by the API.
Attapulgite Clay - A colloidal, viscosity-building clay used
principally in salt water muds. Attapulgite is a hydrous
magnesium aluminum silicate.
Back Pressure - Pressure resulting from restriction of full
natural flow of oil or gas.
Barite - Barium sulfate. An additive used to weight drilling
mud.
Barrel - 42 United States gallons at 60 degrees Fahrenheit.
BAT - The best available technology economically achievable,
under Section 304(b) (2) (b) of the Act.
f
BCT - The best conventional pollutant control technology.
BPT - The best available demonstrated control technology
processes, operating methods, or other alternatives,
including where practicable, a standard permitting no
discharge of pollutants under Section 306(a) (1) of the Act.
Bentonite - A clay additive used to increase viscosity of
drilling mud.
Blowcase - A pressure vessel used to propel fluids intermittently
by pneumatic pressure.
Blowout - A wild and uncontrolled flow of subsurface formation
fluids at the earth's surface.
XVIII-l
-------
Blowout Preventer (BOP) - A device to control formation pressures
in a well by closing the annulus when pipe is suspended in
the well or by closing, the top of the casing at other times.
BMP - Best management practices under Section 304(e) of the Act.
*
BOD - Biochemical oxygen demand.
BPT - The best practicable control technology currently
available, under Section 304(b) (1) of the Act.
Bottom-Hole Pressure - Pressure at the bottom of a well.
Brackish Water - Water containing low concentrations of any
soluble salts.
Brine - Water saturated with or containing a high concentration
of common salt (sodium chloride); also any strong saline
solution containing such other salts as calcium chloride,
zinc chloride, calcium nitrate, etc.
BS&W - Bottom Sediment and water carried with the oil.
Generally, pipeline regulation limits BS&W to 1% of the
volume of oil.
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, drilling continues
through and below the casing with a smaller bit. The
overall length of this casing is called the string of
casing. More than one string inside the other may be used
in drilling the same well.
Centrifuge - A device for the mechanical separation of solids
from a liquid. Usually used on weighted muds to recover the
mud and discard solids. The centrifuge uses high-speed
mechanical rotation to achieve this separation as
distinguished from the cyclone-type separator in which the
fluid energy alone provides the separating force.
Chemical-Electrical Treater - A vessel which utilizes
surfactants, other chemicals, and an electrical field to
break oil-water emulsions.
Choke - A device with either a fixed or variable aperture used
to release the flow of well fluids under controlled
pressure.
Christmas Tree - Assembly of fittings and valves at the top of
the casing of an oil well that controls the flow of oil from
the well.
XVIII-2
-------
Circulate - The movement of fluid from the suction pit through
pump, drill pipe, bit annular space in the hole, and back
again to the suction pit. .
Clean Water Act - The Federal Water Pollution Control Act
Amendments of 1972 (33 U.S.C. 1251 et sea.)/ as amended by
the Clean Water Act of 1977 (Pub. L. 95-217).
Closed-In - A well capable of producing oil or gas, but
temporarily not producing.
COD - Chemical oxygen demand.
Condensate - Hydrocarbons which are in the gaseous state under
reservoir conditions but which become liquid either in
passage up the hole or at the surface.
Connate Water - Water that probably was laid down and entrapped
with sedimentary deposits as distinguished from migratory
waters that have flowed into deposits after they were laid
down.
Cuttings - Small pieces of formation that are the result of the
chipping and/or crushing action of the bit.
Cyclone - Equipment, usually cyclone type, for removing drilled
sand from the drilling mud stream and from produced fluids.
Deck Drainage - Any waste resulting from deck washings, spillage,
rainwater, and runoff from gutters and drains including drip
pans and work areas within facilities addressed by this
document.
Derrick and Substructure - Combined foundation and overhead
structure to provide for hoisting and lowering necessary to
drilling.
Desilter - Equipment, normally cyclone type, for removing
extremely fine drilled solids from the drilling mud stream.
Development Facility - Any fixed or mobile structure addressed by
this document that is engaged in the drilling of potentially
productive wells.
Diesel Oil - The grade of distillate fuel oil, as specified in
the American Society for Testing and Materials' Standard
Specification D975-81, that is typically used as the
continuous phase in conventional oil-based drilling fluids.
XVIII-3
-------
Differential Pressure Sticking - Sticking which occurs because
part of the drill string (usually the drill collars) becomes
embedded in the filter .cake resulting in a non-uniform
distribution of pressure around the circumference of the
pipe. The conditions essential for sticking require a
permeable formation and a pressure differential across a
nearly impermeable filter cake and drill string.
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 this document. Included with these wastes are safety
shower and eye wash stations, hand wash stations, and fish
cleaning stations.
Drill Cuttings - Particles generated by drilling into subsurface
geologic formations and carried to the surface with the
drilling fluid.
Drilling Fluid - The circulating fluid (mud) used in the rotary
drilling of wells to clean and condition the hole and to
counterbalance formation pressure. A water-base 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-base drilling fluid
has diesel, crude, or some other oil as its continuous phase
with water as the dispersed phase.
Drill Pipe - Special pipe designed to withstand the torsion and
tension loads encountered in drilling.
Dump Valve - A mechanically or pneumatically operated valve used
on separator, treaters, and other vessels for the purpose of
draining, or "dumping" a batch of oil or water.
Emulsion - A substantially permanent heterogenous mixture of two
or more liquids (which are not normally dissolved in each
other, but which are) held in suspension or dispersion, one
in the other, by mechanical agitation or, more frequently,
by adding small amounts of substances known as emulsifiers.
Emulsions may be oil-in-water, or water-in-oil.
EPA - United States Environmental Protection Agency.
Exploration Facility - Any fixed or mobile structure addressed
by this document that is engaged in the drilling of wells to
determine the nature of potential hydrocarbon reservoirs.
Field - The area around a group of producing wells.
XVIII-4
-------
Flocculation - The combination or aggregation of suspended solid -
particles in such a way that they form small clumps or tufts
resembling wool.
Flowing Well - A well which produces oil or gas without any means
of artificial lift.
Fluid Injection - Injection of gases or liquids into a reservoir
to force oil toward and into producing wells. (See also
"Water Flooding.")
Formation - Various subsurface geological strata penetrated by
well bore.
Formation Damage - Damage to the productivity of a well resulting
from invasion of mud particles into the formation.
Fracturing - Application of excessive hydrostatic pressure which
fractures the well bore (causing lost circulation of
drilling fluids).
Freewater Knockout - An oil/water separation tank at atmospheric
pressure.
Gas Lift - A means of stimulating flow by aerating a fluid column
with compressed gas.
Gas-Oil Ratio - Number of cubic feet of gas produced with a
barrel of oil.
Gathering Line - A pipeline, usually of small diameter, used in
gathering crude oil from the oil field to a point on a main
pipeline.
Gel - A term used to designate highly colloidal, high-yielding,
viscosity-building commercial clays, such as bentonite and
attapulgite clays.
GC - Gas chromatography.
Gun Barrel - An oil-water separation vessel.
Header - A section of pipe into which several sources of oil,
such as well streams, are combined.
Heater-Treater - A vessel used to break oil water emulsion with
heat.
Hydrocarbon Ion Concentration - A measure of the acidity or
alkalinity of a solution, normally expressed as pH.
XVIII-5
-------
Hydrostatic Head - Pressure which exists in the well bore due to.-
the weight of the column of drilling fluid; expressed in
pounds per square inch (psi) .
Inhibitor - An additive which prevents or retards undesirable
changes in the product. Particularly, pxidation and
corrosion; and sometimes paraffin formation.
Invert Oil Emulsion Drilling Fluid - A water-in-oil emulsion
where fresh or salt water is the dispersed phase and diesel,
crude, or some other oil is the continuous phase. Water
increases the viscosity and oil reduces the viscosity.
Killing a Well - Bringing a well under control that is blowing
out. Also, the procedure of circulating water and drilling
fluids into a completed well before starting well servicing
operations.
Location (Drill Site) - Place at which a well is to be or has
been drilled.
