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DEVELOPMENT DOCUMENT
for
FINAL EFFLUENT LIMITATIONS GUIDELINES
and
NEW SOURCE PERFORMANCE STANDARDS
for the
OFFSHORE SUBCATEGORY
of the
OIL AND GAS EXTRACTION POINT SOURCE CATEGORY
William K. Reilly
Administrator
Thomas O'Farrell
Director, Engineering and Analysis Division
Marvin Rubin
Chief, Energy Branch
Ronald P. Jordan
Project Officer
January 15, 1993
Engineering and Analysis Division
Office of Science and Technology
Office of Water
U.S. Environmental Protection Agency
Washington, D.C. 20460
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TABLE OF CONTENTS
Page
SECTION I
INTRODUCTION
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1.0 LEGAL AUTHORITY 1-1
1.1 BACKGROUND 1-1
1.1.1 Clean Water Act . . ..." . . . . 1-1
1.1.2 Section 304(m) Requirements and Litigation 1-3
1.1.3 Pollution Prevention Act .-.- 1-3
1.1.4 Prior Regulation and Litigation for the Offshore
Subcategory 1-4
SECTION H SUMMARY OF THE FINAL REGULATIONS
1.0 INTRODUCTION . ; . H-l
1.1 BPT LIMITATIONS H-l
1.2 SUMMARY OF THE FINAL RULE n-1
1.2.1 BAT and NSPS for Major Waste Streams . . H-2
1.2.2 BAT AND NSPS for Miscellaneous Waste Streams H-2
1.2.3 BCT for Major and Miscellaneous Waste Streams H-3
1.2.4 BCT, BAT and NSPS Summary Tables for the Final
Rule H-3
SECTION IH INDUSTRY SUBCATEGORIZATION
o
1.0 INTRODUCTION ffl-1
2.0 REGULATORY DEFINITION ffl-1
2.1 NEW SOURCE DEFINITION . ffl-2
2.2 GEOGRAPHICAL LOCATIONS OF THE OFFSHORE INDUSTRY . ffl-5
2.3 MAJOR WASTES STREAMS ffl-5
2.3.1 Drilling Fluid . . ffl-8
2.3.2 Drill Cuttings . . . . ........ ffl-8
2.3.3 Produced Water ffl-8
2.4 MISCELLANEOUS WASTES ffl-8
2.4.1 Produced Sand . ffl-8
2.4.2 Well Treatment Fluids .-."... ffl-8
2.4.3 Well Completion Fluids ffl-9
2.4.4 Workover Fluids . ffl-9
2.4.5 Deck Drainage ffl-9
2.4.6 Domestic Waste . ffl-9
2.4.7 Sanitary Waste ffl-9
2.5 MINOR WASTES . . . . ffl-9
3.0 CURRENT PERMIT STATUS ffl-10
4.0 REFERENCES ffl-12
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TABLE OF CONTENTS (Continued)
SECTION IV INDUSTRY DESCRIPTION
1.0 INTRODUCTION IV-1
2.0 DRILLING ACTIVITIES '.'. iv-l
2.1 EXPLORATORY DRILLING iv-l
2.1.1 Drilling Rigs IV-3
2.1.2 Formation Evaluation IV-4
2.2 DEVELOPMENT DRILLING iy-4
2.2.1 Well Drilling IV-4
3.0 PRODUCTION ACTIVITIES ' . ' ] r/-8
3.1 FLUID EXTRACTION IV-g
3.1.1 Enhanced Oil Recovery IV-9
3.2 COMPLETION IV-10
3.3 FLUID SEPARATION . IV-12
3.4 WELL TREATMENT IV-16
3.5 WORKOVER IV-17
4.0 PRODUCTION AND DRILLING: CURRENT ACTIVITY AND FUTURE
PROJECTIONS IV-17
4.1 INDUSTRY SUBCATEGORIZATION IV-17
4.1.1 Industry Profile IV-18
4.2 EXISTING PLATFORMS IV-19
4.3 NEW SOURCES IV-20
4.3.1 Drilling Activity IV-20 :
4.3.2 Production IV-21
5.0 REFERENCES IV-22
SECTION V DATA AND INFORMATION GATHERING
1.0 INTRODUCTION V-l
2.0 DRILLING FLUIDS AND DRILL CUTTINGS . V-2
2.1 CHARACTERIZATION OF WATER-BASED DRILLING FLUIDS V-2
2.2 AMERICAN PETROLEUM INSTITUTE DRILLING FLUIDS SURVEY V-4
2.3 API/OOC DRILLING FLUIDS BIOASSAY STATISTICS V-7
2.4 OFFSHORE OPERATORS COMMITTEE SPOTTING FLUID SURVEY V-7
2.5 THE EPA/API DIESEL PILL MONITORING PROGRAM V-8 I
2.6 STATISTICAL ANALYSIS OF THE API-USEPA METALS DATABASE V-12 0
2.7 STUDY OF ONSHORE DISPOSAL FACILITIES FOR DRILLING WASTE V-13
2.8 ONSHORE DISPOSAL OF OFFSHORE DRILLING WASTE - CAPACITY I
OF ONSHORE DISPOSAL FACILITIES V-13 "
2.9 OFFSHORE DRILLING SAFETY v-14
3.0 PRODUCED WATER DATA GATHERING '.'.'.'.'.'.'.'.'.'. V-15
3.1 INTRODUCTION " V-15
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TABLE OF CONTENTS (Continued)
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3.2 30 PLATFORM STUDY . V-15
3.3 ALASKA AND CALIFORNIA SAMPLING PROGRAMS V-16
3.4 PRODUCED WATER TREATMENT TECHNOLOGY EVALUATIONS V-17
3.4.1 Three Facility Study V-17
3.4.2 Ceramic Crossflow Membrane Filtration V-18
3.4.3 Evaluation of Gas Flotation Performance V-18
3.4.4 Technical Feasibility of Brine Reinjection V-19
3.5 LITERATURE DATA COLLECTION FOR RADIOACTIVITY IN PRODUCED
WATER V-19
4.0 DATA COLLECTION FOR MISCELLANEOUS AND MINOR
DISCHARGES . v_20
5.0 ANALYTICAL METHODS V-20
5.1 REVIEW OF STATIC SHEEN TESTING PROCEDURES . . V-20
5.2 ANALYTICAL METHOD FOR DIESEL OIL DETECTION V-22
5.3 OIL AND GREASE V-24
5.4 DRILLING FLUIDS TOXICITY TEST V-25
6.0 REFERENCES . . V-28
SECTION VI SELECTION OF POLLUTANT PARAMETERS
1.0 INTRODUCTION VI-1
2.0 DRILLING FLUIDS AND DRILL CUTTINGS VI-1
2.1 DIESEL OIL vi-2
2.2 FREE OIL VI-3
2.3 TOXICITY ..'.'/.'. VI-3
2.4 POLLUTANTS NOT REGULATED . . . VI-5
3.0 PRODUCED WATER VI-5
3.1 POLLUTANTS Nor REGULATED VI-7
4.0 WELL TREATMENT, COMPLETION AND WORKOVER FLUIDS . . . . . . . . . VI-7
4.1 POLLUTANTS NOT REGULATED . . . VI_g
5.0 PRODUCED SAND VI-8
6.0 DECK DRAINAGE '.'.'.'.'.'.'.'.'. VI-9
7.0 REFERENCES ............... VI-10
SECTION VII DRILLING FLUIDS - CHARACTERIZATION, CONTROL AND
TREATMENT TECHNOLOGIES
1.0 INTRODUCTION VH-1
2.0 DRILLING FLUIDS SOURCES VH-1
3.0 DRILLING FLUIDS VOLUMES '.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'. vn-2
4.0 DRILLING FLUIDS CHARACTERIZATION '..'.-.'.'.'.'.'.'.'.'.'.'. W-3
4.1 PROPERTIES OF DRILLING FLUIDS AND ADDITIVES 'VH-5
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TABLE OF CONTENTS (Continued)
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4.2 COMPONENTS OF DRILLING FLUIDS VH-7
4.3 DRILLING FLUID COMPOSITION VII-10
5.0 CONTROL AND TREATMENT TECHNOLOGY VH-17
5.1 BPT TECHNOLOGY VH-17
5.2 ADDITIONAL WASTE MANAGEMENT PRACTICES AND TECHNOLOGIES
CONSIDERED vn-17
5.2.1 Product Substitution - Acute Toxicity Limitations VII-19
5.2.2 Product Substitution - Clean Barite VII-19
5.2.3 Product Substitution - Mineral Oil . VII-25
5.2.4 Onshore Treatment/Disposal VH-25
5.2.5 Waste Minimization - Enhanced Solids Control VII-28
5.2.6 Conservation and Reuse/Recycling VH-31
5.2.7 Thermal Distillation/Oxidation VH-31
5.2.8 Solvent Extraction VH-32
5.2.9 Grinding/Reinjection VII-33
5.2.10 Incineration VH-34
6.0 REFERENCES I
SECTION VIE DRILL CUTTINGS-CHARACTERIZATION, CONTROL AND
TREATMENT TECHNOLOGIES
1.0 INTRODUCTION
2.0 DRILL CUTTINGS SOURCES Vffl-1
2.1 SOLIDS CONTROL SYSTEM VKI-1
3.0 DRILL CUTTINGS VOLUMES Vffl-3
4.0 DRILL CUTTINGS CHARACTERISTICS VDI-4
5.0 CONTROL AND TREATMENT TECHNOLOGY - . Vffl-4
5.1 BPT TECHNOLOGY Vffl-5
5.2 ADDITIONAL TECHNOLOGIES Vffl-5
5.2.1 Onshore Treatment and/or Disposal Vffl-5
5.2.2 Mechanical Processes Vffl-5
5.2.3 Thermal Distillation/Oxidation Vffl-7
5.2.4 Solvent Extraction Vffl-7
5.2.5 Grinding/Reinjection Vffl-8
6.0 REFERENCES V^9
SECTION LX PRODUCED WATER-CHARACTERIZATION, CONTROL
AND TREATMENT TECHNOLOGIES
1.0 INTRODUCTION K'1
2.0 PRODUCED WATER SOURCES LX-1
3.0 PRODUCED WATER VOLUMES LX-1
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TABLE OF CONTENTS (Continued)
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4.0 PRODUCED WATER COMPOSITION t IX-6
4.1 GULF OF MEXICO - 30 PLATFORM STUDY IX-6
14.2 CALIFORNIA SAMPLING PROGRAM IX-9
4.3 ALASKA SAMPLING PROGRAM IX-11
4.4 STATISTICAL ANALYSIS OF EPA/API PRODUCED WATER EXPANDED
IDATASET . IX-13
5.0 CONTROL AND TREATMENT TECHNOLOGIES IX-14
5.1 BPT TECHNOLOGY LX-15
I 5.1.1 Equalization IX-16
^P 5.1.2 Solids Removal IX-16
i 5.1.3 Gravity Separation IX-16
5.1.4 Parallel Plate Coalescers LX-17
* 5.1.5 Gas Flotation rx-17
, 5.1.6 Chemical Treatment LX-22
5.1.7 Skim Pile . . IX-23
5.1.8 Reinjection LX-25
_ 5.2 ADDITIONAL TECHNOLOGIES EVALUATED FOR BAT AND NSPS
| CONTROL . . LX-25
5.2.1 Improved Performance of Gas Flotation Technology LX-25
_ . 5.2.2 Reinjection . IX-27
^B 5.2.3 Granular Filtration . LX-32
5.2.4 Crossflow Membrane Filtration . . LX-35
15.2.5 Activated Carbon Adsorption LX-41
6.0 REFERENCES LX-42
9m SECTION X MISCELLANEOUS WASTE-CHARACTERIZATION,
| CONTROL AND TREATMENT TECHNOLOGIES
11.0 INTRODUCTION . , X-l
2.0 PRODUCED SAND '.'.'.'.'.'.'.'.'. X-l
9 2.1 PRODUCED SAND SOURCES X-l
12.2 PRODUCED SAND VOLUMES X-2
2.3 PRODUCED SAND CHARACTERIZATION X-4
! 2.4 CONTROL AND TREATMENT TECHNOLOGIES X-6
12.4.1 BPT Technology X-7
w 2.4.2 Additional Technologies X-10
! 3.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS ... . X-ll
13.1 WELL TREATMENT, WORKOVER, AND COMPLETION FLUID
VOLUMES X-ll
3.2 WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS
J CHARACTERISTICS X-14
^ 3.2.1 Well Treatment Fluids . . . X-14
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TABLE OF CONTENTS (Continued)
Page
3.2.2 Workover and Completion Fluids X-16
3.2.3 Chemical Characterization of Well Treatment,
Workover, and Completion Fluids X-19
3.3 WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS
CONTROL AND TREATMENT TECHNOLOGIES X-23
3.3.1 BPT Technology X-23
3.3.2 Additional Technologies Considered X-24
4.0 DECK DRAINAGE . . , X-25
4. L DECK DRAINAGE SOURCES X-25
4.2 DECK DRAINAGE VOLUMES X-25
4.3 DECK DRAINAGE CHARACTERISTICS X-25
4.4 DECK DRAINAGE CONTROL AND TREATMENT TECHNOLOGIES X-28
4.4.1 BPT Technology X-28
4.4.2 Additional Deck Drainage Technologies X-33
5.0 DOMESTIC WASTES X-34
5.1 DOMESTIC WASTES SOURCES X-34
5.2 DOMESTIC WASTES VOLUME AND CHARACTERISTICS X-35
5.3 DOMESTIC WASTES CONTROL AND TREATMENT TECHNOLOGIES X-36
5.3.1 Additional Technologies X-36
6.0 SANITARY WASTES . X-37
6.1 SANITARY WASTES SOURCES, VOLUMES AND CHARACTERISTICS X-37
6.2 SANITARY WASTES CONTROL AND TREATMENT TECHNOLOGIES X-37
7.0 MINOR DISCHARGES X-38
7.1 BLOWOUT PREVENTER (BOP) FLUID . X-39