96-hr LC-50 - The concentration of a test material that is
lethal to 50% of the test organisms in a bioassay after 96
hours of constant exposure.
M10 - Those offshore facilities continuously manned by ten or
more persons.
M9IM - Those offshore facilities continuously manned by nine or
fewer persons or only intermittently manned by any number of
persons.
Mud Pit - A steel or earthen tank which is part of the surface
drilling mud system.
Mud Pump - A reciprocating, high pressure pump used for
circulating drilling mud.
Multiple Completion - A well completion which provides for
simultaneous production from separate zones.
NPDES Permit - A National Pollutant Discharge Elimination System
permit issued under Section 402 of the Act.
NRDC - Natural Resources Defense Council.
NSPS - New source performance standards under Section 306 of the
Act.
OOC - Offshore Operators Committee.
PESA - Petroleum Equipment Suppliers Association.
XVIII-6
-------
Packer Fluid - Any Fluid placed in the annulus between the
tubing and casing above a packer. Along with other
functions, the hydrostatic pressure of the packer fluid is
utilized to reduce the pressure differentials between the
formation and the inside of the casing and across the packer
itself.
Pressure Maintenance - The amount of water or gas injected vs.
the oil and gas production so that the reservoir pressure is
maintained at a desired level.
Priority Pollutants - The 65 pollutants and classes of pollutants
declared toxic under Section 307(a) of the Act. Appendix C
contains a listing of specific elements and compounds.
Production Facility - Any platform or fixed structure addressed
by this document that is used for active recovery of hydro-
carbons from producing formations. The production facility
begins operations with the completion phase.
Produced Water - 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.
Produced Sand - Slurried particles used in hydraulic fracturing
d the accumulated formation sands and scale particles
-,
-------
Sequestering Agents - A substance that maintains status quo
bonding. In the case of treatment fluids, they prevent
precipitation of iron compounds. Organic acids are most
commonly used.
Shaleshaker - Mechanical vibrating screen to.separate drilled
formation cuttings carried to surface with drilling mud.
Shut In - To close valves on a well so that it stops producing;
said of a well on which the valves are closed.
Skimmer - A settling tank in which oil is permitted to rise to
the top of the water and is then taken off.
SPCC - A spill prevention control and countermeasure plan
required under Section 311(j) of the Act.
Spot - The introduction of oil to a drilling fluid system for
the purpose of freeing a stuck drill bit or string.
Stripper Well (Marginal Well) - A well which produces such small
volume of oil that the gross income therefrom provides only
a small margin of profit or, in many cases, does not even
cover actual cost of production.
Stripping - Adding or removing pipe when well is pressured
without allowing vertical flow at top of well.
Surfactant - A substance that affects the properties of the
surface of a liquid or solid by concentrating on the surface
layer.
TDS - Total Dissolved Solids.
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.
TOG - Total Organic Carbon.
Total Depth (T.D.) - The greatest depth reached by the drill bit.
Treater - Equipment used to break an oil-water emulsion.
TSS - Total Suspended Solids.
USCG - United States Coast Guard.
USGS - United States Geological Survey.
XVIII-8
-------
Water Flooding - Water is injected under pressure into the
formation via injection wells and the oil is displaced
toward the producing wells.
Well Completion - In a potentially productive formation, the
completion of a well in a manner to permit production of
oil; the walls of the hole above the producing layer (and
within it if necessary) must be supported against collapse
and the entry into the well of fluids from formations other
than the producing layer must be prevented. A string of
casing is always run and cemented, at least to the top of
the producing layer, for this purpose. Some geological
formations require the use of additional techniques to
"complete" a well such as casing the producing formation and
using a "gun perforator" to make entry holes, the use of
slotted pipes, consolidating sand layers with chemical
treatment, and the use of surface-actuated underwater robots
for offshore wells.
Well Completion Fluids - Salt solutions, weighted brines,
polymers, and various additives used to prevent damage to
the well bore during operations which prepare the drilled
well for production.
Well Head - Equipment used at the top of a well, including casing
head, tubing head, hangers, and Christmas Trees.
Well Treatment Fluids - Any fluid used to restore or improve
productivity by chemically or physically altering
hydrocarbon-bearing strata after a well has been drilled.
Wildcat Well - A well drilled to test formations nonproductive
within a 1-mile radius of previously drilled wells. It is
expected that probable hole conditions can be extrapolated
from previous drilling experience data from that general
area.
WOGA - Western Oil and Gas Association.
Workover - To clean out or otherwise work on a well in order to
increase or restore production.
Workover Fluid - Salt solutions, weighted brines, polymers, or
other specialty additives used in a producing well to allow
safe repair and maintenance or abandonment procedures.
XVIII-9
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APPENDIX 1
ANALYSIS OF ALTERNATIVE COST AND CONTAMINANT
REMOVAL FOR GRANULAR MEDIA FILTRATION TECHNOLOGY
-------
APPENDIX 1
ANALYSIS OF ALTERNATIVE COST AND CONTAMINANT
REMOVAL FOR GRANULAR MEDIA FILTRATION TECHNOLOGY
The compliance costs determined in the development document
for produced waters were based on use of membrane filters as
BAT/NSPS technology. This appendix will present alternate costs
based on the use of granular media filtration technology. While
granular media filtration is not being proposed as a BAT/NSPS
control option, EPA is seriously considering this as a viable
option; thus, costs were calculated for it as well. The removal
data include less contaminants than included in the original
analysis, because membrane filtration removes additional
contaminants.
A. BAT
1. Industry Profile
The same Industry Profile used for membrane filtration is
used in granular media filtration cost analysis. Model platforms
and produced water flow rates can be found in Tables XIII-8 and
XIII-8A.
2. Contaminant Removal
Contaminant removals associated with BAT options are
determined by comparing the effluent levels after treatment by
the BAT treatment system (either filtration or reinjection)
versus the effluent levels associated with a typical BPT
treatment. Data used to calculate removals are given in Table
1A. BPT data are based on the 30 platform study. Filtration
effluent data are taken from the spreadsheets.
Pollutants included in the contaminant removal analyses are
conventionals, metals, and organics. TSS and oil and grease are
the conventionals analyzed, and zinc was evaluated for metals
-------
removal. The organic removal analysis evaluated reductions for ,
2-4-dimethylphenol, ethylbenzene, -aphthalene, toluene, bis(2-
ethylhexyl)phthalate, phenol, and Benzene. These pollutants were
those that were consistently present in significant amounts for
produced waters.
The spreadsheets used to evaluate pollutant removal
calculated removal quantities by multiplying the average produced
water rate for each model platform by the difference in
contaminant levels for BPT and the BAT option. The pollutant
removal quantities were then summed for each well category (i.e.,
shallow/deep or distance from shore) and for each geographic
region.
3. Implementation Cost
The cost to install a BAT treatment system for each of the
model platforms was estimated based on the maximum produced water
flow rate over the life of the project and the cost of a
treatment system designed to provide the needed capacity. Data
were entered into the spreadsheets which defined system cost for
five systems over a range of flow rates (200-40,000 barrels per
day); the spreadsheet graphed this data to provide a relationship
between peak water flow rate and system cost; the spreadsheet
then determined the cost for each model platform based on its
peak water flow rate. The cost to implement the BAT option was
determined by summing the costs for each model platform.
-------
TABLE 1A
WASTEWATER CONCENTRATION AFTER BPT TREATMENT
AND BAT TREATMENT OPTIONS
Cent*"1* nant
TSS (mg/1)
Oil t grease (fflg/1)
Zinc (ug/1)
Benzene (ug/1)
Bis(2-ethyIhexyl)phthalate
(ug/1)
Ethylbenzene (ug/1)
Napthalene (ug/1)
Phenol (ug/1)
Toluene (ug/1)
2-4 Dimthjlphenol (ug/1)
BPT Eff. (DAP)
Oil Only
67.5
79
133
931
1
31
66
90
914
693
0
Gas Only Oil and Gas Flow Weighted Averaee*
67.5
28
154
6049
101
736
410
7456
4965
720
67.5
92
2574
1797
106
533
136
814
1533
0
67.5
89.8
2360
1823
101
505
138
954
1545
14.4
BAT (Filtration) BAT
Treated Eff . (Reinfection)
36.1
25.2
52.4
150
10
60
60
60
150
0
0
0
0
0
0
0
0
0
0
0
*Flow weighted averages are calculated according to model brine flows per platform type (from ERCE memorandum
from P. Crampton to file, 'Produced Water - Determination of Aggregate Contaminant Levels in BPT Treated
Effluent," November 21, 1990.
-------
Filtration/Surface Water Discharge. This option
includes the cost of installing a granular media filter to reduce
levels of pollutants prior to discharge to surface water. It
assumes that the water is first treated with BPT treatment; BPT
treatment is considered to be a Dissolved Air Flotation (DAF)
unit or equivalent, but the cost of BPT treatment is not included
in the implementation cost. The cost of a filtration system over
a range of design flow rates is presented in Table 2A. Table 2A
also presents estimates of annual cost for the filtration systems
over the same flow range, geographical area multipliers which
take into account the difference in capital costs for oil
production in areas other than the Gulf of Mexico, and
assumptions used in deriving costs under specific circumstances.
Filtration/Reinfection (Zero Discharge). This option
includes the cost of installing a granular media filter to reduce
levels of TSS prior to deep-well injection of the produced water
and the hardware associated with the injection system. It is
assumed that the produced water is first treated with BPT
treatment (DAF or equivalent). The cost of a filtration/
reinjection system over a range of design flows is presented in
Table 3A. Table 3A also presents annual costs over the same
range of flows, geographic area multipliers which take into
account the difference in capital costs for oil production in
areas other than the Gulf of Mexico, cost to pipe and treat the
water at an onshore facility, costs of injection well drilling,
and assumptions used for deriving costs under specific
circumstances.
4. Results
The implementation costs for contaminant removal are
presented in detail in the spreadsheets.
-------
VABLE It
OOR DATA m BAT OUIULAR HDU mTIATXOI/SURFACE HATER
DISCHARGE SYSTBt FOR PtCOOCKD HATER TREATMENT
1. Capital Co»t Vorrea Tlowrato
tlowjrate (BPP)
•_
ChovicAl Veod/Stons*
Nitration
rlplac
Platform Addition
Generator*
tab-Total*!
In*. I Bonding {«)
TOTALS
2. jAttnaal Co*t Yerra* novrat*
CovpOB«at
Ubor
Nklat«Mae«
ChT»ifl»lt
Kn«r>7
Slndj. Oi^poMl
TOTALS
3* Goo0mvhic AT^B NultloXlvr
200 1,000
1X9,000 129,000
132,000 273,000
42,150 M.300
1M.100 1M.100 2
53,100
491.250 M5.400 2
19.650 24,41*
510,900 712.SU 3
now
200 1,000
32,100 32.SOO
15,327 21.3S4
<5 320
1,200 3,300
5.500 12,700
54,892 70,504
Oolf of taieo
heUle CoMt
Atlantic
Alacka - Cook lalot
Alaaka • Other
9,000
129,000
•06,500
73,550
,071,000
59,000
,939,050
117,562
.056,612
nt« (BPD)
5,000
32,800
91,698
1,600
5,900
56,000
187,998
10,000
129,000
735,000
86,400
2,102,000
63,000
3,116.200
124,648
3,240,000
10,000
32,800
97,225
3.200
7,800
108,900
249,925
1.0
1.6
1.6
2.0
3.5
40,000
172,000
1,339,000
151,100
2,197,000
83,000
3,944,000
157,716
4,102,176
40,000
32,800
123,065
12,800
12,000
424,000
604,665
for Calf Ib BlatfotM la •ballov water, fear platform*
facility with appropriate eapaeltj.
cowMae offloaat and Croat at alagla
-------
TABLE SA
COST DATA FOR C&AIULAR MEDIA mTBATXOH/KEIBJECTXOH SYSTEM
Fat PRODUCED HATER TREATMEHT
1. Capital Co«t Verau* Tlowrat*
•_
Chemical feed/Storage
filtration
Injection Sratem
Platform Addition
Generator*
Sub-Total* t
la*, a landing (4Z)
TOTALS
2 Armufl Cwtr V«rwt ?l«rr*r«
Component -
Labor
Maintenance
Chemieala
Energy
Sludge Diepoaal
TOTALS
3. Geographic Area Multiplier
200 1,000
129,000 129,000
152,000 273,000
240,000 384,000
168,100 168,100
32,000
689,200 1,006,400
27,568 40,256
716,768 1,046,656
t
200 1,000
32,800 32,800
21,503 31,400
65 320
1,200 3.300
5,500 12,700
61,068 80,520
Oulf of Mexico
Pacific Coaat
AtXaUXt&C
Alaaka - Cook, !
Alaaka - Other
flovrat* (BPD)
5.000
129,000
606,500
466,000
2,071,000
39,000
3,352,350
134,094
3,486,444
flomte (BPD)
5,000
32,800
104,593
1,600
5,900
56,000
200,893
1
1
1
bOat 2
3
10,000
129,000
735,000
799,050
2,102,000
63,000
3,828,850
153,154
3,982,004
10,000
32,800
119,460
3.200
7,800
108.900
272.160
0
6
6
0
5
40,000
172,000
1,339,000
1,847,630
2,197,000
83,000
5,638,950
225,550'
3,864,500
40,000
32,800
175,935
12,800
12,000
424.000
657,535
•a 37Z of ahallov wall* weald treat produced water onahore and reiaject water enehore. The capital
operating coat* incurred for aueh an approach would be a* follow* ('Pipeline' ~" "
4. Aaai
and
average distance of formula*).
eoat*.
........ to-Shora* eoat baaed on
Note • The** eoat* ware mot rerieed from original onahore treatment
a) Capital Co«t of On«here Filtration/Reinlection 8yatem
Tlewrata (BPD)
Component
filter Sratam
Reinjeetion Syatam
Pipe-to-Shore
Chemical feed/Storage
Generator*
Sub-Totalai
Installation (30Z)
Engineering (1OT)
Contingency (15Z)
Inraranee/Boadiag (41)
200
43,000
68,600
800,000
36,000
0
947,600
284,280
94,760
142,140
37,904
1,000
77,000
109,800
800,000
36,000
14,857
1,037.657
311,297
103,766
155,649
41,506
5,000
171,000
130,100
800,000
36,000
16,857
1,153,957
346,187
115,396
173,094
46,158
10,000
207.000
228,300
1,084,000
36,000
18,000
1,373,300
471,990
157,330
235,995
62,932
40,000
376.000
327.900
1,309,440
48,000
23,714
2,285,054
683,516
228.505
342,758
91,402
TOTALS
1,506,684 1,649,875 1,834,792 2,501,547 3,633,236
-------
TABLE SA (Continued)
COST DATA FOR GRANULAR MEDIA FILTRATION/REIHJECTIOH SYSTEM
FOR PRODUCED HATER TREATMENT
b) Annual co«t for Onahera filtration/KaiBlaetion gTataa
(BTO)
200 1,000 5,000 10,000 40,000
Uber
Cnamieal*
Inargy
rattu
5. Cott to Drill Offahore
lalaetim
32.MO
U.42I
19
343
•1,519
Ball . Baaed OB
ragioniaed baaia and Ta derived zrea an Drill u
32.MO
31.130
91
943
•4.964
drilling a 3,500
M€ tarvcy
32,100 32.SOO
34,619 47,199
457 914
1,616 2.229
•9,562 13,142
feet deep vail. Coat ia
32, »00
M.552
3,657
3,429
1M.437
ou
B«ll Ceat (t)
Oil/Oil «nd C«« 0«« Only
1,174,143 «11,«25
P«eifie 937,930 2,524,130
Golf ef Mttiee 1,191,293 1,421,200
Atlantic 1,<73,000 1,C73,000
4. Co«t te Drill Oa«her« InUetlen B«ll - latimud at 155.0001 ta«*d OB API drill eo*t 4au
7. Coit te Cenwt Drr Holt te InUetlon P«ll - It !• ••ra»*d that drill slot* on modal pUtferu that
ar« not «*«d tor production walls raprataat dry hela* that eaa ba ceBrartad te wttar iajaction «all*|
oeat ia actiaatad at $240,000. (Xhia dea« act agraa with data la record - Tol, 17, Oeev*aat 1-27.)