7.2 DESALINATION UNIT DISCHARGE X-39
7.3 FIRE CONTROL SYSTEM TEST WATER X-39
7.4 NON-CONTACT COOLING WATER X-39
7.5 BALLAST AND STORAGE DISPLACEMENT WATER X-39
7.6 BILGE WATER X-40
7.7 BOILER SLOWDOWN X-40
7.8 TEST FLUIDS X-40
7.9 DlATOMACEOUS EARTH FILTER MEDIA X-40
7.10 BULK TRANSFER OPERATIONS X-41
7.11 PAINTING OPERATIONS X-41
7.12 UNCONTAMINATED FRESHWATER . . X-41
7.13 WATER FLOODING DISCHARGES X-41
7.14 LABORATORY WASTES X-41
7.15 MINOR WASTES VOLUMES AND CHARACTERISTICS X-42
8.0 REFERENCES X-43
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SECTION XI
TABLE OF CONTENTS (Continued)
COST AND POLLUTANT LOADING DETERMINATION-
DRILLING FLUIDS AND DRILL CUTTINGS
1.0 INTRODUCTION ....... ?. .. , X][-l
2.0 OVERVIEW OF METHODOLOGY .... . . . . . . . . XI-1
2.1 CURRENT NPDES PERMIT LIMITATIONS xi-2
3.0 BASIS FOR ANALYSIS AND ASSUMPTIONS .'.'.'.'.['.'.'.'.'. Xl[-3
3.1 DRILLING ACTIVITY .....' xii-3
3.2 DRILLING WASTE VOLUMES xi_3
3.3 DRILLING FLUID CHARACTERISTICS . xi-5
3.4 DRILL CUTTINGS CHARACTERISTICS XI-6
3.5 LUBRICITY XI-6
3.6 STUCK PIPE INCIDENTS . . ....... XI-6
3.7 MINERAL AND DIESEL OIL USAGE XI-6
3.8 BARITE CHARACTERISTICS XI-7
3,9 ONSHORE DISPOSAL VOLUMES/TOXICITY TEST FAILURE RATES . xi-9
3.10 ONSHORE DISPOSAL COSTS OF DRILLING WASTES '.....'. XI-10
3.11 CONTAMINANT REMOVAL XI-12
4.0 BCT OPTIONS CONSIDERED . . . . . ...'.'.'.'.'.'.'.'.'.-.'.'.'. XI-12
4.1 BAT AND NSPS OPTIONS f] XI-14
5.0 OPTION EVALUATIONS XI-16
5.1 BPT AND BPJ BASELINE XI-17
5.1.1 BPT Baseline: Drilling Fluids . . . ........... XI-17
5.1.2 BPT Baseline: Drill Cuttings ........................ XI-18
5.1.3 BPJ Baseline: Drilling Fluids , . . . . . . . XI-19
5.1.4 BPJ Baseline: Drill Cuttings XI-19
5.2 BCT COMPLIANCE COSTS AND POLLUTANT REMOVALS XI-19
5.3 BCT INCREMENTAL COMPLIANCE COSTS AND POLLUTANT
REMOVALS XI-19
5.4 BAT AND NSPS COMPLIANCE COSTS AND LOADINGS XI-20
5.5 BAT AND NSPS INCREMENTAL COMPLIANCE COSTS AND
POLLUTANT REMOVALS XI-20
6.0 BCT .'..';.'.'.';;;;; \;;;;;; v; M-2i
6.1 BCT METHODOLOGY XI-22
6.2 BCT COST TEST CALCULATIONS XI-23
6.2.1 Drilling Fluids .XI-23
6.2.2 Drill Cuttings XI-24
7.0 COST AND CONTAMINANT REMOVAL SUMMARY TABLES """ "" ^^
8:0 REFERENCES ? XI-35
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SECTION XII
COMPLIANCE COST AND POLLUTANT LOADING
DETERMINATION-PRODUCED WATER
TABLE OF CONTENTS (Continued)
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1.0 INTRODUCTION XII-1 I
2.0 BASIS FOR BCT, BAT AND NSPS OPTION EVALUATION XII-1 <
3.0 COMPLIANCE COSTS AND POLLUTANT REMOVAL CALCULATION II
METHODOLOGY XII-2 II
4.0 CAPITAL AND ANNUAL COSTS PER PLATFORM XII-4
4.1.1 Gas Flotation - BAT and NSPS Capital Costs XII-4 1
4.1.2 Gas Flotation - BAT and NSPS Annual Costs XH-6 "^
4.2.1 Granular Filtration - BAT and NSPS Capital Costs XH-6
4.2.2 Granular Filtration Annual Costs - XII-9
4.3.1 Reinjection-BAT and NSPS Capital Costs - XII-10
4.3.2 Reinjection Annual Costs Assumptions XII-12
5.0 REGIONAL AND TOTAL INDUSTRY COSTS XH-12
5.1.1 Gas Flotation - BAT Total Industry and Capital Costs XH-13
5.1.2 Gas Flotation - BAT Annual Costs XH-15
5.1.3 Gas Flotation - NSPS Total Industry Capital Costs XII-16
5.1.4 Gas Flotation - NSPS Total Industry Annual Costs XH-17
5.2 ONSHORE DISPOSAL COSTS XII-17
6.0 BCT OPTIONS CONSIDERED XH-19
7.0 BAT AND NSPS OPTIONS CONSIDERED XH-20
8.0 OPTION EVALUATION XII-21 -.
8.1 BCT, BAT AND NSPS INCREMENTAL COMPLIANCE COSTS XII-21 ||
8.2 BCT, BAT AND NSPS POLLUTANT REMOVALS XII-23
8.2.1 Gas Flotation and Granular Filtration Effluent nrffr
Characterization XII-23 ||
8.2.2 Annual BCT/BAT/NSPS Pollutant Removals XH-25
9.0 BCT COST TEST - XH-28
9.1 BCT COST TEST CALCULATIONS XH-28
10.0 REFERENCES XII-29
SECTION Xffl COMPLIANCE COSTS AND POLLUTANT LOADING
DETERMINATIONPRODUCED SAND
1.0 INTRODUCTION Xffl-1
2.0 PRODUCED SAND GENERATION RATES AND DISPOSAL VOLUMES Xffl-1
3.0 PRODUCED SAND CHARACTERISTICS . Xffl-1
4.0 BPT COMPLIANCE COSTS Xffl-2
4.1 ONSHORE DISPOSAL COSTS XIH-4
4.2 SAND WASHING COSTS . Xffl-4
5.0 BPT POLLUTANT REMOVALS Xffl-6
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6.0. BCT, BAT AND NSPS OPTIONS CONSIDERED Xffl-6
7.0 ZERO DISCHARGE COMPLIANCE COSTS XIII-7
8.0 ZERO DISCHARGE POLLUTANT REMOVALS XIII-9
9.0 BCT/BAT/NSPS INCREMENTAL COSTS AND POLLUTANT REMOVALS . . XIII-9
10.0 BCT COST TEST XHI-10
11.0 REFERENCES XHI-12
SECTION XIV COMPLIANCE COST AND POLLUTANT LOADING
DETERMINATIONWELL TREATMENT, WORKOVER, AND
COMPLETION FLUIDS
1.0 INTRODUCTION XTV-1
2.0 COMPLIANCE COSTS AND POLLUTANT REMOVAL CALCULATION
METHODOLOGY . XIV-1
3.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
GENERATION RATES XIV-1
4.0 BCT REGULATORY OPTIONS XTV-2
5.0 BAT AND NSPS OPTIONS CONSIDERED XIV-2
6.0 INCREMENTAL COST CALCULATIONS . '*..-...'..'.'.'.'. XIV-3
6.1 VOLUMES GENERATED FROM EXISTING STRUCTURES XIV-4
6.2 VOLUMES GENERATED FROM NEW STRUCTURES XIV-4
6.3 STORAGE COSTS XIV-6
6.4 TRANSPORTATION COSTS XIV-6
y 6.5 ONSHORE DISPOSAL COSTS XIV-6
6.6 BAT AND NSPS VOLUMES AND DISPOSAL COSTS XIV-6
7.0 REFERENCES xiV-7
SECTION XV BASIS FOR REGULATION - DECK DRAINAGE
1.0 BCT, BAT AND NSPS OPTIONS CONSIDERED XV-1
SECTION XVI BASIS FOR REGULATION - DOMESTIC WASTE
1.0 BCT, BAT, AND NSPS OPTIONS CONSIDERED XVI-1
SECTION XVII BASIS FOR REGULATION-SANITARY WASTE
1.0 BCT, BAT, AND NSPS OPTIONS CONSIDERED XVH-1
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TABLE OF CONTENTS (Continued)
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SECTION XVin NON-WATER QUALITY ENVIRONMENTAL IMPACTS
AND OTHER FACTORS
1.0 INTRODUCTION XVffl-1
2.0 DRILLING WASTES XVIII-1
2.1 ENERGY REQUIREMENTS AND AIR EMISSIONS XVIII-2
2.1.1 Energy Requirements XVIII-2
2.1.2 Air Emissions XVffl-6
2.1.3 Interaction With OCS Air Regulations XVffl-7
2.2 SOLIDS WASTE GENERATION AND MANAGEMENT XVHI-10
2.2.1 Gulf of Mexico Region XVIH-10
2.2.2 California Region XVffl-12
2.2.3 Alaska Region XVffl-13
2.2.4 Atlantic Region XVffl-14
2.3 CONSUMPTIVE WATER USE XVIU-14
2.4 OTHER FACTORS XVIH-14
2.4.1 Impact of Marine Traffic on Coastal Waterways XVffl-14
2.4.2 Safety XVffl-16
2.4.3 Administrative/Enforcement Considerations XVIH-19
3.0 PRODUCED WATER XVffl-20
3.1 ENERGY REQUIREMENTS AND AIR EMISSIONS XVIII-20
3.1.1 Energy Consumption XVDI-21
3.1.2 Air Emissions ....'. XVffl-25
3.2 UNDERGROUND INJECTION OF PRODUCED WATER XVDI-26
4.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS . XVIH-27
4.1 BAT FUEL REQUIREMENTS AND AIR EMISSIONS XVIH-29
4.2 NSPS FUEL REQUIREMENTS AND AIR EMISSIONS XVffl-30
5.0 REFERENCES XVHI-31
SECTION XIX BEST MANAGEMENT PRACTICES XIX-1
SECTION XX GLOSSARY AND ABBREVIATIONS XX-1
APPENDIX 1 BAT AND NSPS PROFILES OF MODEL PRODUCTION
PLATFORMS
APPENDK2 RAW DATA FOR ESTIMATING POLLUTANT LOADINGS
FOR PRODUCED WATER
LIST OF FIGURES xi
LIST OF TABLES xii
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LIST OF FIGURES
in-l Federal Outer Continental Shelf Region ... . ... ... ni-7
IV-1 Typical Drilling Fluids Circulation System .......... ..... .......... IV-6
IV-2 Typical Completion Methods ,. ...... . . . . . . IV-11
IV-3 Produced Water Treatment System .............................. IV-14
IV-4 Bulk Separator . . . FV-15
Vffl-1 Typical Solids Control System for Drilling Fluids and Drill Cuttings ........ Vffl-2
IX-1 Dispersed Gas Floatation Unit 4"' IX-20
K-2 Typical Skim Pile IX-24
IX-3 Multi-Media Granular Filter IX-33
IX-4 Flow Dynamics of a Crossflow Filter . . K-36
K-5 Module Assembly of Several Multichannel Elements of a Crossflow
Membrane Filter . . . . . . Dt-38
X-l Closed Hole Perforated Completion (With Gravel Pack) ...... . . . . . . . . . . . X-8
X-2 Produced Water Treatment System ........ . . . . ..... X-29
X-3 Shell Western E&P Inc.-Beta Complex Emergency Sump System Flow
Diagram ......' . ......; . . ... . . . . . . X-32
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LIST OF TABLES
Page
'
i-i urronvjj^oui^^v^* ^ , -,, ~~ -
1-2 1985 PROPOSED EFFLUENT LIMITATIONS - PREFERRED OPTIONS 1-6
I-3A 1985 PROPOSED EFFLUENT LIMITATIONS - PREFERRED OPTIONS 1-8 |
I-3B 1985 PROPOSED EFFLUENT LIMITATIONS - PREFERRED OPTIONS . . 1-9 ^
1-4 SUMMARY OF OFFSHORE OIL AND GAS SUBCATEGORY FEDERAL I
REGISTER NOTICES M0
H-l BCT EFFLUENT LIMITATIONS '. . H-4 _,
H-2 BAT EFFLUENT LIMITATIONS H-5 B^
H-3 NSPS EFFLUENT LIMITATIONS H-6
HI-1 SUMMARY OF CURRENT REQUIREMENTS FOR DRILLING FLUIDS |
AND CUTTINGS FOR THE OFFSHORE PERMITS HI-11
W-l OFFSHORE DRILLING ACTIVITY . . .'.. . !V-2 II |
IV-2 . EXISTING STRUCTURES IN OFFSHORE WATERS IV-20
IV-3 AVERAGE ANNUAL NEW WELL DRILLING IV-21
IV-4 TOTAL PROJECTED NEW STRUCTURES - (1993-2007) IV-21 |
V-l GENERIC MUD DESCRIPTIONS V-3
V-2 SUMMARY OF DRILLING FLUIDS ANALYSIS PROGRAM V-5
V-3 PERCENT DIESEL RECOVERED VS QUANTITY OF EXTRA BUFFER
HAULED ASHORE FOR DISPOSAL V'10 n
V-4 SUMMARY OF RESULTS FOR THE VARIABILITY STUDY . V-26 ||
Vn-1 VOLUME OF DRILLING FLUID & CUTTINGS DISCHARGED VH-4
VH-2 ANALYSIS OF TRACE METALS IN BARITE SAMPLES VH-9 ||
VH-3 FUNCTIONS OF COMMON DRILLING FLUID CHEMICAL ADDITIVES . . VH-11
VH-4 GENERIC DRILLING FLUIDS COMPOSITION VH-12
VH-5 POLLUTANT ANALYSIS OF GENERIC DRILLING FLUIDS VH-13 ^
VH-6 ORGANIC POLLUTANTS DETECTED IN GENERIC DRILLING FLUIDS . . VII-15 n
VH-7 METAL CONCENTRATIONS IN GENERIC DRILLING FLUIDS VII-16
VH-8 RESULTS OF ACUTE TOXICITY TESTS WITH GENERIC DRILLING ..