I. lajaetiea eapaeity of «aU ia 4,000 B»
9. Aaaia* for Onlf Ib platfermt in aballev «atar, fear platfer** eemblaa afflaant aad traat at aiagla
facility
-------
The results are summarized in Table 4A in terms of
implementation cost and contaminant removal. This table includes
the information necessary to determine costs for all of the
regulatory options presented in Section XI. Table 5A is a
summary according to specific BAT regulatory options in terms of
numbers of platforms affected, capital and annual compliance
costs, and annual pollutant removals.
B. NSPS
1. Industry Profile
The industry profile is the same as defined in the
development document f.or new sources using membrane filtration
(See Tables XIII-14 and XIII-15).
2. Contaminant Removals
Contaminant removals associated with NSPS regulatory options
are determined by comparing effluent levels after treatment by
the NSPS treatment system (either filtration or reinjection)
versus effluent levels associated with a typical BPT treatment
system. Data on effluent levels are the same as presented for
the BAT analysis in Table 1A.
3. Implementation Cost
Implementation costs to install an NSPS treatment system for
each of the "model platforms" were estimated using the same basis
as for BAT.
Both filtration/surface water discharge and zero discharge
(filtration/reinjection) scenarios are costed. The capital (and
annual) cost for a filtration system over a range of design flows
is presented in Table 6A. Geographical area multipliers, which
-------
TABLE *A
HMMXY OF XMPLEMEHTATIOH COSTS AHD COHTAMIHAHT REMOVAL OSING
OUUTOLAR HEDIA FILTRATIOH FOR PRODUCED HATER TREATMEHT
Pollutant laduetion (lb/7r)
Yiltar/8«rfaea Hatar Diac
Shallow Hatar
Daap Hatar
All laeilitiaa
liltration/ltaiB laetton*
Shallow Hatar
Daap Hatar
All Tattil Iti^ff
« of Platf on
*I**TK**
1,309
951
2,260
1,309
951
2,260
Capital
la Coat (8)
•76,358,040
1,534,717,385
2,411,075,425
2,144,944,718
2,646,517,649
4,791,462,567
Annul
Coat (I/7T)
57,754,658
•7,307,095
145,061,754
93,436,375
117.125,274
210,561,649
CoBvaatiooal
11,006,227
23,599,504
34,604,731
18,100,909
38,591,292
56,692,201
Hatala
248,502
582,591
•31,093
254,566
595,407
•49,973
Organiet
510,243
1,115,356
1,623,599
574,779
1.254,608
1,829 ,387
filtar/Kaialaet OBahora/Offahora for Shallow Halla*
Shallow Hatar
Valla < 4 MUaa
Hall. > 4 Hilaa
AIT laeilitiat
1,309
208
2,052
2,260
1,863,031,327
186,756,067
2,227,902,454
2,414,658,521
•77.244,354
11,213,980
134,048,287
145,254.267
18,100,909
3,234,044
31,417,812
34,651,855
254,566
73,550
758,753
•32,303
574,779
140,067
1,487,384
1,627,450
•Shallow daiigaaticB taaad oo «Mtmr dapth at drill dta.
**D«aitnatlon baaad OB diataaea fro* ahera (< 4 aUaa) at drill aita.
-------
TABLE SA
SUMMARY OF IMPLEMENTATION COSTS AND CONTAMINANT REMOVAL - BAT
USINQ GRANULAR MEDIA FILTRATION FOR PRODUCED WATERS
fof
Platforms
Capital
Costffl
Pollutant Reduction (Ib/yr)
Annual
Cost ($/yr) Conventional
Metals
Organtos
Filter and Discharge Shadow/
BPT Deep
Zero Discharge Shadow/
BPT Deep
Filter and Discharge AH
Zero Discharge Shadow/
Fitter Deep
Zero Discharge Ad
Zero Discharge with
4 Mlles/BPT Beyond
1.309
876.000.000
1.309 1.663.000.000
2.260
2.260
2.260
208
2,411,000.000
3,398,000.000
4.510,000.000
187,000.000
58.000.000 11.006.000
77.000,000 18.101.000
145.000.000 34.605.000
165.000.000 41.700.000
194.000.000 56.693.000
11,000.000 3.234,000
249.000
510.000
255.000 575.000
831.000 1.626.000
837.000 1.690.000
850.000 1.829.000
74.000 140.000'
-------
TAIL! •*
COST ucras wt MM ranunoavromci ran oucaoai
TUAiunrr STSTDB rat ROOUCD van.
1. Capital Coat
Coapoaaat
Chaaieal Tatd/leonc*
filtratioa
Pipiac
Goaaxatera
flab-Tbtalat
laa. t InnrHin <4i)
TOTAIJ
2. Annual Cott
C-poa«t
tabor
Chaaieala
Slvdfo Diapoaal
TOTAL*
3. CootraBhie ATM Multiplier
200 1,000
129,000 129,000
152,000 273,000
42,150 40,300
•9,000 107,000
412.130 569,300
14.4M 22,772
421.436 592,072
200 1,000
32.MO 32.MO
12,t39 17,762
65 320
1,200 3,300
3,500 12,700
52,424 64.M2
Vlowrat* (BFD)
5,000
129,000
406,300
110,323
115,000
9M.U5
3*,433
999.231
nowrato (BPD)
5,000
32.MO
29,971
1,600
5,900
56,000
126. 27»
Oulf of tfadeo
Pacific Coaat
Atlaatie
Alaaka - Cook lalot
Alaska - Otaax
10,000
129,000
733,000
129,400
140,000
1,133.600
43.344
1.17I.944
10.000
32.MO
35,361
3,200
7, «00
1M.900
lt7,*M
1.0
1.4
1.4
2.0
3.5
40,000
72,000
564,000
95,400
•7,654
1,947,650
77.906
2.023.356
40,000
32,800
40,767
12,(00
12,000
424,000
542,367
4. AaraM for Oulf Ib platform* la •oiUow wtar. foor pUtf
facility with apprepriat* capacity.
coabtno offInaat aad troat at ciagla
-------
take into account the difference in capital costs for oil
production in areas other than the Gulf of Mexico, are the same
as those presented in Table 2A.
The capital and annual cost of a filtration/reinjection
system over a range of design flows is presented in Table 7A.
Table 7A also presents the capital and annual cost to pipe the
produced water to shore for filtration/reinjection over a range
of design flows and assumptions used in deriving costs under
specified circumstances. Geographic area multipliers presented
earlier in Table 2A were used to take into account the difference
in capital costs for oil production in areas other than the Gulf
of Mexico.
4. Results
The implementation costs and contaminant removals for NSPS
options are presented in detail in the spreadsheets contained in
the rulemaking record. A separate figure was developed for each
NSPS regulatory option.
The results are summarized in Table 8A in terms of
implementation cost and contaminant removals. Table 9A
summarizes these results according to the regulatory options as
presented in Section XI.
-------
TABLE 7A
tot BK nLTunoM/uxuicnoii ITOTM
rat RCODCED Him
1. Capital Coat Varan* Tlowrata
Tlowrata (BPD)
3. Aa
Component
Chewioal Teed/Storage
filtration
lajactioa tyataai
veaaratora
•ob-Totalai
laa. & Bonding (41)
TOTALS
Annual P r V • Tlfwwr
CoBpOMBt
Labor
Haiataaaaea
Cbavieala
laergy
•lodge Diapoaal
TOTALS
200
129,800
132,000
240,000
•9,000
•10,100
24,404
•34,304
200
32,800
' 65
1.200
3,300
38.400
1
129
273
384
107
•93
35
929
t
1
32
27
3
12
76
.
.
,
,
.
.
.
.
.
•
000
000
000
000
000
300
732
032
000
•00
•71
320
300
700
991
5,000
129
606
486
115
1,337
33
1,390
Tlowrata
,000
,500
,000
,000
,330
,494
,•44
(BPD)
3,000
32
41
1
5
36
13*
,800
,725
.600
.900
,000
,025
10
129
735
799
140
1,803
72
1,175
10
'
t
!
,
000
000
000
050
000
050
122
172
000
32,800
36,235
3,200
7, «00
108.900
208
•
735
Aaavwa 37X of ahallow walla would traat prodnead watar onabora and reinject watar oaahora.
and operating eoata incurred for auch aa approach would ba aa follow* (lPipeliae-to-thore*
average distance of fontulaa). Iota - Tbaaa eoata wara not rariaad from original onabora
eoata.
•) Capital Coat of Oaahora filtration /Rain lection (yeton
Ow
filter Irate*
Baiajaetioa Bjatew,
Pipe-to-Shoro
Chamical Teed/Storage
Oaneratore
•nb-Tetalai
laatallatioa (JOX)
Engineering (10X)
Contingency (1SX)
Inaurance/Bonding (4X)
200
43,000
68,600
•00,000
36,000
0
947,400
284,280
94,760
142,140
37,904
1
77
109
•00
36
14
1.037
311
103
135
41
,
,
,
,
,
,
000
000
•00
000
000
•37
457
297
766
649
306
Tlowrata
(BPD)
3,000
171
130
•00
36
16
1.133
346
115
173
46
,000
,100
,000
,000
.•57
,»37
.117
,396
.094
.138
10
207
228
1.0.4
1*
1.373
471
157
235
•2
,000
t
t
t
f
*
t
t
000
300
000
000
000
300
990
330
995
932
40,000
172,000
1,339,000
1,847,630
210,000
3,368
142
3,711
40
32
111
12
12
424
392
The
eoat
treat
40
376
327
1,309
48
S3
2,283
683
228
342
91
,650
,746
,396
,000
,•00
.342
,•00
,000
.000
.942
capital
baaed a
•ant
,000
,000
,900
,440
,000
.714
,054
,516
,505
.758
,402
TOTALS
1,506,684 1.649..75 1,U4,792 2,301,347 3.633,236
-------
XABLE 7A (CaetlBU»d)
COOT DAXA in ttn nuuTxo>/ixiiUBCTxaB mm
ntnaoociD
b) A«*fi**«x coat for Oaapora Yiltration/Ka^'laction Syatam
Tlo»rata
200 1,000 5,000 10,000 40,000
1 •
Labor
IfaiAtananca
Chamieala
faargy
TOTALS
4. Coat to Drill Off ahora
xagionitad baaia ana ia
32.MO
43,201
343
7.,3.3
In Lotion Vail - Baaad on
darivad from ATI Drill n
32,100
49,4,6
943
•9,330
drilling a 3,500
MC •Q^WJf
32.MO
55,044
457
1,6M
•9,9*7
foot daa]
32.WO
75,046
914
2,229
110,9*9
t wall. Coat
32,«00
108,997
3,657
3,429
14C.U3
ia OB
CMC (•)
Oil/011 and Cat C«« Only
AUtkA 1,174,149 111,823
Pseific 937,930 2,524,130
Gulf of tfaxieo 1.191,295 1.4U.200
Atlantic 1.673,000 1.673,000
5. Co»t to Drill OMher* InUetloa Wall . BctiMtod »t 135,0001 teood CD API drill coat 4*ta
6. Cott to Conyort Dry Hol« to laloetien Wall • It ii iiiimfl that drill slot* OB modal platform* that
ara not uaad tor production valla rapraaant dry holaa that can ba eoarartad to matar injaetion valla|
eoat ia aatiaatod at $240.000. (Ihia daaa mot agraa with data is raeord - Vol. 17, Dooomaat 1-27.)
7. lajaction capacity of wall ia 6,000 1K>
-------
PLE SA
SUMMARY OF NSPS IMPLEMENTATION COSTS AND CONTAMINANT REMOVAL
FOR PRODUCED WATERS USING GRANULAR MEDIA FILTRATION
I of Platforms
Pollutant Reduction (Ib/yr)
Capital Annual ~
Cost ($) Cost ($/yr) Conventional Metals Organlcs
Filter/Surface Water Discharge*
Shallow Water 393
Deep Water 458
All Facilities 851
248.264,116
465,285,931
713,550,047
24,659,984
44.616,346
69,276.329
6.599,182
20,804,900
27.404.083
141,781 311,935
531.058 1.013.579
672.839 1.325.514
Filtration/Reinlection*
Shallow Water
Deep Water
All Facilities
393 853,584.177
458 1.165.574.177
851 2,019.158,353
40,083,471
61,964,274
102,047,745
10,894,109
33,955.399
44,849.507
145.452 346.267
542.299 1.118,697
687,751 1.464,964
Filter/Reinlect Onshore/Offshore for Shallow Wells*
Shallow Water 393 813,157,489
Filter/Surface Water Discharge**
Wells < 4 Miles
Wells > 4 Miles
All Facilities
162
689
851
151.334.427
562,215,620
713,550,047
35,898,792
14.062.233
55,214.096
69.276.329
10.894,109 145.452 346.267
6.362,449
21,041,633
27.404.083
136.751 276.393
536.087 1.049.121
672.839 1.325.514
*Shallow water designation based on water depth at drill site.
**Designation based on distance from shore (< 4 miles) at drill site.
-------
TABLE 9A
SUMMARY OF NSPS IMPLEMENTATION COSTS AND CONTAMINANT REMOVAL
USING GRANULAR MEDIA FILTRATION TOR PRODUCED WATERS
*0»
Platforms
Capital
Cost ($)
Pollutant Reduction (Ib/yr)
Annual
Cost ($/yr) Conventional
Metals
Organlcs
Filter and Discharge Shallow/
BPT Deep
Zero Discharge Shallow/
BPT Deep
FHter and Discharge Ad
Zero Discharge Shadow/
Filter Deep
Zero Discharge AH
Zero Discharge with
4 Mlles/BPT Beyond
393
393
248.000.000
813.000.000
25.000.000
6.599.000
851 714,000.000
851 1.319.000.000
851 2.019.000,000
182 151.334.427
36,000,000 10.894.000
69.000.000 27,404,000
85.000.000 31.698.000
102.000.000 44,850.000
14.062.233 6.362.449
142.000
145.000
312.000
346.000
673.000 1.326.000
677.000 1.359.000
688,000 1.465.000
136.751 276.393
-------
APPENDIX 2
DRILLING WASTE: EXAMPLE CALCULATION
FOR FUEL REQUIREMENTS AND AIR EMISSIONS
FOR ZERO DISCHARGE REQUIREMENT
-------
FUEL CONSUMPTION
All veils except Alaska
(similar to Walk, Haydel)
SUPPLY BOATS
Diesel Usage Rate • Diesel Usage
Travel - 16 hre/trip 110 gal/hr 1.760 gal/trip
Demurrage - 24 hrs/trip 60 gal/hr 1,440 gal/trip
Generator - 35 days/veil 6 gal/hr 5.040 gal/veil
From pg 2 of the emissions calculations. The number of trips equals 5.
I Trips Diesel Usage Diesel Usage (gal/veil)
Travel 5 1,760 gal/trip 8,800
Demurrage 5 1,440 gal/trip 7,200
Generator NA 5,040 gal/veil 5.040
21,040
TRUCKS
From pg 3 of emissions calculations. The t of truckloads/vell is
H.