FLUIDS AND MYSIDS (MYSIDOPSIS BAHIA) , VII-17 ||
VH-9 ORGANIC CONSTITUENTS OF DIESEL AND MINERAL OILS VH-18
VH-10 PERCENT OF SAMPLES PASSING BOTH CADMIUM AND MERCURY II
PROPOSED LIMITATIONS ON BARITE . . VH-21 II
Vn-11 PERCENT OF SAMPLES PASSING BOTH CADMIUM AND MERCURY
PROPOSED LIMITATIONS ON DRILLING FLUIDS VH-22 B^
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VII-12 AMOUNT OF BARITE MEETING CADMIUM AND MERCURY
LIMITATIONS - 1985 DATA VII-23
VH-13 COMPARISON OF PROJECTED BARITE NEEDS AND SUPPLIES VH-24
Vm-1 CUTTINGS WASHER TECHNOLOGY . . Vffl-6
IX-1 CHARACTERISTICS OF PLATFORMS SELECTED FOR THE 30
PLATFORM STUDY IX-3
IX-2 CHARACTERISTICS OF FACILITIES SELECTED FOR THE
CALIFORNIA SAMPLING PROGRAM , IX-4
IX-3 CHARACTERISTICS OF FACILITIES SELECTED FOR THE ALASKA
SAMPLING PROGRAM IX-4
IX-4 BAT PRODUCED WATER GENERATION RATES - 4 MILE PROFILE IX-5
IX-5 BAT PRODUCED WATER GENERATION RATES - 3 MILE PROFILE IX-5
IX-6 NSPS PRODUCED WATER GENERATION RATES - 3 MILE PROFILE IX-5
IX-7 NSPS PRODUCED WATER GENERATION RATES - 4 MILE PROFILE IX-6
IX-8 PERCENT OCCURRENCE OF ORGANICS FOR TREATED EFFLUENT
SAMPLES 30 PLATFORM STUDY IX-7
IX-9 POLLUTANT CONCENTRATIONS IN BPT TREATED PRODUCED
WATER FROM THE THIRTY PLATFORM STUDY IX-8
IX-10 AVERAGE EFFLUENT COMPOSITION OBTAINED FROM THE 1982
CALIFORNIA SAMPLING PROGRAM IX-9
EX-11 PRIORITY POLLUTANT DETECTION RATES IN FILTER TREATED
PRODUCED WATER FROM THE THREE-FACILITY STUDY IX-10
IX-12 PRODUCED WATER POLLUTANT CONCENTRATIONS IN FILTER
INFLUENT FROM THREE FACILITY STUDY IX-11
IX-13 AVERAGE EFFLUENT CONCENTRATIONS OBTAINED FROM THE
1982 ALASKA SAMPLING PROGRAM IX-12
IX-14 AVERAGE EFFLUENT CONCENTRATIONS FROM PRODUCED
WATER IN COOK INLET DMR DATA IX-13
IX-15 1992 BPT EFFLUENT DATA IX-14
IX-16 GRANULAR MEDIA FILTRATION PERFORMANCE IX-35
IX-17 MEMBRANE FILTRATION PERFORMANCE DATA FROM THE
MEMBRANE FILTRATION STUDY IX-39
X-l SUMMARY OF RESULTS OF OOC PRODUCED SAND SURVEY X-3
X-2 AVERAGE OIL CONTENT IN PRODUCED SAND X-5
X-3 SUMMARY OF RADIONUCLIDE DATA FOR PRODUCED SAND
FROM OOC SURVEY ... X-5
X-4 AVERAGE RADIOACTIVITY LEVELS IN PRODUCED SAND X-6
Xlll
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LIST OF TABLES (Continued)
X-5 TYPICAL VOLUMES FROM WELL TREATMENT, WORKOVER, AND
COMPLETION OPERATIONS X-12
X-6 SURVEY OF WELL SERVICING ACTIVITY X-13
X-7 DATA ON ACIDIZING IN THE GULF OF MEXICO X-13
X-8 VOLUMES DISCHARGED DURING WORKOVER, COMPLETION, AND
WELL TREATMENT OPERATIONS FROM THE COOK INLET DMR
STUDY X-14
X-9 WELL TREATMENT CHEMICALS X-15
X-10 COMMON BRINE SOLUTIONS USED IN WORKOVER AND
COMPLETION OPERATIONS X-17
X-ll ADDITIVES TO COMPLETION AND WORKOVER FLUIDS X-18
X-12 ANALYTICAL RESULTS FROM THE COOK INLET DISCHARGE
MONITORING STUDY X-20
X-13 ANALYSIS OF FLUIDS FROM AN ACIDIZING WELL TREATMENT X-21
X-14 METALS ANALYSIS OF A FRACTURING FLUID X-22
X-15 VOLUMES OF DECK DRAINAGE FROM OFFSHORE RIGS IN THE
GULF OF MEXICO X-25
X-16 CHARACTERISTICS OF DECK DRAINAGE FROM OFFSHORE
PLATFORMS X-26
X-17 POLLUTANT CONCENTRATIONS IN UNTREATED DECK DRAINAGE X-27
X-18 DATA FROM SUMP EFFLUENT TAKEN AT THUMS ISLAND
GRISSOM FACILITY X-28
X-19 DATA FROM DECK DRAINAGE TAKEN AT SHELL BETA COMPLEX X-28
X-20 GARBAGE DISCHARGE RESTRICTIONS X-35
X-21 TYPICAL UNTREATED COMBINED SANITARY AND DOMESTIC
WASTES FROM OFFSHORE FACILITIES X-36
X-22 TYPICAL OFFSHORE SANITARY AND DOMESTIC WASTE
CHARACTERISTICS X-36
X-23 MINOR WASTE DISCHARGE VOLUMES X-42
XI-1 NUMBER OF WELLS DRILLED PER YEAR XI-3
XI-2 MODEL WELL CHARACTERISTICS XI-4
XI-3 DRILLING FLUIDS COMPOSITION XI-5
XI-4 MINERAL AND DIESEL OIL USAGE XI-7
XI-5 ORGANIC CONSTITUENTS IN MINERAL OIL TYPE A XI-7
XI-6 METALS CONCENTRATIONS IN BARITE XI-9
XI-7 TOXICITY/STATiC SHEEN TEST FAILURE RATES XI-10
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LIST OF TABLES (Continued)
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XI-8 DRILL WASTE ONSHORE DISPOSAL COSTS . . XI-11
XI-9 DIRECT AND INDIRECT POLLUTANTS AS DEFINED BY THIS
RULEMAKING . . , . XI-12
XI-10 INDUSTRY-WIDE DRILLING ASSUMPTIONS XI-17
XI-11 ANNUAL INCREMENTAL.COMPLIANCE COSTS/POLLUTANT
REDUCTIONS FOR REGULATORY OPTIONS - DRILLING FLUIDS XI-21
XI-12 ANNUAL INCREMENTAL COMPLIANCE COSTS/POLLUTANT REDUCTIONS
FOR REGULATORY OPTIONS - DRILL CUTTINGS XI-21
XI-13 BCT COST TEST RESULTS FOR DRILLING FLUIDS XI-24
XI-14 BCT COST TEST RESULTS FOR DRILL CUTTINGS . XI-25
XI-15 REGULATORY OPTIONS AND CORRESPONDING ANALYSIS
DIRECTORY . xi-26
XI-16 BPT BASELINE: DRILLING FLUIDS , XI-27
XI-17A ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
BPJ BASELINE . XI-27
XI-17B ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
(3 MILE PROFILE) , .XI-28
XI-17C ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
(8/3 MILE PROFILE) XI-28
XI-17D ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
ZERO DISCHARGE . . . . .- XI-29
XI-17E ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
(4 MILE PROFILE) - XI-29
XI-17F ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
(6 MILE PROFILE) . . XI-30
XI-17G ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
(8 MILE PROFILE) XI-30
XI-18A BPT BASELINE: DRILL CUTTINGS ....... ... XI-31
XI-18B ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS
(3 MILE PROFILE) . .XI-32
XI-18C ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS
(8/3 MILE PROFILE) XI-32
XI-18D ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS
ZERO DISCHARGE xi-33
XI-18E ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS
(4 MILE PROFILE) . . . . XI-33
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LIST OF TABLES (Continued)
XI-18F ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS
(6 MILE PROFILE) Xl-34
XI-18G ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS
(8 MILE PROFILE) XI-34
XH-1 COST DATA FOR GAS FLOTATION - EXISTING PLATFORMS (BAT) XH-5
XH-2 COST DATA FOR GAS FLOTATION - NEW PLATFORMS (NSPS) . XII-5
XII-3 COST DATA FOR GRANULAR FILTRATION - EXISTING PLATFORMS
(BAT) XII-7
XE-4 COST DATA FOR GRANULAR FILTRATION - NEW PLATFORMS
(NSPS) XII-7
XH-5 BACKWASH AND SLUDGE VOLUMES GENERATED FROM MULTI-
MEDIA FILTRATION XH-10
Xfl-6 COST DATA FOR REINFECTION - EXISTING PLATFORMS (BAT) XH-11
Xtt-7 COST DATA FOR REINJECTION - NEW PLATFORMS XII-11
XH-8 BAT ONSHORE TREATMENT CAPITAL COSTS XH-18
XH-9 BAT ONSHORE TREATMENT ANNUAL COSTS XH-18
Xfl-10 BAT - GULF OF MEXICO ONSHORE COMPLIANCE COSTS: 3 MILE
PROFILE XH-19
Xn-11 BAT - GULF OF MEXICO ONSHORE COMPLIANCE COSTS: 4 MILE
PROFILE XH-19
XH-12 SUMMARY OF INCREMENTAL COSTS AND CONTAMINANT
REMOVAL -BAT XH-22
XH-13 SUMMARY OF INCREMENTAL COMPLIANCE COSTS AND
CONTAMINANT REMOVAL-NSPS . XII-22
XH-14 TOTAL OIL AND GREASE VARIATION ESTIMATES PHYSICAL
COMPOSITING - SCREENED FOR BPT COMPLIANCE XH-23
XH-15 POLLUTANT LOADING CHARACTERIZATION PRODUCED
WATER XH-24
XH-16 ANNUAL PRODUCED WATER DISCHARGES XII-25
XH-17 BAT ANNUAL REGIONALIZED POLLUTANT REMOVALS . . . . - XII-26
Xn-18 NSPS ANNUAL REGIONALIZED POLLUTANT REMOVALS XII-27
XH-19 PRODUCED WATER BCT COST TEST XH-28
Xffl-1 PRODUCED SAND GENERATION VOLUMES AND BPT DISPOSAL
PRACTICES Xin-2
Xm-2 PRODUCED SAND CHARACTERISTICS XHI-2
Xm-3 BPT COMPLIANCE COSTS XHI-3
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LIST OF TABLES (Continued)
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Xm-4 BPT POLLUTANT REDUCTIONS XHI-7
XHI-5 ZERO DISCHARGE DISPOSAL COSTS . Xffl-8
XIII-6 BCT/BAT/NSPS POLLUTANT REDUCTIONS . XIH-9
XHI-7 ZERO DISCHARGE INCREMENTAL COMPLIANCE COSTS AND
POLLUTANT REMOVALS XHI-10
Xm-8 BCT COST TEST PRODUCED SAND XIH-11
XIV-1 TOTAL BAT WORKOVER AND TREATMENT VOLUME GENERATION
ESTIMATES XIV_4
XIV-2 NSPS WORKOVER AND COMPLETION SCHEDULE VOLUME
ESTIMATES, DISPOSAL COSTS XIV-5
XVffl-1 AIR EMISSIONS AND ENERGY REQUIREMENTS FOR DISPOSAL
DRILLING FLUIDS AND DRILL CUTTINGS XVIH-2
XVIII-2 UNCONTROLLED AND CONTROLLED EMISSION FACTORS XVIH-7
XVIH-3 PRIMARY CAUSES AND CLASSIFICATION OF ACCIDENTS ON
MODUS AND OSVS _ XVHI-18
XVHI-4 NON-WATER QUALITY ENVIRONMENTAL IMPACTS PRODUCED
WATFR v,^*^
WA1ฃ1K XVIH-21
XVIH.-5 FUEL REQUIREMENTS FOR GAS FLOTATION UNITS XVHI-22
XVIH-6 FUEL REQUIREMENTS FOR GRANULAR FILTRATION UNITS .... . . XVHI-23
XVIH-7 FUEL REQUIREMENTS AND USAGE FOR CENTRIFUGE . . XVffl-24
XVHI-8 FUEL REQUIREMENTS FOR INJECTION PUMPS . . .......... XVHI-24
XVIII-9 EMISSION FACTORS FOR NATURAL GAS-FIRED TURBINES XVffl-25
XVHI-10 AIR EMISSIONS FOR GAS FLOTATION UNITS . XVHI-25
XVm-11 AIR EMISSIONS FOR GRANULAR FILTRATION SYSTEMS XVIH-26
XVffl-12 AIR EMISSIONS FOR REINJECTION PUMPS XVffl-27
XVm-13 EMISSION FACTORS FOR DIESEL POWERED INDUSTRIAL
EQUIPMENT XVU^g
XVm-14 BAT DIESEL FUEL REQUIREMENTS . . . XVIM-29
XVm-15 BAT AIR EMISSION RATES FOR WORKOVER AND TREATMENT
FLUIDS - xvm-29
XVffl-16 NSPS DIESEL FUEL REQUIREMENTS XVffl-30
XVm-17 NSPS AIR EMISSION RATES FOR TWC FLUIDS XVffl-30
XVII
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SECTION I
INTRODUCTION
1.0 LEGAL AUTHORITY
The Environmental Protection Agency (EPA) is establishing these final Effluent Limitations
Guidelines and New Source Performance Standards for the Offshore Subcategory of the Oil and Gas
Extraction Point Source Category under the authority of Sections 301, 304 (b), (c), and (e), 306, 307,
308, and 501 of the Clean Water Act (CWA) (the Federal Water Pollution Control Act Amendments of
1972, as amended by the Clean Water Act of 1977 and the Water Quality Act of 1987); 33 U.S.C. 1311,
1314 (b), (c), and (e), 1315, 1317, and 1361; 86 Stat. 816, Pub. L. 92-500; 91 Stat. 1567, Pub. L. 95-
217; and 101 Stat. 7, Pub. L. 100-4).
1.1 BACKGROUND
1.1.1 Clean Water Act
The CWA establishes a comprehensive program to "restore and maintain the chemical, physical,
and biological integrity of the Nation's waters" (Section 101(a)). To implement the CWA, EPA is to
issue technology based effluent limitations guidelines, new source performance standards and pretreatment
standards for industrial dischargers. The levels of control associated with these effluent limitations
guidelines and the new source performance standards for direct dischargers are summarized briefly below.
Since no offshore facilities currently discharge into publicly owned treatment works (POTW),
pretreatment standards are not included hi this rulemaking and are reserved.
1. Best Practicable Control Technology Currently Available (BPT)
BPT effluent limitations guidelines are generally based on the average of the best existing
performance by plants of various sizes, ages, and unit processes within the industrial category or
subcategory.
In establishing BPT effluent limitations guidelines, EPA considers the following criteria: (1) total
cost of achieving effluent reductions hi relation to the effluent reduction benefits, (2) the age of equipment
and facilities involved, (3) the processes employed, (4) the process changes required, (5) the engineering
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aspects of the control technologies, (6) the non-water quality environmental impacts (including energy
requirements), and (7) other factors as the EPA Administrator deems appropriate (Section 304(b)(l)(B)
of the CWA). EPA considers the category- or subcategory-wide cost of applying the technology in
relation to the effluent reduction benefits. Where existing performance is uniformly inadequate, BPT may
be transferred from a different subcategory or category.
2. Best Available Technology Economically Achievable (BAT)
In general, BAT effluent limitations guidelines represent the best existing economically achievable
performance of plants hi the industrial subcategory or category. The CWA establishes BAT as a principal
national means of controlling the direct discharge of priority pollutants and nonconventional pollutants
to navigable waters. The factors considered in assessing BAT include the following: (1) the age of the
equipment and facilities involved, (2) the processes employed, (3) the engineering aspects of the control
technologies, (4) potential process changes, (5) the costs and economic impact of achieving such effluent
reduction, (6) non-water quality environmental impacts (including energy requirements, Section
304(b)(2)(B), and (7) other factors as the EPA Administrator deems appropriate. EPA retains
considerable discretion in assigning the weight to be accorded these factors. As with BPT, where existing
performance is uniformly inadequate, BAT may be transferred from a different subcategory or category.
BAT may include process changes or internal controls, even when these technologies are not common
industry practice.
3. Best Conventional Pollutant Control Technology (BCT)
The 1977 Amendments added Section 301(b)(2)(E) to the CWA establishing "best conventional
pollutant control technology" (BCT) for the discharge of conventional pollutants from existing industrial
point sources. Section 304(a)(4) designated the following as conventional pollutants: biochemical oxygen
demand (BOD5), total suspended solids (TSS), fecal coliform, pH, and any additional pollutants defined
by the Administrator as conventional. The Administrator designated oil and grease as an additional
conventional pollutant on July 30, 1979 (44 FR 44501).
BCT is not an additional limitation, but replaces BAT for the control of conventional pollutants.
Where the BCT limitations differ from the BAT limitations, the more stringent of the limitations apply.
In addition to other factors specified hi section 304(b)(4)(B), the CWA requires that BCT effluent
limitations guidelines be established in light of a two-part "cost-reasonableness" test (American Paper
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Institute v. EPA, 660 F.2d 954 (4th Cir. 1981)). The methodology for establishing BCT effluent
limitations guidelines became effective on August 22, 1986 (51 FR 24974, July 8, 1986).
4. New Source Performance Standards (NSPS)
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. 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. 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.,
conventional, nonconventional, and priority pollutants). In establishing NSPS, EPA is directed to fake
into consideration the cost of achieving the effluent reduction and any non-water quality environmental
impacts and energy requirements.
1.1.2 Section 304(m) Requirements and Litigation
Section 304(m) of the CWA (33 U.S.C. 1314(m)), added by the Water Quality Act of 1987,
requires EPA to establish schedules for (1) reviewing and revising existing effluent limitations guidelines
and standards (effluent guidelines), and (2) promulgating new effluent guidelines. On September 8,1992,
EPA published an Effluent Guidelines Plan (57 FR 41000), in which schedules were established for
developing new and revised effluent guidelines for several industry subcategories and categories. One
of the industries for which EPA established a schedule was the offshore subcategory of the oil and gas
extraction point source category (offshore subcategory). Although referenced in the Effluent Guidelines
Plan under Section 304(m), the offshore guidelines are not subject to the Consent Decree that EPA
entered into in the 304(m) litigation.
1.1.3 Pollution Prevention Act
In the Pollution Prevention Act of 1990 (42 U.S.C. 13101 et seq., Pub.l. 101-508, November
5, 1990), Congress declared pollution prevention the national policy of the United States. This act
declares that pollution should be prevented or reduced whenever feasible; pollution that cannot be
prevented should be recycled or reused in an environmentally safe manner wherever feasible; pollution
that cannot be recycled should be treated; and disposal or release into the environment should be chosen
only as a last resort.
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1.1.4 Prior Regulation and Litigation for the Offshore Subcategory
On September 15, 1975, EPA 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.
EPA promulgated final BPT regulations on April 13, 1979 (44 FR 22069), but deferred action on the
BAT and NSPS regulations. Table 1-1 presents the 1979 BPT limitations.
TABLE 1-1
OFFSHORE SUBCATEGORY BPT EFFLUENT LIMITATIONS*
Waste Stream, \
Produced Water
Drilling Muds
Drilling Fluids
Well Treatment Fluids
Deck Drainage
Sanitary-MlO
Sanitary-M9IM
Parameter
Oil and Grease
Free Oil*
Free Oil*
Free Oil*
Free Oil*
Residual Chlorine
Floating Solids
BPT Effluent Limitation
72 mg/1 Daily Maximum
48 mg/1 30-Day Average
No Discharge
No Discharge
No Discharge
No Discharge
1 mg/1 (minimum)
No Discharge
*The free oil "no discharge" limitation is implemented by requiring no oil sheen to be present upon
discharge.
The Natural Resources Defense Council (NRDC) filed suit on December 29, 1979 seeking an
order to compel the U.S. EPA Administrator to promulgate final NSPS for the offshore subcategory.
In settlement of the suit (NRDCv. Costle, C.A. No. 79-3442 (D.D.C.)), EPA acknowledged the statutory
requirement and agreed to take steps to issue such standards. However, because of the length of time
that had passed since proposal, EPA believed that examination of additional data and reproposal were
necessary. Consequently, EPA withdrew the proposed NSPS on August 22, 1980 (45 FR 56115). The
proposed BAT regulations were withdrawn on March 19, 1981 (46 FR 17567).
On August 26, 1985 (50 FR 34592) EPA proposed BAT and BCT effluent limitations guidelines,
and new source performance standards for the offshore subcategory. This 1985 proposal also included
an amendment to the BPT definition of "no discharge of free oil." The waste streams covered by the
1985 proposal were drilling fluids, drill cuttings, produced water, deck drainage, well treatment fluids,
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produced sand, and sanitary and domestic wastes. Table 1-2 provides a summary of the preferred options
as proposed in 1985.
On October 21, 1988, EPA issued a Notice of Data Availability (53 FR 41356) concerning the
development of NSPS, BAT, and BCT regulations for the drilling fluids and drill cuttings waste streams.
This 1988 notice presented substantial additional and revised technical, cost, economic, and environmental
effects information which EPA collected after publication of the 1985 proposal.
EPA presented new information regarding the diesel oil prohibition and the toxicity limitation,
and new compliance costing and economic analysis results 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, EPA proposed requirements for limitations on metals content in the stock barite based on the
use of existing barite supplies, or alternatively in the drilling fluids (whole fluid basis) at point of
discharge, for comment.
On January 9, 1989, EPA published a Correction to Notice of Data-Availability (54 FR 634)
concerning the analytical method for the measurement of oil content and diesel oil because the 1988
notice had inadvertently published an incomplete version of that method.
On November 26, 1990, EPA published a notice as 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 and sanitary
wastes, and well treatment, completion, and workover fluids. On March 13, 1991 (56 FR 10664), EPA
published a second notice proposing BAT, BCT, and NSPS limitations and standards for the offshore
subcategory. The regulatory options presented were the same as those proposed on November 26, 1990
with the exception of the deletion of a requirement under NSPS which prohibited the discharge of visible
foam from the sanitary waste stream (this requirement had been inadvertently included in the November
1990 proposal).