Gulf 71, Pacific 62, Atlantic 102
From the report "Onshore Disposal of Offshore Drilling Wastes . . . .)
veils/year equals 968 (Gulf - 715, Pacific • 237. Atlantic - 16) so the
715 237 16
weighted t of trips equalsi — (71) -I- (62) + — (102) - 69
968 968 968
(69 trips)(40 miles/trip)
. 690 gal of diesel/vell
4 miles/gal
CRANE
67 gal/hr 25 days to drill to 10,553 ft 13.400 gal diesel/vell
TRACTOR
1.67 gal/hr assume 8 hrs/vell 13 gal diesel/vell
DOZER/LOADER
22 gal/hr 2 days/veil (8 hrs/day) 350 gal diesel/vell
TOTAL • 35,493 gal/veil
-------
Table 1
Diesel Fuel Requirements Associated
With the Disposal of Water-Based Muds and Cuttings
(Zero Discharge Case)
Region Diesel Requirements foall
Gulf (714 wells) 25,377,495
Pacific (237 wells) 8,411,841
Atlantic (16 wells) 567,888
M. Alaska (6 wells) 1,369,596
S. Alaska (6 wells) 469.560
Total 36,196,380 (or 861,819 bbls)
Table 2
Emission Discharges Associated
With the Disposal of Water-Based Muds and Cuttings
(Zero Discharge Case)
Air Emissions Discharged ftons/vrl
Region SO. £Q fi£ NO.
Gulf (714 wells) 216 550 286 3,309
Pacific (237 wells) 71 181 94 1,092
Atlantic (16 wells) 8 21 9 116
N. Alaska (6 wells) 16 48 21 256
S. Alaska (6 wells) _ g 11 _ 5_ 40
Total 313 811 415 4,813
Total of all emissions • 6,352 tons/yr
-------
S. Alaska
SUPPLY BOATS
(Similar to Walk, Haydel; number of trips from pg 2 of emissions calculations)
5 trips x 8240 gal/trip • 41.200 gal
TRUCKS
(same as M. Alaska)
65 trips)(1600 milts/trip)
. 26,000 gal
4 miles/gal
CRANES
(same as N. Alaska) - 10.700 gal
FREEZEBACK EQUIPMENT
(same as N. Alaska) • 360 gal
TOTAL S. ALASKA - 78.260 gal/well
TOTAL ALL WELLS EXCEPT ALASKA • 35,493 gal/well
TOTAL N. ALASKA WELLS - 228,266 gal/well
TOTAL S. ALASKA WELLS - 78,260 gal /well
Region I Wells Diesel Requirements
Gulf 715 25,377,495 gal
Pacific 237 8,411,841 gal
Atlantic 16 567,888 gal
N. Alaska 6 1,369,596 gal
S. Alaska 6 469.560 gal
TOTAL 36.196.380 gal
or 661.819 BBLS
-------
N. Alaska
ICE BOAT
(Similar to Walk, Haydel; number of hours from pg 2 emissions
calculations)
Diesel requirement
Travel 5 hrs z 110 gal/hr • - 550 gal
Demurrage 40 hrs x 60 gal/hr • 2,400 gal
Generator 2.160 hrs z 6 gal/hr - 12.960 gal
15.910 gal
TUG
(Data come from page 3 of the emissions calculations.)
Travel 816 hrs z 110 gal/hr • 89.760 gal
Demurrage 1,128 hrs z 60 gal/hr - 67,680 gal
Generator 2,976 hrs z 6 gal/hr • 17.656 gal
175,T '
,296 gal
TRUCKS
(f of trips are shown on page 3 of emissions calculations; other numbers from
Walk, Haydel)
65 trips)(1600 miles/trip)
- - 26,000 gal
4 miles/gal
CRANES
(Identical to Walk, Haydel)
Same as for Gulf • 10,700 gal
FREEZEBACK EQUIPMENT
(Identical to Walk. Haydel)
Same as for landfarm equipment - 360 gal
TOTAL • N. ALASKA - 228,266 gal/well
-------
TUG BOATS (M. Alaska Only)
4,000 mile round trip
Assume 2 trips since vol. are greatly reduced
Travel (2 trips) (17 days/trip) (24 hr/day) - 816 hrs
Demurrage (15 days at rig) (24 hr/day) + (2 trips) (!• day/trip) (24 hrs/day)
• 1,128 hrs
Generator (124 days) (24 hr/day) - 2,976 hrs
Assume same emission values as for supply boat and mult, by time (Ib/vell)
S02 CO HC HP.
Travel 2,448 8. 568 1,877 35,904
Demurrage 1,805 4.061 1.579 28,426
Generator 595 595 1.468 8.928
4.848 13,224 4,944 73,258
TRUCKS (Same as Walk, Baydel except for muds and cuttings volumes)
119 BBLS/truckload, 40 miles round trip except AK. which is 1,600 mi
Region Muds t cuttings I truckloads/vell
Gulf 8,397 71
Pacific 7,309 62
Atlantic 12,053 102
Alaska 7,730 65
Emission factor Ib/truckload (Gulf, Ibs/truckload
(grams /mile) Pacific, Atlantic) (Alaska)
HC 3.5 0.3 12.3
CO 9.4 0.8 33.1
NO, 18.9 1.7 66.6
• Mult. t truckloads by emissions (Ibs/truckload) to determine Ibs/vell
Region B£ £0 E2, (Ibs/well)
Gulf 21.3 56.8 120.7
Pacific 18.6 49.6 105.4
Atlantic 30.6 81.6 173.4
Alaska 799.5 2,151.5 432.9
-------
Emission (Ib/vell)
Region
Gulf (avg)
Pacific (avg)
Atlantic (avg)
AK (avg)
AK
t Trips* S02
5
5
0
5
600
600
946
600
511
CO
1,440
1,440
2,458
1,440
629
£C
772
772
1,054
772
1,148
9,064
9.064
14,299
9,064
7,708
ICEBOAT
Travel
Demurrage
Generator
(5 trips Ml hr/trip) - 5 hrs
(5 trips)(8 hr/trip) • 40 hrs
(90 days)(24 hr/day) - 2.160 hrs
Mult, tine requirements for iceboat by emission values(lbs/hr) on page 1 to
get emissions in Ibs/well for N. Alaska
Travel
Demurrage
Generator
S02
15
64
£P_
53
144
432
629
12
56
1.080
1,148
220
1,008
6.480
7,708
(place values in table above)
*Number of trips calc. from cuttings volumes shown in "Onshore Disposal of
Offshore Drilling Waste' as follows: Vol. cuttings/25/12 - $ trip.
Region Cuttings Vol. (BBLS) I Trips
Gulf 1,471 5
Pacific 1,262 5
Alaska 1.345 5
Atlantic 2.577 9
(assume 25 BBL cuttings/box,
12 boxes/trip
-------
Emissions Associated with Onshore Disposal of Water-Based Drilling Muds and
Cuttings (Ib/well) (avg. case)
SO. CO fiC N0r
Gulf
Supply boats
Cranes
Trucks
Tractors
Dozers
TOTAL
Pacific
Supply boats
Cranes
Trucks
Tractors
Dozers
TOTAL
Atlantic
Supply boats
Cranes
Trucks
Tractors
Dozers
TOTAL
Alaska
Supply boats
Cranes
Trucks
Tractors
Dozers
TOTAL
Alaska
Supply boats
Tug/barge
Cranes
Trucks
Tractors
Dozers
TOTAL
600
3
_
1
605
600
1
_
1
603
946
3
.
1
^
600
1
.
1
603
511
4.848
3
* »
1
5.364
1.440
10
57
29
1.539
1.440
4
50
29
T7526
2.548
2
82
29
2.581
1,440
5
2,152
29
3.629
629
13.224
9
2.152
29
16.046
772
4
21
2
801
772
2
19
2
75f
1.054
3
31
2
1.092
722
2
800
2
17378
1.148
4.944
4
800
2
6.900
9,064
47
121
10
9,255
9.064
1
105
10
13
97213
14.299
41
173
10
14,536
8,064
22
4,329
10
137538
7,708
73,258
43
4.329
10
85.361
-------
CRANE (same assumptions as Walk, Haydel except for volumes of muds/cut tings
10 lifts/hr, 25 BBLS/box)
Region
Gulf
Pacific
Atlantic
N. Alaska
S. Alaska
i Cuttings Boxes Times Factor
1,471/25 • 59
51
103
54
54
4
2
2
4
2
Hours of Operation
23.6 (59/10 x 4)
10.2
20.6
21.6
10.8 '
Emission factors CO
(Ib/hr) 0.434
1C
0.16
0^33
Particulates
0.143
Aldehyde
0.03
•Mult, hrs of operation by emission factors in Ibs/hr to get:
Region £0 gC NO. SOT Particulates Aldehyde
0.71
0.31
0.62
0.65
0.32
Gulf
Pacific
Atlantic
N. Alaska
S. Alaska
10.2
4.4
8.9
9.4
4.7
^•^^
3.8
1.6
3.3
3.5
1.7
•^•Ml
47.4
20.5
41.4
43.4
21.7
3.1
1.4
2.7
2.9
1.4
3.4
1.5
2.9
3.1
1.5
VHEEL TRACTOR FOR GRADING (identical to Walk, Haydel)
Parameter
(assume 8 hrs)
Emission Factor (Ib/hr) Emission (Ib/vell)
CO
HC
NO,
SO,
Particulates
Aldehyde
3.59
0.188
1.269
0.090
0.136
0.03
28.7
1.5
10.2
0.72
0.24
0.24
DOZER/LOADER (identical to Walk, Baydel)
Parameter
(assume 16 hrs)
Passion Factor flb/hr) Fission fib/veil)
CO
EC
»°»
SO,
Particulates
Aldehyde
0.201
0.098
0.827
0.076
0.058
0.009
2.2
1.6
13.2
1.2
0.9
0.1
-------
Estimated Annual Emissions Under Zero Discharge Limit (tons/year)
SO, £0 HC NO.
Gulf (715 veils) 216 550 286
Pacific (237 veils) 71. 181 94
Atlantic (16 veils) 8 21 9
S. Alaska (6 veils) 2 11 5
N. Alaska (6 veils) _16 48 21
TOTALS 313 811 415 4,813
6,352 tons per year of all pollutants
Notes:
1. I of veils obtained from the report "Onshore Disposal of Offshore
Drilling Waste.
2. f of veils in Alaska evenly divided between N. and S.
-------
APPENDIX 3
PRODUCED WATERS EXAMPLE CALCULATION OF
ENERGY REQUIREMENTS AND AIR EMISSIONS FOR
FILTRATION AND DISCHARGE ALL OPTIONS
FOR GULF OF MEXICO
-------
SAMPLE CALCULATION
1. Energy Requirement - Filtration/Surface Water Discharge
a) Gulf of Mexico
Plow - 866.5 x 106 BPY
P - 50 psi
Energy • (50 Ibs/in2)(144 in2/ft2)(866.5 x 10* B/yr)
X (5.61 ft3/B)(l/.8 eff) - 43,749 x 10* ft-lb/yr
yr day hr nin ' .0018182 HP
. 2522 HP
3650 24 hr 60 min 60 sec ft - Ib/sec
Natural Gas
(2522 HP)(2545 BTU/HP-hr)(scf NG/1000 BTU)
X (I/.2 eff)(24 hr/D)(365 D/yr)
• 281.2 x 106 scf Natural Gas/yr
-------
2. Energy Requirement - Reinjection
a) Gulf of Mexico
Flow « 866.5 x 10' B/yr
P • 50 psi plus 1800 psi
• 1850 psi
Natural Gas - 10,404 x 10* scf NG/year
3. Air Emissions - Filter/Discharge
a) Gulf of Mexico
Natural Gas « .2812 x 109 scf NG
1) Particulates - 7.016 x .2812 • 1.97 tons/yr
2) NO, - 206.5 x .2812 - 58.1 tons/yr
3) C02 - 57.5 x .2812 • 16.2 tons/yr
4) SO, - 0.33 x .2812 • 0.09 tons/yr
5) HC. - 21.0 x .2812 - 5.9 tons/yr
-------
APPENDIX 4
CONTAMINANT REMOVAL BY MEMBRANE FILTRATION
ACCORDING TO REGION AND REGULATORY OPTION
-------
This appendix consists of two tables. Table 4A list contaminant
removals (all units are in pounds/year) for existing sources for
BAT regulatory options. Table 4B lists contaminant removals (all
units also in pounds/year) for new sources for NSPS regulatory
options.
-------
TABLE 4A
SHALLOW/BPT DEEP
POLLUTANT GULF
BENZENE
DIMETHYLPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
IUTANIUM
PNC
CALIF
165507
1295
45710
12484
139795
9132
86182
13837
32949
148556
151032
5695
6875
0.038
4666
11808
12380
145223
4285
120940
762
324
222453
35541
278
9816
2681
30020
1961
18507
2971
7075
31901
32433
1223
1476
0.008
1002
2536
2658
31185
920
25971
164
70
47770
ALASKA ATLANTIC TOTAL
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
201048
1573
55525
15165
169815
11093
104688
16808
40024
180457
183465
6918
8352
0.046
5668
14344
15038
176408
5205
146911
925
393
270223
-------
TABLE 4A (Continued)
REINJECT SHALLOW/BPT DEEP
POLLUTANT GULF
CALIF
ALASKA ATLANTIC TOTAL
BENZENE
DIMETHYLPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
174172
1362
48090
13141
147128
9618
90753
14570
34663
156365
159031
5999
7237
0.381
11713
29426
2146445
2035218
10761
425289
15332
809
224739
37402
292
10327
2822
31594
2065
19488
3129
7444
33578
34150
1288
1554
0.082
2515
6319
460928
437043
2311
91327
3292
174
48260
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 211574
0 1654
0 58417
0 15964
0 178722
0 11683
0 110241
0 17699
0 42107
0 189943
0 193182
0 7288
0 8791
0 0.463
0 14228
0 35744
0 2607373
0 2472261
0 13072
0 516616
0 18624
0 983
0 272999
-------
TABLE 4A (Continued)
PlLTER AND DISCHARGE ALL
POLLUTANT GULF
BENZENE
DZMETH7LPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-X7LENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
^ITANIUM
•NC
CALIF
527251
4126
145616
39771
445342
29093
274547
44079
104965
473252
481139
18141
21903
0.121
14865
37617
39438
462634
13651
385276
2427
1031
708664
98659
772
27248
7442
83332
5444
51373
8248
19641
88555
90031
3395
4098
0.023
2782
7039
7380
86568
2554
72093
454
193
132605
ALASKA ATLANTIC TOTAL
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
625910
4898
172864
47213
528674
34537
325920
52327
124606
561807
571170
21536
26002
0.144
17646
44656
46817
549202
16206
457368
2881
1224
841269
-------
TABLE 4A (Continued)
RZINJECT SHALLOW/FILTER DEEP
POLLUTANT GULF CALIF
ALASKA ATLANTIC TOTAL
BENZENE
DIMETHYLPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
535917
4192
147997
40428
452675
29579
279118
44812
106679
481061
489139
18446
22265
0.464
21912
55235
2173503
2352629
20127
689625
16997
1517
710950
100520
786
27759
7583
84907
5548
52355
8406
20009
90232
91748
3460
4176
0.096
4295
10822
465649
492426
3945
137449
3583
297
133096
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 636437
0 4979
0 175756
0 48012
0 537582
0 35127
0 331472
0 53218
0 126688
0 571292
0 580887
0 21906
0 26441
0 0.560
0 26207
0 66057
0 2639152
0 2845055
0 24072
0 827074
0 20580
0 1814
0 844046
-------
TABLE 4A (Continued)
INJECT ALL
POLLUTANT
BENZENE
DIKETHYLPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
JTITANIUM
QlNC
GULF
554857
4338
153200
41865
468701
30640
289108
46415
110425
498128
506622
19112
23056
1.213
37314
93740
6837882
6483550
34280
1354835
48842
2579
715945
CALIF
103825
812
28667
7834
87703
5733
54098
8685
20663
93210
94799
3576
4314
0.227
6982
17541
1279504
1213201
6415
253517
9139
483
133968
ALASKA ATLANTIC TOTAL
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 658682