The 1990 and 1991 proposals did not supersede the 1985 proposal or the information included
in the 1988 and 1989 notices. Rather, they revised the 1985 proposal in certain areas. The revisions
were based on new data and information acquired by EPA since the 1985 proposal regarding waste
characterization, treatment technologies, industrial practices, industry profiles, analytical methods,
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environmental effects, costs, and economic impacts. Some of this new information regarding drilling
wastes had been published in a Notice of Data Availability (53 FR 41356, Oct. 21, 1988). This new
information led EPA to develop additional regulatory options to those proposed in 1985. Table 1-3
presents a summary of the preferred options as proposed in 1991.
The Consent Decree was revised on May 28, 1992. Under this modification, the date for
promulgation of the final effluent limitations guidelines and standards (BCT, BAT, and NSPS) for
produced water, drilling fluids and drill cuttings, well treatment fluids, and produced sand waste streams
was extended from June 19, 1992 to January 15, 1993.
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.
In addition, EPA has issued a series of general NPDES permits that set BAT and BCT limitations
applicable to sources in the offshore subcategory on a Best Professional Judgment (BPJ) basis under
Section 402(a)(l) of the CWA. These permits include the following: Western Gulf of Mexico General
Permit (57 FR 54642, November 19, 1992); Gulf of Mexico General Permit (51 FR 24897, July 9,
1986); Bering and Beaufort Seas General Permit (49 FR 23734, June 7, 1984 modified 52 FR 30481,
September 29, 1987); Norton Sound General Permit (50 FR 23570, June 4, 1985); Cook Inlet/Gulf of
Alaska General Permit (51 FR 35400, October 3, 1986); and Beaufort Sea H/Chukchi Sea General
Permit (53 FR 37840, September 20,1988 modified 54 FR 39574, September 27,1989). The rulemaMng
record for this final rule includes copies of the most significant Federal Register notices proposing these
general permits and issuing them in final form. -
Table 1-4 presents a summary of the Federal Register Notices that pertain to this rulemaking.
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TABLE 1-4
SUMMARY OF OFFSHORE OIL AND GAS SUBCATEGORY
FEDERAL REGISTER NOTICES
Level of Control
BPT
BAT/NSPS
BPT/BAT/NSPS
NSPS
BAT
BAT/BCT/NSPS
BAT/BCT/NSPS
BAT/BCT/NSPS
BAT/BCT/NSPS
BAT/BCT/NSPS
Action
Interim Final
Proposal
Final (BPT)
Reserved (BAT/NSPS)
Withdraw Proposal
Withdraw Proposal
Proposal
Notice of Data Availability
(Drilling Muds & Cuttings)
Correction to Notice of Data
Availability
Initial Proposal
Reproposal
Proposal
Date
^g^gg^gggffl^jflfai^mmffMmmmsaimB!.mimJliyJ
Sept. 15, 1975
(40 FR 42543)
Sept. 15, 1975
(40 FR 42572)
April 13, 1979
(44 FR 22069)
August 22, 1980
(45 FR 561 15)
March 19, 1981
(46 FR 17567)
August 26, 1985
(50 FR 34592)
October 21, 1988
(53 FR 41356)
January 9, 1989
(54FR634)
November 26, 1990
(55 FR 49094)
March 13, 1991
(56 FR 10664)
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SECTION II
SUMMARY OF THE FINAL REGULATIONS
1.0 INTRODUCTION
The processes and operations which comprise the offshore oil and gas extraction subcategory
(Standard Industrial Classification (SIC) Major Group 13) are currently regulated under 40 CFR 435,
Subpart A. The existing effluent limitations guidelines, which were issued on April 13, 1979 (44 FR
22069), are based on the achievement of BPT.
1.1 BPT LIMITATIONS
In general, BPT represents the average of the best existing performances of well-known
technologies and techniques for the control of pollutants. BPT for the offshore subcategory accomplishes
the following: (1) limits the discharge of oil and grease hi produced water to a daily maximum of 72 mg/1
and a monthly average of 48 mg/1; (2) prohibits the discharge of free oil in deck drainage, drilling fluids,
drill cuttings, and well treatment fluids; (3) requires a minimum residual chlorine content of 1 mg/1 in
sanitary discharges; and-(4) prohibits the discharge of .floating solids hi sanitary and domestic wastes.
BPT effluent limitations are not being changed by this rule. A summary of the BPT effluent limitations
is presented in Table 1-1 in Section 1.1.1,4.
1.2 SUMMARY OF THE FINAL RULE
This rule establishes regulations based on BAT that will result in reasonable progress toward the
goal of the CWA to eliminate the discharge of all pollutants. At a minimum, BAT represents the best
economically achievable performance in the industrial category or subcategory. This rule also establishes
requirements based on BCT. In addition, this rule establishes NSPS based on the best demonstrated
control technology.
This section summarizes the BCT, BAT, and NSPS limitations for the final rule by classifying
the regulated waste stream as either a major waste stream or a miscellaneous waste stream. Produced
water, drilling fluids, and drill cuttings are classified as major waste streams. Deck drainage, produced
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sand, well treatment, workover, and completion fluids, sanitary wastes, and domestic wastes are classified
as miscellaneous wastes.
1.2.1 BAT and NSPS for Major Waste Streams
Under this rule, EPA is promulgating the following NSPS and BAT effluent limitations guidelines
for the offshore subcategory. This rule limits the discharge of oil and grease in produced water to a daily
maximum of 42 mg/1 and a monthly average of 29 mg/1 based on unproved operating performance of gas
flotation technology. For this rulemaking, oil and grease is being limited as an indicator for toxic and
nonconventional pollutants. Furthermore, EPA is prohibiting the discharge of drilling fluids and drill
cuttings from wells located within 3 nautical miles from shore (the inner boundary of territorial seas).
For wells located beyond 3 nautical miles from shore, this rule establishes BAT and NSPS limitations for
discharges of drilling fluids and drill cuttings of toxicity equal to or greater than 30,000 ppm (three
percent by volume) in the suspended paniculate phase (SPP), cadmium and mercury in stock barite at 3
mg/kg and 1 mg/kg, respectively, on a dry weight basis. This rule also prohibits the discharge of diesel
oil and prohibits the discharge of free oil as determined by the static sheen test. All wells drilled off the
Alaskan coast are excluded from the zero discharge limitation; instead, all discharges of drilling fluids
and drill cuttings must comply with the limitations on toxicity, cadmium, and mercury, and the
prohibitions on the discharge of free oil and diesel oil.
1.2.2 BAT AND NSPS for Miscellaneous Waste Streams
EPA is promulgating BAT and NSPS limitations equal to BPT limitations for deck drainage.
These limitations prohibit the discharge of free oil as determined by the visual sheen test. Discharges
of produced sand are prohibited under the BAT and NSPS effluent limitation of this rule. For treatment,
completion, and workover fluids, this rule establishes BAT and NSPS limits on the discharge of oil and
grease to 29 mg/1 monthly average and 42 mg/1 daily maximum (equal to those of produced water). EPA
is promulgating limitations on domestic waste prohibiting the discharge of foam (BAT and NSPS) and
floating solids (BCT and NSPS), as well as incorporating MARPOL (International Convention for
Prevention of Pollution from Ships) limitations which prohibit all discharges of plastics and garbage, ban
discharge of victual waste within 12 nautical miles of nearest land, and require that victual waste
discharged more than 12 nautical miles from nearest land must be comminuted or ground (BCT and
NSPS). For sanitary wastes, EPA is promulgating BCT and NSPS limitations equal to BPT limitations.
These limitations prohibit the discharge of floating solids from facilities with 9 or fewer personnel and
require a minimum chlorine content of 1 mg/1 for facilities with 10 or more personnel. EPA is not
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estabttskuivg BAT for sanitary wastes because there have been no toxic or nonconventipnal pollutants of
concern identified in these wastes.
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1.2.3 BCT for Major and Miscellaneous Waste Streams
BCT for produced water is equal to current BPT limitations. EPA is establishing BCT limitations
for drilling fluids and drill cuttings equal to the zero discharge portion of BAT for distances of 3 nautical
miles or less from shore, and no discharge of free oil, as determined by the static sheen test, for wells
drilled at distances greater than 3 nautical miles from shore. Discharges of produced sand are prohibited
under BCT. BCT limitations for well treatment, completion, and workover fluids prohibit the discharge
of free oil as determined by the static sheen test. EPA is establishing BCT limits on deck drainage that
prohibit discharge of free oil, as determined by the visual sheen test.
1 .2.4 BCT, BAT and NSPS Summary Tables for the Final Rule
Table II-l presents a summary of the BCT limitations for the final rule; Table n-2 presents a
summary of the BAT limitations for the final rule; and Table U-3 presents a summary of the NSPS
limitations for the final rule.
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TABLE II-l
BCT EFFLUENT LIMITATIONS
Stream
Produced Water
(all facilities)
Drilling Fluids and
Drill Cuttings
A) Facilities located
within 3 miles from
shore.
B) Facilities located
beyond 3 miles from
shore.
Well Treatment,
Completion, and
Workover Fluids
Produced Sand
Deck Drainage
Sanitary Waste
Sanitary M10
Sanitary M91M
Domestic Waste
Pollutant Parameter
Oil & Grease
Free Oil
Free Oil
Free Oil
Residual Chlorine
Floating Solids
Floating Solids and
MARPOL Limits
BCT Effluent Limitations
No discharge if the maximum for any one
72 mg/1 and the monthly average exceeds
day exceeds
48 mg/1
No discharge0'
No dischargeฎ
No dischargeฎ
No discharge
No dischargeฎ
No discharge if minimum of 1 mg/1 is not maintained
No discharge
No discharge of Floating Solids
(1) Alaskan facilities are exempt from "No discharge" limitation. They are required to comply with die
same discharge limitations as facilities located beyond 3 miles from shore.
(2) As determined by the Static Sheen Test
(3) As determined by the Visual Sheen Test
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TABLE H-2
BAT EFFLUENT LIMITATIONS
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Stream
Produced Water
(all facilities)
Drilling Fluids and
Drill Cuttings
A) Facilities located
within 3 miles
from shore.
B Facilities located
beyond 3 miles
from shore.
Well Treatment,
Completion, and
Workover Fluids
Produced Sand
Deck Drainage
Sanitary Waste
Sanitary M10
Sanitary M91M
Domestic Waste
Pollutant Parameter
Oil & Grease
Toxicity
Free Oil
Diesel Oil
Mercury
Cadmium
Oil & Grease
Free Oil
None
None
Foam
BAT Effluent Limitations
No discharge if the maximum for any one day
exceeds 42 mg/1, and the monthly average exceeds 29
mg/1
No discharge0*
No discharge if minimum 96-hour LC50 of SPP is
not at 3 % by volume
No dischargeฎ
No discharge
1 mg/kg dry weight maximum in stock barite
3 mg/kg dry weight maximum in stock barite
Same as produced water
No discharge
No dischargeฎ
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No discharge
(1) .Alaskan facilities are exempt from "No discharge" limitation. They are required to comply with the
same discharge limitations as facilities located beyond 3 miles from shore.
(2) As determined by the Static Sheen Test
(3) As determined by the Visual Sheen Test
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TABLE II-3
NSPS EFFLUENT LIMITATIONS
Stream
Produced Water
(all facilities)
Drilling Fluids and
Drill Cuttings
A) Facilities located within 3
miles from shore.
8) Facilities located beyond 3
miles from shore.
Well Treatment, Completion,
and Workover Fluids
Produced Sand
Deck Drainage
Sanitary Waste
Sanitary M10
Sanitary M91M
Domestic Waste
Pollutant Parameter
Oil & Grease
Toxicity
Free Oil
Diesel Oil
Mercury
Cadmium
Oil & Grease
Free Oil
Residual Chlorine
Floating Solids
Floating Solids &
MARPOL Limits
Foam
NSPS Effluent Limitations
No discharge if the maximum for any
one day exceeds 42 mg/1, and the
monthly average exceeds 29 mg/1
No discharge0*
No discharge if minimum 96-hour LC50
of SPP is not at 3 % by volume
No dischargeฎ
No discharge
1 mg/kg dry weight maximum in stock
barite
3 mg/kg dry weight maximum in stock
barite
Same as produced water
No discharge
No discharge3'
No discharge if minimum of 1 mg/1, is
not maintained
No discharge
No discharge of floating solids
No discharge
(1) Alaskan facilities are exempt from "No discharge" limitation.
same discharge limitations as facilities located beyond 3 miles
(2) As determined by the Static Sheen Test
(3) As determined by the Visual Sheen Test
They are required to comply with the
from shore.
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SECTION III
INDUSTRY SUBCATEGORIZATION
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1.0 INTRODUCTION ,
This section describes the offshore subcategory by (1).regulatory definition, (2) geographic
locations, ,and (3) classification of the major, miscellaneous, and minor waste streams. :
2.0 REGULATORY DEFINITION
The offshore subcategory of the oil and gas extraction point source category, as defined in 40
CFR 435.10, is comprised of those structures involved in exploration, development, and production
operations seaward of the inner boundary of the territorial seas (shoreline). This rulemaking covers
offshore activities included in the following SICs: 1311-Crude Petroleum and Natural Gas, 1381-Drilling
Oil and Gas Wells, 1382-Oil and Gas Field Exploration Services, and 1389-Oil and Gas Field Services,
not classified elsewhere.
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Structures are 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 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."
In some areas, the inner boundary of the territorial seas is clearly established and shown on maps.
For example, the Texas General Land Office (Survey Division) has 7.5 minute quadrangle maps available
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 maps available for
the Louisiana coastline showing the inner boundary of the territorial seas. In general, for Louisiana the
inner boundary consists of the coastline or the seaward edge of the outermost barrier islands where there
are bays', inlets, and bayous. The inner boundary for California extends from the mainland coast or the
seaward edge of all offshore islands. "In Alaska, the inner boundary 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 CWA sets out criteria requiring a determination of whether or mot
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the discharge will cause degradation of these waters. The State Department is consulted to make site-
specific determinations when it is questionable whether or not the discharge is beyond the baseline
(Section 403(c)).
2.1 NEW SOURCE DEFINITION
The definition of "new source" as it applies to the Offshore Guidelines was discussed at length
in EPA's 1985 proposal, 50 FR 34617-34619, Aug. 26, 1985. As discussed in that proposal, provisions
in the NPDES regulations define new source (40 CFR 122.2) and establish criteria for a new source
determination (40 CFR 122.29(b)). In 1985, EPA proposed special definitions which are consistent with
40 CFR 122.29 and which provide that 40 CFR 122.2 and 122.29(b) shall apply "except as otherwise
provided in an applicable new source performance standard." (See 49 FR 38046, Sept. 26, 1984.)
The Offshore Guidelines apply to all mobile and fixed drilling (exploratory and development) and
production operations. In 1985, EPA addressed the question of which of these facilities are new sources
and which are existing sources under these guidelines.
As discussed in 1985, Section 306(a)(2) of the Act defines "new source" to mean "any source,
the construction of which is commenced after publication of the proposed NSPS if such standards are
promulgated consistent with Section 306." The CWA defines "source" to mean any "facility , . . from
which there is or may be a discharge of pollutants" and "construction" to mean "any placement,
assembly, or installation of facilities or equipment... at the premises where such equipment will be
used."
The regulations implementing this provision state, in part:
"New Source means any building structure, facility, or installation from which there is or may
be a 'discharge of pollutants,' the construction of which is commenced:
(a) After promulgation of standards of performance under section 306 of the Act which are
applicable to such source, or
(fa) After proposal of standards of performance in accordance with section 306 of the Act which
are applicable to such source, but only if the standards are promulgated in accordance with section 306
within 120 days of their proposal." 40 CFR ง 122.2.
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:< "(4) Construction of a new source as defined under ง 122.2 has commenced if the pwner or
operator has: ' >
(i) Begun, or caused to begin as part of a continuous on-site construction program;
(A) Any placement assembly, or installation of facilities or equipment; or ..-..,-- ,
(B). Significant site preparation work including clearing, excavation or removal of existing
buildings, structures or facilities which is necessary for the placement, assembly, or installation of aew
source facilities pr equipment; or , , ;
(ii) Entered into a binding contractual obligation for the purchase pf facilities or equipment which
are intended to; be used in its operation within* a reasonable tune. Options to purchase or contracts which
can be terminated or modified without substantial loss, and contracjs.for feasibility engineering and design
studies do npt constitute .a,contraetual obligation under the paragraph." 40CFR ง 122.29(b)(4) (emphasis
added). "- , . ,, ,. , ..
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In 1985, EPA proposed to define, for purposes of the Offshore Guidelines, "significant site
preparation wprk" as "the process pf clearing and preparing an area pf the ocean floor for purposes pf
cpnstructing pr placing a develppment pr productipn facility pn or over the site." (emphasis, added).
Thus., development and production wells would be new sources under the Offshore Guidelines. Further,
with regard to 40 CFR 122,29(b)(4)(ii), EPA stated that although it was. npt "proppsing a special
deflmtipn.pf this provision believing it should appropriately be a decision for the permit writer," EPA
suggested that the definition of new source include development or production sites even if the Discharger
entered into a contract for purchase of facilities or equipment prior to publication, if np specific site was
specified in the contract Conversely, EPA suggested that the defmitipn pf new spurce exclude
develppment pr productipn sites if the discharger entered intp a cpntract pripr tapublicatipn and a specific
site was specified in the: cpntract...;,r v ; j; t
, As a cpnsequence?pf the .proppsed definitipn pf "significant site preparatipn wprk, " if "clearing
or preparatipn pf an ajea fpr. develppment or prpduction has occurred at a site prior to the publication
of the NSPS, then subsequent development and production activities at the site would not be considered
a new source" (5Q FR 34618). Also, exploratipn activities at a site wpuld not be considered significant
site preparation work, and therefore explpratpry wells wpuld npt be new.spurces (50 FR 34618). The
purposes pf these distinctions were to "grandfather" as an existing .source, any source if "significant site
preparation work ... evidencing an intent to. establish full scale pperatipns at a site,, had been performed
prior tp NSPS becpming effective" (50 FR 34618). -At the same time, if pnly explpratpry drilluig had
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occurred prior to NSPS becoming effective, then subsequent drilling and production wells would be
considered to be new sources.
EPA also proposed a special definition for "site" in the phrase significant site preparation work
used in 40 CFR 122.2 and 40 CFR 122.29(b). "Site" is defined in 40 CFR 122.2 as "the land or water
area where any 'facility or activity' is physically located or conducted, including adjacent land used hi
connection with the facility or activity." EPA proposed that the term "water area" mean the "specific
geographical location where the exploration, development, or production activity is conducted, including
the water column and ocean floor beneath such activities. Thus, if a new platform is built at or moved
from a different location, it will be considered a new source when placed at the new site where its oil and
gas activities take place. Even if the platform is placed adjacent to an existing platform, the new platform
will still be considered a 'new source,' occupying a new 'water area' and therefore a new site" (50 FR
34618, Aug. 26, 1985).
As a consequence of these distinctions, exploratory facilities would always be existing sources.
Production and development facilities where significant site preparation has occurred prior to the effective
date of the Offshore Guidelines would also be existing sources. These same production and development
facilities, however, would become "new sources" under the proposed regulatory definition if they moved
to a new water area to commence production or development activities. The proposed definition,
however, presents a problem because even though these facilities would be "new sources" subject to
NSPS, they could not be covered by an NPDES permit in the period immediately following the issuance
of these regulations. This is because no existing general or individual permits could have included NSPS
until NSPS were promulgated. To resolve this problem, the final rule temporarily excludes from the
definition of "new source" those facilities that as of the effective date of the Offshore Guidelines are
subject to an existing general permit pending EPA's issuance of a new source NPDES general permit.
EPA believes this approach is reasonable because when Congress enacted Section 306 of the CWA it did
not specifically address mobile activities of the sort common in this industry, as distinguished from
activities at stationary facilities on land that had not yet been constructed prior to the effective date of
applicable NSPS. Moreover, EPA believes that Congress did not intend that the promulgation of NSPS
would result hi stopping all oil and gas activities which would have been authorized under existing
NPDES permits as soon as the NSPS are promulgated. Now that NSPS are promulgated, EPA intends
to apply them to appropriate facilities (i.e., those where there is significant site preparation work for
development or production after promulgation of NSPS) within the Offshore Subcategory. EPA intends
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to issue as final, after opportunity for notice and comment, new source NPDES permits as soon as
possible.
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2.2 GEOGRAPHICAL LOCATIONS OF THE OFFSHORE INDUSTRY
Offshore exploration, development, and production occurs in areas that are offered for
development by Federal or State governments on a leased basis. These areas are known as tracts. The
standard Federal offshore leased tract is 5,760 acres or 9 square miles. The Minerals Management
Service (MM) is the bureau within the U.S. Department of Interior (DOI) that is responsible for
administering the minerals leasing program for the Federal Outer Continental Shelf (OCS). The Federal
OCS consists of all areas seaward of the 3 mile boundary except for offshore Texas and Florida which
is 3 leagues. The Federal OCS is divided into 26 planning areas to allow for individual consideration
for areas having differences in resource potential, environmental concerns, and degree of previous
development. Figure III-l presents a map of the Federal offshore regions. On June 26, 1990, the
President of the United States directed the Secretary of Interior to cancel three leasing offerings offshore
California (parts of the northern, central, and southern California planning areas), one tract offshore
southwestern Florida in the Gulf of Mexico, tracts in the Georges Bank area off New England, and all
tracts off the coast of Washington and Oregon1. The lease cancellations exclude the above-mentioned
Federal OCS planning areas, except tracts located in me Santa Maria Basin and Santa Barbara Channel,
from consideration for any lease sale until after the year 2000. Tracts within the Santa Maria Basin and
Santa Barbara Channel will be available for leasing after January 1, 1996. These lease cancellations are
hereafter referred to as the "presidential moratoria on leasing."
Each State runs its own leasing program and there is no coordination between the States and the
Federal MMS in the leasing process. All States except Texas and Florida (the Gulf of Mexico side only)
were granted jurisdiction over offshore lands to a distance of 3 nautical miles from their coasts by the
Submerged Lands Act (43 U.S.C 1301, et seq.). Texas and Florida (the Gulf of Mexico side only) have
jurisdiction to 3 marine leagues (approximately 10.35 statute miles).
2.3 MAJOR WASTES STREAMS
The major waste streams from drilling and production operations are those streams with the
greatest volumes and amounts of pollutants. The major waste streams are drilling fluids and drill cuttings
from drilling operations and produced water from production operations. The following sections present
the regulatory definition for each of these waste streams.
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2.3.1 Drilling Fluid
The term "drilling fluid" refers to the circulating fluid (mud) used in the rotary drilling of wells
to clean and condition the hole and to counter balance formation pressure. A water-based drilling fluid
is the conventional drilling mud in which water is the continuous phase and the suspending medium for
solids, whether or not oil is present. An oil-based drilling fluid has diesel, mineral, or some other oil
as its continuous phase with water as the dispersed phase.
2.3.2 Drill Cuttings
The term "drill cuttings" refers to the particles generated by drilling into subsurface geologic
formations and carried to the surface with the drilling fluid.
2.3.3 Produced Water
THe term "produced water" refers to the water (brine) brought up from the hydrocarbon-bearing
strata during the extraction of oil and gas, and can include formation water, injection water, and any
chemicals added downhole or during the oil/water separation process.
2,4 MISCELLANEOUS WASTES
Miscellaneous wastes from drilling and production operations are those wastes generated which
are relatively small in volume and pollutant levels, yet significant enough to be of regulatory concern.
The miscellaneous wastes generated from drilling and production operations are: produced sand, well
treatment fluids, well completion fluids, workover fluids, deck drainage, and domestic and sanitary waste.
The following sections present the regulatory definition for each of these wastes.
2.4.1 Produced Sand
The term "produced sand" refers to slurried particles used in hydraulic fracturing, ihe
accumulated formation sands and scale particles generated during production. Produced sand also
includes desander discharge from the produced-water waste stream and blowdown of the water ph^e
from the produced water treating system.
2.4.2 Well Treatment Fluids
The term "well treatment" fluids refers to any fluid used to restore or improve productivity by
chemically or physically altering hydrocarbon-bearing strata after a well has been drilled.
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2.4.3 Well Completion Fluids
The term "well completion fluids" means salt solutions, weighted brines, polymers, and various
additives used to prevent damage to the well bore during operations which prepare the drilled well for
hydrocarbon production.
2.4.4 Workover Fluids
The term "workover fluids" means salt solutions, weighted brines, polymers, or other specialty
additives used in a producing well to allow safe repair and maintenance or abandonment procedures.
2.4.5 Deck Drainage
The term "deck drainage" refers to any waste resulting from deck washing spillage, rain water,
and runoff from gutters and drains including drip pans and work areas within facilities subject to this
subpart.
2.4.6 Domestic Waste
The term "domestic waste" refers to materials discharged from sinks, showers, laundries, safety
showers, eyewash stations, and galleys located within facilities subject to this subpart.
2.4.7 Sanitary Waste
The term "sanitary waste" refers to human body waste discharged from toilets and urinals located
within facilities subject to this subpart.
2.5 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 but are
considered to be minor and, more appropriately controlled by NPDES permit limitations. Therefore, no
controls for these wastes are promulgated by this rule. These wastes are categorized into the following
14 minor wastes categories:
1) Desalination unit discharge - wastewater associated with the process of creating fresh
water from seawater.
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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/1) - seawater
added or removed to maintain proper draft.
5) Mud, cuttings, and cement at the seafloor that result from marine riser disconnect arid
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 that 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.
1 1) 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.