0 5150
0 181867
0 49698
0 556405
0 36373
0 343206
0 55100
0 131088
0 591338
0 601421
0 22688
0 27370
0 1.441
0 44296
0 111281
0 8117386
0 7696751
0 40695
0 1608352
0 57981
0 3061
0 849913
-------
TABLE 4A (Continued)
4 MILE/BPT DEEP
POLLUTANT
BENZENE
DZMETHTLPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
GULF
CALIF
25734
201
7107
1941
21736
1420
13400
2151
5123
23098
23483
885
1069
0.006
726
1836
1925
22580
666
18804
118
50
34588
32737
256
9041
2469
27651
1806
17047
2737
6517
29384
29874
1126
1360
0.008
923
2336
2449
28725
848
23922
151
64
44001
ALASKA ATLANTIC TOTAL
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
58471
458
16148
4411
49387
3226
30446
4888
11640
52482
53357
2012
2429
0.013
1648
4172
4374
51305
1514
42726
269
114
78589
-------
TABLE4B
•LT:
TOLL1
LTER SHALLOW/BPT DEEP
.UTANT GULF
CALIF
ALASKA ATLANTIC TOTAL
BENZENE
DIMETH7LPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
91558
716
25287
6906
77335
5052
47676
7654
18227
82181
83551
3150
3804
0.021
2581
6532
6848
80337
2371
66904
421
179
123061
8530
67
2356
643
7205
471
4442
713
1698
7657
7784
294
354
0.002
240
609
638
7485
221
6233
39
17
11465
21620
169
5971
1631
18262
1193
11258
1807
4304
19406
19729
- 744
898
0.005
610
1543
1617
18971
560
15798
100
42
29059
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
121709
952
33613
9181
102801
6716
63375
10175
24230
109244
111064
4188
5056
0.028
3431
8683
9104
106793
3151
88936
560
238
163586
-------
TABLE 4B (Continued)
REINJECT SHALLOW/BPT DEEP
POLLUTANT GULF
BENZENE
DIHETHYLPHENOL
ETH7LBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
CALIF ALASKA ATLANTIC TOTAL
0 128081
0 1001
0 35364
0 9664
0 108193
0 7073
0 66737
0 10714
0 25490
0 114986
0 116947
0 4412
0 5322
0 0.280
0 8613
0 21639
0 1578432
0 1496640
0 7913
0 312745
0 11275
0 595
0 165266
96352
753
26604
7270
81391
5321
50204
8060
19176
86501
87976
3319
4004
0.211
6480
16278
1187413
1125882
5953
235270
8482
448
124325
8977
70
2479
677
7583
496
4677
751
1787
8059
8196
309
373
0.020
604
1517
110627
104895
555
21919
790
42
11583
22752
178
6282
1717
19219
1256
11855
1903
4528
20426
20774
784
945
0.050
1530
3844
280392
265862
1406
55556
2003
106
29358
-------
TABLE 4B (Continued)
•:LT
TOLL
LTER AND DISCHARGE ALL
.UTANT GULF CALIF
ALASKA ATLANTIC TOTAL
BENZENE
DIMETHYLPHENOL
ETH7LBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
248600
1945
68658
18752
209980
13717
129449
20783
49491
223139
226858
8554
10327
0.057
7009
17737
18595
218133
6437
181658
1144
486
334137
209359
1638
57821
15792
176835
11552
109016
17503
41679
187918
191049
7204
8697
0.048
5903
14937
15660
183701
5421
152984
964
410
281394
27271
213
7532
2057
23035
1505
14200
2280
5429
24478
24886
• 938
1133
0.006
769
1946
2040
23929
706
19928
126
53
36654
9134
. 71
2523
689
7715
504
4756
764
1818
8199
8336
314
379
0.002
258
652
683
8015
237
6675
42
18
12277
494365
3868
136533
37291
417565
27278
257422
41330
98418
443734
451129
17010
20537
0.114
13938
35271
36978
433778
12800
361245
2276
967
664463
-------
TABLE 4B (Continued)
REINJECT SHALLOW/FILTER DEEP
POLLUTANT GULF CALIF ALASKA
ATLANTIC TOTAL
BENZENE
DIMETHYLPHENOL
ETH7LBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANBS
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
253394
1982
69975
19116
214036
13986
131978
21189
50439
227459
231283
8722
10528
0.247
10907
27483
1199159
1263678
10019
350024
9204
755
335401
209806
1642
57943
15826
177213
11577
109252
17541
41767
188320
191462
7219
8716
0.066
6266
15845
125649
281112
5754
168670
1715
435
281512
28403
222
7843
2143
23992
1568
14798
2376
5653
25498
25931
- 978
1180
0.051
1689
4247
280815
270821
1552
59685
2029
117
36953
9134
' 71
2523
689
7715
504
4756
764
1818
8199
8336
314
379
0.002
258
652
683
8015
237
6675
42
18
12277
500737
3917
138284
37774
422957
27635
260784
41869
99678
449476
457012
17234
20803
0.366
19120
48226
1606306
1823625
17562
585054
12990
1324
666143
REINJECT SHALLOW/FILTER DEEP
POLLUTANT
BENZENE
DIMETHYLPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
GULF
253394
1982
69975
19116
214036
13986
131978
21189
50439
227459
231283
8722
10528
0.247
10907
27483
1199159
1263678
10019
350024
9204
755
335401
CALIF
209806
1642
57943
15826
177213
11577
109252
17541
41767
188320
191462
7219
8716
0.066
6266
15845
125649
281112
5754
168670
1715
435
281512
ALASKA
28403
222
7843
2143
23992
1568
14798
2376
5653
25498
25931
978
1180
0.051
1689
4247
280815
270821
1552
59685
2029
117
36953
ATLANTIC
9134
71
2523
689
7715
504
4756
764
1818
8199
8336
314
379
0.002
258
652
683
8015
237
6675
42
18
12277
TOTAL
500737
3917
138284
37774
422957
27635
260784
41869
99678
449476
457012
17234
20803
0.366
19120
48226
1606306
1823625
17562
585054
12990
1324
666143
-------
TABLE 4B (Continued)
KEINJECT ALL
POLLUTANT
BENZENE
DIMETHYLPHENOL
ETH7LBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BDTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
GULF
CALIF
ALASKA ATLANTIC TOTAL
261616
2045
72234
19739
220994
14447
136315
21885
52066
234868
238873
9011
10871
0.572
17594
44199
3224074
3057006
16163
638807
23029
1216
337569
220321
1723
60832
16623
186111
12166
114798
18430
43847
197795
201168
7589
9155
0.482
14817
37222
2715167
2574470
13612
537974
19394
1024
284285
28699
224
7924
2165
24243
1585
14954
2401
5712
25765
26204
989
1193
0.063
1930
4849
353678
335351
1773
70077
2526
133
37031
9613
75
•2654
725
8120
531
5009
804
1913
8630
8777
331
399
0.021
646
1624
118464
112325
594
23472
846
45
12403
520249
4068
143645
39253
439467
28729
271076
43520
103538
467058
475023
17920
21618
1.138
34987
87893
6411383
6079152
32142
1270330
45796
2418
671289
-------
TABLE 4B (Continued)
4 MILE/BPT DEEP
POLLUTANT
BENZENE
DIMETHYLPHENOL
ETHYLBENZENE
NAPHTHALENE
TOLUENE
BIS-PHTHALATE
PHENOL
M-XYLENE
P-CRESOL
N-ALKANES
BUTANONE
STERANES
TRITERPANES
RADIUM
ALUMINUM
ARSENIC
BORON
BARIUM
COPPER
IRON
MANGANESE
TITANIUM
ZINC
GULF
CALIF
ALASKA ATLANTIC TOTAL
24762
194
6839
1868
20915
1366
12894
2070
4930
22226
22596
852
1029
0.006
698
1767
1852
21727
641
18094
114
48
33282
69609
545
19225
5251
58796
3841
36247
5819
13858
62480
63522
2395
2892
0.016
1963
4966
5207
61078
1802
50865
320
136
93560
21620
169
5971
1631
18262
1193
11258
1807
4304
19406
19729
. 744
898
0.005
610
1543
1617
18971
560
15798
100
42
29059
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
115992
908
32034
8749
97972
6400
60398
9697
23092
104112
105847
3991
4819
0.027
3270
8276
8676
101776
3003
84758
534
227
155901
------- |