3.0 CURRENT PERMIT STATUS
Offshore oil and gas structures in the Gulf of Mexico, California, and Alaska are regulated by
general and individual permits based on BPT, State water quality, ocean discharge criteria, and on Best
Professional Judgment (BPJ) of BCT and BAT levels of control. The general permits and some of the
individual permits are based to some degree upon the effluent limitations guidelines proposed in 1985 arad
for some waste streams are more stringent than the BPT regulations promulgated in 1979.
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Requirements in these general permits vary from region to region; however, produced water BPT
level limitations are consistently required. 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 ffl-1 presents a summary of the different requirements for drilling fluids and cuttings
contained in the various offshore permits and identifies the bases used in developing current baseline costs
and loadings for use hi developing the final limitations.
TABLE m-1
SUMMARY OF CURRENT REQUIREMENTS FOR
DRILLING FLUIDS AND CUTTINGS FOR THE OFFSHORE PERMITS
Requirement
No discharge of Oil Based
Drilling Fluids and Cuttings
(BPT)
Metals Limitation
Mercury (mg/kg)
Cadmium (mg/kg)
No Discharge of Oil
for Lubricity
as a Pill
Toxicity Limit for Drilling
Fluids
No Discharge of "Free Oil"
Gulf of Mexico
Yes
Stock Barite1
1
3
Yes (Diesel)
No (Diesel)2
30,000 ppm spp4
Visual Sheen
Pacific
Yes
Stock Barite
1
2
Yes (Diesel)
No (Diesel)2
30,000 ppm spp4
Static Sheen
Alaska
No
Stock Barite
1
3
Yes (Diesel)
Yes (Mineral)3
Yes5
Static Sheen
1 The modification to the Region VI OCS general permit for the Central and Western Gulf of
Mexico incorporates metals limitations (3 mg/kg Cd, 1 mg/kg Hg in stock barite) for drilling
fluids. However, for this rulemaking, the costing and pollutant loadings were developed prior
to the modifications and reflect the values presented in the table as current requirements. See
57 FR 54642 (Nov. 19, 1992). (Applies to Federal waters seaward of Louisiana and Texas.)
2 Diesel pill plus 50 bbl buffer of drilling fluid on either side of the pill cannot be discharged;
mineral oil can be discharged without a buffer.
3 Mineral oil pill plus a 50 bbl buffer of drilling fluid on either side of the pill cannot be
discharged. Diesel not allowed.
* Suspended Paniculate Phase
5 Implemented by the establishment of pre-approved drilling fluids and additives.
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4.0 REFERENCES
1.
2.
U.S. Department of Interior, Department of Interior News Release, Statement by Secretary of
the Interior, Manuel Lujan concerning the President's decisions regarding America's offshore oil
and gas program, June 26, 1990. (Offshore Ridemddng Record Volume 123)
Minerals Management Service, "Federal Offshore Statistics: 1990, Leasing, Exploration,
Production and Revenues," prepared by Office of Statistics and Information, Minerals'
Management Service, U.S. Department of Interior, MM 91-0068.
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SECTION IV
INDUSTRY DESCRIPTION
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1.0 INTRODUCTION
This section describes the major processes of the offshore oil and gas extraction industry and the
current and projected development and production activity. The industry operations are divided into two
categories: drilling and production activities. Proper characterization of the technical processes of these
two operation categories is essential in defining and characterizing the industry's waste streams.
2.0 DRILLING ACTIVITIES
This section describes the characteristics of the two types of drilling activities: exploration and
development. Exploration activities are those operations involving the drilling of wells to determine
potential hydrocarbon reserves. Development activities involve the drilling of production wells once a
hydrocarbon reserve has been discovered and delineated. Although the rigs used to drill exploration and
development wells sometimes differ, the drilling process is generally the same. Table IV-1 presents the
annual level of offshore exploration, delineation, and development drilling activity for the years 1973
through 1990.
2.1 EXPLORATORY DRILLING
Exploration for hydrocarbon-bearing reservoirs consists of several indirect and direct methods.
Indirect methods, such as geological and geophysical surveys, identify the physical and chemical
properties of sediments through surface instrumentation. Geological surveys determine subsurface
stratigraphy which identifies rocks typically associated with hydrocarbon bearing reserves. Geophysical
surveys indicate the depth and nature of subsurface rock formations and identify underground conditions
favorable to oil and gas deposits. There are three types of geophysical surveys: magnetic, gravity., and
seismic. These surveys are generally conducted from a boat that has specialized equipment for this
purpose. Exploratory drilling is the only way to directly confirm the presence of hydrocarbons and to
determine the quantity of hydrocarbons after the surveys indicate hydrocarbon potential. Exploratory
wells are also referred to as "wildcats."
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TABLE IV-1
OFFSHORE DRILLING ACTIVITY1
Year " '
1973
1974
1975
1976
1977
1978
1979
1980
1981
.1982
1983
1984
1985
1986
1987
1988
1989
1990
Number of Wells
PrIJIed
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
769
866
746
704
Footage Drilled3
8,354,069
7,402,256
9,783,176
9,817,244
11,519,851
11,756,744
12,392,501
12,503,275
14,422,470
14,537,052
12,831,906
14,259,153
12,815,948
9,407,734
7,345,260
9,334,447
7,721,365
6,963,804
Average Well Depth
Ot)
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
10,360
10,779
10,350
9,892
Includes exploration, delineation, and development drilling.
Exploratory wells may be shallow and drilled in the initial exploratory phase of operations, or
they may be deep, seeking to discover the extent of oil or gas bearing reservoirs. These types of
exploration activities are usually of short duration at a given site, involve a small number of wells, and
are conducted from mobile drilling units. A historical survey of offshore drilling indicates that a total
of 7,468 exploratory wells have been drilled as of January 1, 1985. Of these, 5,206 were drilled in
Federal waters. Of these, oil was found in 376 cases (5.0%), gas was found in 641 cases (8.6%), and
6,451 (86.4%) were dry holes. Approximately 30 percent of exploratory drilling occurred in State waters
and 70 percent in Federal waters.2
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2,1,1 Drilling Rigs
Mobile offshore drilling units (MODU) are used to drill exploratory wells because they can be
easily moved from one drilling site to another. The two basic types of MODUs are bottom-supported
units and floating units. Bottom-supported units include submersibles and jackups. Floating units include
inland barge rigs, drill ships, ship-shaped barges, and semisubmersibles.3
Bottom-supported drilling units are typically used when drilling occurs in shallow waters.
Submersibles are barge-mounted drilling rigs that are towed to the drill site and sunk to the bottom.
There are two common types of submersible rigs: posted barge and bottle-type.
Jackups are barge-mounted drilling rigs that have extendable legs that are retracted during
transport. At the drill site, the legs are extended to the seafloor. As the legs continue to extend, the
barge hull is lifted above the water. Jackup rigs can be used in waters up to 300 feet deep. There are
two basic types of jackups: columnar leg and open-truss leg.
Floating drilling units are typically used when drilling occurs in deep waters and at locations far
from shore. Semisubmersible units are able to withstand rough seas with minimal rolling and pitching
tendencies. Semisubmersibles are hull-mounted drilling rigs which float on the surface of the water when
empty. At the drilling site, the hulls are flooded and sunk to a certain depth below the surface of the
water. When the hulls are fully submerged, the unit is stable and not susceptible to wave motion due to
its low center of gravity. The unit is moored with anchors to the seafloor. Semisubmersibles are
commonly used for drilling projects in the North Sea and the North Atlantic Ocean. There are two types
of seinisubmersible rigs: bottle-type and column-stabilized.
Drill ships and ship-shaped barges are vessels equipped with drilling rigs that float on the surface
of the water. These vessels maintain position above the drill site by anchors on the seafloor or the use
of propellers mounted fore, aft, and on both sides of the vessel. Drill ships and ship-shaped barges are
susceptible to wave motion since they float on the surface of the water, and thus are not suitable for use
hi heavy seas.
2.1.2 Formation Evaluation
The operator is constantly evaluating characteristics of the formation during the drilling process.
The evaluation involves measuring properties of the reservoir rock and obtaining samples of the rock and
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fluids from the fonnation. Three common evaluation methods are well logging, coring, and drill stem
testing. Well logging uses instrumentation that is placed in the wellbore and measures electrical,
radioactive, and acoustic properties of the rocks. Coring consists of extracting rock samples from the
fonnation and characterizing the rocks. Drill stem testing brings fluids from the formation to the surface
for analysis.3
2.2 DEVELOPMENT DRILLING
Development activities involve the drilling of several wells into a reservoir to extract
hydrocarbons discovered by exploratory drilling. Several types of drilling rigs are used in developmental
drilling operations.. The two most common types of rigs used are the platform rig and the MODU.
Development wells are often drilled from fixed platforms because once the exploratory drilling
has confirmed that an extractable quantity of hydrocarbons exist, a platform is constructed at that site for
drilling and production operations.
To effectively extract hydrocarbons from the reservoir, several wells are drilled into different
parts of the formation. Since all wells must originate directly below the platform, a special drilling
technique is used to penetrate different portions of the reservoir. This technique is called controlled
directional drilling. Directional drilling involves drilling the top part of the well straight and then
directing the wellbore to the desired location. This requires special drilling tools and devices that
measure the direction and angle of the hole. Directional drilling also requires the use of special drilling
fluids that prevent temperature build up and stuck pipe incidents due to the increased stress on the drill
bit and drill string.
2.2.1 Well Drilling
The process of preparing the first few hundred feet of a well is referred to as "spudding." This
process consists of extending a large diameter pipe, known as the conductor casing, from a few hundred
feet below the seafloor up to the drilling rig. The conductor casing, which is approximately 2 feet hi
diameter, is either hammered, jetted, or placed into the seafloor depending on the composition of the
seafloor. If the composition of the seafloor is soft, the conductor casing can be hammered into place or
lowered into a hole created by a high-pressure jet of seawater. In areas where the seafloor is composed
of harder material, the casing is placed in a hole created by rotating a large-diameter drill bit on the
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seaflbor. In'all cases, the cuttings or solids displaced from setting the casing are not brought to the
surface and are expended onto the seafloor.
Rotary drilling is the drilling process used to drill the well. The rotary drilling process consists
of a drill bit attached to the end of a drill pipe, referred to as the "drill string," which makes a hole in
the ground when rotated. Once the well is spudded and the conductor casing is hi place, the drill string
is lowered through the inside of the casing to the bottom of the hole. The bit rotates and is slowly
lowered as the hole is formed. As the hole deepens, the walls of the hole tend to cave in and widen, so
periodically the drill string is lifted out of the hole and casing is placed into the newly formed portion
of the hole to protect the wellbore. This process of drilling and adding sections of casing is continued
until final well depth is achieved.
Rotary drilling utilizes a system of circulating drilling fluid to move drill cuttings away from the
bit and out of the borehole. The drilling fluid, or mud, is a mixture of water, special clays, and certain
minerals and chemicals. The drilling fluid is pumped downhole through the drill string and is ejected out
of nozzles in the drill bit with great speed and pressure. The jets of mud lift the cuttings off the bottom
of the hole and away from the bit so that the cuttings do not interfere with the effectiveness of the drill
bit. The drilling fluid is circulated to the surface through the casing, or annulus, where cuttings, silt,
sand, and any gasses are removed before returning the fluid down-hole to the bit. The cuttings, sand,
and silt are separated from the drilling fluid by a solids control process consisting typically of a
shaleshaker, desilter, and desander. Figure IV-1 presents a flow diagram of the mud circulation system.
Some of the drilling fluid remains with the cuttings after solids control.4-5 If the cuttings, silt, sand, and
residual drilling fluid do not contain free oil; they are discharged overboard. Cuttings contaminated with
oil from the formation or from an oil-based mud are stored in cuttings boxes and brought to shore for
disposal.
Drilling fluids function to cool and lubricate the bit, stabilize the walls of the borehole, and
maintain equilibrium between the borehole and the formation pressures. The drilling fluid must exert
a higher pressure in the wellbore than in the surrounding formation, otherwise fluids from the formation
(water, oil, and gas) will migrate from the formation into the wellbore, and potentially create a blowout.
A blowout occurs when drilling fluids are ejected from the well by subsurface pressures and the well
flows uncontrolled.
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To prevent well blowouts, high pressure safety valves called blowout preventers (BOPs) are
attached at the top of the well. Since the formation pressures vary at different depths, the density of the
drilling fluid must be constantly monitored and adjusted to the downhole conditions during each phase
of the drilling project. Other properties of the drilling fluid, such as lubricity, gel strength, and viscosity,
must also be controlled to satisfy the drilling conditions. The mud must be replaced if the drilling fluid
cannot be adjusted to meet the downhole drilling conditions. This is referred to as a "mud changeover."
The solids control process is necessary to maintain constant mud characteristics and/or change
them as required by the drilling conditions. The ability to remove drill solids from the drilling fluid,
referred to as "solids control efficiency," is dependent on the equipment and the formation characteristics.
Poor solids removal efficiencies result in increased drilling torque and drag, increased tendency for stack
pipe, Increased mud costs, and reduced wellbore stability. Mud dilution is a common method for
reducing the percentage of solids remaining in the circulating mud system that are not removed
mechanically via shaleshakers and hydrocyclones. Mud dilution involves thinning the mud with water
and rebuilding the desired Theological properties of the mud with additives. The disadvantages of dilution
are that the portion of the mud removed from the circulating system must be stored or disposed and
greater quantities of mud components are necessary to formulate the replacement mud. Both of these add
expenses to the drill project.
Most drilling fluid systems are water-based, although oil-based systems are still used for
specialized drilling projects. In the 1970's, drilling fluids were mostly oil-based. The trend away from
oil-based muds is due to the BPT limitations on the discharge of free oil and in advancements in water-
based fluids technology. Until recently, only oil-based muds could achieve the temperature stability and
lubricity properties required by special drilling conditions such as directional and deep well drilling.
However, advancements in drilling fluid technology have enabled operators to formulate water-based
muds with similar properties to that of oil-based muds through the use of small quantities of oil and/or
synthetic additives. Small quantities of oil and/or synthetic additives are used to enhance the lubricity
of a water-based mud system and to aid in freeing stuck drill pipe. In the past, diesel oil was solely used
for enhancing lubricity and freeing stuck pipe because of its properties and the fact that it is often the
most readily available oil at a drilling site. However, mineral oil and synthetic lubricants have replaced
diesel oil because of diesel's known toxicity. When oil or a synthetic spotting fluid is used as an aid in
freeing stuck drill pipe, a standard technique is to pump a slug or "pill" of oil or oil-based fluid down
the drill string and "spot" it in the annulus area where the pipe is stuck. Most of the pill can be removed
IV-7
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from the bulk mud system and disposed of separately. However, one hundred percent removal of the
pill is not possible and a portion of the spotting fluid remains with the mud system.
The most significant waste streams, in terms of volume and constituents associated with drilling
activities are drilling fluids and drill cuttings. Drill cuttings are generated throughout the drilling project,
although higher quantities of cuttings are generated during drilling of the first few thousand feet of the
well because the borehole is the widest during this stage. The largest quantities of excess drilling fluids
are generated as the project approaches final well depth. Fluids are generated during the drilling process
because of displacement due to solids control and smaller volumes required due to the decreasing
borehole diameter. Fluid generation is the largest at well completion because the entire mud system must
be removed from the hole and the mud tanks. Some constituents of the drilling fluid can be salvaged
after completion of the drilling program. Salvage facilities may exist at the rig or at another location such
as the industrial facility that supplies the drilling fluids. Where drilling is continuous, such as on a
multiple-well offshore platform, the mud can be conditioned and reused from one well to another.
3.0 PRODUCTION ACTIVITIES
This section details the activities and processes associated with extracting hydrocarbons from the
formation and processing the fluid for transportation to shore. The activities and processes described hi
this section are fluid extraction, well completion, fluid separation, well treatment, and workover.
3.1 FLUID EXTRACTION
The fluid produced from oil reservoirs consists of oil, natural gas, and salt water or brine. 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. The water contains dissolved and suspended solids,
hydrocarbons, metals, and may contain small amounts of radionuclides. Suspended solids consist of
sands, clays, or other fines from the reservoir.
Crude oil can vary widely hi its physical and chemical properties. Two important properties are
its density and viscosity. Density usually is measured by the "API gravity" method which assigns a
number to the oil according to its specific gravity. Oil can range from very light gasoline-like materials
(called natural gasolines) to heavy, viscous asphalt-like materials.
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Production fluids flow to the surface through tubing inserted within the cased borehole. For oil
wells, the energy required to lift the fluids up the well is supplied by the natural pressures in the
formation, known as natural drive. There are four kinds of natural drive mechanisms found with oil and
gas production: dissolved-gas drive, gas-cap drive, water drive, and combination gas and water drive.
As hydrocarbons are produced, the natural pressures in the reservoir decrease and additional
pressure must be added to the reservoir to extract the fluids. Additional pressure can be provided
artificially to the reservoir by various operations at the surface. The most common methods of artificial
lift are the following three: (1) gas lift, which is injection of gas into the well in order to lighten the
column of fluid in the borehole and assist in lifting the fluid from the reservoir as the gas expands while
rising to the surface; (2) waterflooding, which is the injection of fluids into the reservoir to maintain
formation pressures that otherwise drop during the withdrawal of the formation fluids; and (3)
employment of various types of pumps in the well itself. As the fluids in the well rise to the surface,
they flow through a series of valves and flow control devices that make up the well head.
3.1.1 Enhanced Oil Recovery
When an oil field is depleted by primary and secondary methods (e.g., natural flow, artificial lift,
waterflooding), as much as 50 percent of the original oil may remain in the formation. Enhanced oil
recovery (EOR) processes have been developed to recover a portion of this remaining oil. The EOR
processes can be divided into three general classes: (1) thermal, (2) chemical, and (3) miscible
displacement.
Thermal: Thermal processes include steam stimulation, steam flooding, and in situ combustion.
Steam stimulation and flooding processes differ primarily in the number of wells involved hi a field.
Steam stimulation uses an injection-wait-pump cycle in a single well, whereas the steam flooding process
uses a continuous steam injection into a pattern of wells and continuous pumping from other wells within
the same pattern. The in situ combustion process uses no other chemicals than the oxygen required to
maintain the fire.
Chemical: Chemical EOR processes include surfactant-polymer injection, polymer flooding, and
caustic flooding. In the first process, a slug of surfactant solution is pumped down the injection well
followed by a slug of polymer solution to act as a drive fluid. The surfactant "washes" the oil from the
formation, and the oil/surfactant emulsion is pushed toward the producing well by the polymer solution.
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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.
Misdble displacement: These EOR processes use an injected slug of hydrocarbon (e.g. , kerosene)
or gas (e.g., carbon dioxide) followed by an immiscible slug (e.g., water). The miscible slug dissolves
crude oil from the formation and the immiscible slug drives the lower viscosity solution toward the
producing well. The injection head and manifold system are similar to those used for steam flooding.
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3.2 COMPLETION
Completion operations include the setting and cementing of the production casing, packing the
well and installing the production tubing. The completion process installs equipment in the well which
allows hydrocarbons to be extracted from the reservoir. Completion methods are determined based on
the type of formation, such as hard sand, loose sand, fine grain loose sand, and loose fine and coarse
grain sands. Bridging agents are used to prevent fluid loss from the well to the formation.6-7
There are two types of completions, open hole and cased hole. Open hole completions are
performed on consolidated formations. Cased hole completions are performed on unconsolldated
formations. The majority of completions hi the Gulf of Mexico are cased hole.8 Figure IV-2 presents
schematic diagrams of four common completion methods for different formation characteristics.
The completion process consists of the following steps: wellbore flush, production tubing
installation, casing perforation, and wellhead installation. The following paragraphs give a brief
description of each of these steps.
The initial wellbore flush consists of a slug of seawater that is injected into the casing. These
fluids are considered cleaning or pre-flush fluids and can be circulated and filtered many times to remove
solids from the well and minimize the potential for damage to the formation.9 When the well has been
cleaned, a second completion fluid termed a "weighing fluid" is injected. This fluid maintains sufficient
pressure to prevent the formation fluids from migrating into the hole until the well completion is finished.
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A. FOR HARD SAND FORMATION
-OPEN HOLE COMPLETED-
PRODUCTION
TUBING
C. FOR FINE GRAIN LOOSE SANDS
PRODUCTION
TUBING
CEMENT
CASING
LINER
B. FOR LOOSE SAND FORMATION
-CLOSED HOLE COMPLETION-
PRODUCTION
TUBING
CEMENT
HANGER
CASING
LINER
CEMENTED
AND
PERFORATED
OIL SANDS
D. FOR LOOSE FINE AND COARSE GRAIN SANDS
PRODUCTION
TUBING
Figure IV-2
Typical Completion Methods
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Production tubing is then installed inside the casing using a packer which is placed at or near the
end of the tubing. The packer consists of pipe, gripping elements, and sealing elements made of rubber
that keep the tubing in place and expand to form a pressure-tight seal between the production tubing and
the well casing.3-10 This seals off the annular space and forces the reservoir fluids to flow up the tubing
and not into the well annulus.
Packer fluids are completion fluids that are trapped between the casing and the production tubing
by the packer. They can provide long-term corrosion protection. Packer fluids are typically mixtures
of a polymer viscosifier, a corrosion inhibitor, and a high concentration salt solution." Packer fluids
remain in place and may be removed during workover operations.12
The production tubing must then be perforated to allow the formation fluids to flow into the
wellbore. The most common method of cased hole completion is perforation. The casing in the well is
perforated to allow the hydrocarbons to flow from the reservoir to the well. Perforation may be
accomplished with the use of a special perforating gun (usually lowered into the well by wireline) that
fires steel bullets or shaped charges which penetrate the casing and cement. An additional means of
perforation is achieved by suspending a small perforated pipe from the bottom of the casing.3'10
The final step in well completion is the installation of the "Christmas tree," a device that controls
the flow of hydrocarbons from the well. The Christmas tree may be installed on the platform (a surface
completion) or below the waterline on or below the seafloor (a subsea completion). When the valves of
the Christmas tree are initially opened, the completion fluids remaining in the tubing are removed and
fluid flow from the formation begins.
3.3 FLUID SEPARATION
At the surface, the constituents of the formation fluids, or production fluids, are separated: gas
from liquids, oil from water, and solids from liquids. The gas, oil, and water may be separated in a
single vessel or, more commonly, in several stages. Gas dissolved in oil is released from solution as the
pressure of the fluid drops. Fluids from high-pressure reservoirs may be passed through a number of
separating stages at successively lower pressures before oil is free of gas. The oil and brine do not
separate as readily as the gas does. Usually, a quantity of oil and water is present as an emulsion. This
emulsion may occur naturally in the reservoir or can be caused by the extraction process which tends to
mk the oil and water vigorously. The passage of the fluids into and up the well, through wellhead
chokes, various pipes, headers, and control Valves into separation chambers, and through any centrifugal
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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.
The produced water treatment system is a series of vessels in a multistage separation process.
Figure IV-3 presents a flow diagram of a typical produced water treatment system. The first stage of the
produced water treatment system is a bulk separator. The bulk separator separates the produced fluid
into gas, oil and water. The gas stream is drawn off the top of the vessel, the oil stream off the middle,
and the water stream off the bottom, A schematic diagram of a bulk separator in presented in Figure
IV-4. Bulk separators are often arranged in series because gas comes out of solution as the pressure
drops.
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.
Production fluids are processed in the appropriate stage of the bulk separation process. The separated
gas is dehydrated in a glycol dehydrator and then used for electrical power generation, gas lift operations,
or transported to shore via pipeline. The oil separated in the bulk separator is piped to an oil treatment
unit for further treatment. The water separated in the bulk separator is piped" to a water treatment unit
for further oil-water separation.
The oil treatment unit is often referred to as a heater treater or chem-electric. This unit receives
the product oil stream from the bulk separator and is designed to remove residual water from the oil
through gravity separation aided by heat and/or the addition of chemicals to enhance and accelerate
separation. Heat and/or emulsion-breaking chemicals are almost always necessary to break the emulsions
present in the oil treatment unit to assure low water content hi the oil product (most pipelines have water
content limitations on the oil that can be transported in the pipelines). Oil is drawn off the top of the oil
treatment unit and sent to the oil product vessel before being piped to shore. Water is removed from the
bottom of the oil treatment unit and piped to the water treatment unit.
The water treatment unit receives produced water from the bulk separator and the oil treatment
unit. The water treatment unit is also referred to as a "precipitator." The produced water entering this
unit contains small quantities of residual oil. The water treatment unit is typically a long horizontal vessel
with quiescent conditions allowing for gravity separation. The vessel contains mostly water and the
separated oil floats to the surface of the water. An oil layer accumulates in the top portion of the vessel.
Oil is periodically removed from the top of the vessel and piped to the oil treatment unit. Water is drawn
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off the bottom of the vessel and discharged overboard through the skim pile if the effluent meets the BPT
oil and grease limitations.
If the water treatment unit does not provide sufficient treatment to meet the BPT oil and grease
limitations, additional water treatment units are used in conjunction with the separation process. The
most common treatment processes used in the offshore industry are gas flotation and coalescers. A
detailed discussion of these and other produced water treatment technologies is presented in Section
ix'.s.i.
The major waste stream associated with production activities is the produced water stream.
Produced sand or production solids is another waste stream of lesser volume. Both waste streams
originate with the production fluids and are separated from the oil product in the produced water
treatment system.
3.4 WELL TREATMENT
Well treatment is the process of stimulating a producing well to improve oil or gas productivity.
There are two basic methods of well treatment, hydraulic fracturing and acid treatment. The specific
method is chosen based on the characteristics of the reservoir, such as type of rock and water cut.10 A
well treatment job will enlarge the existing channels within the formation and increase the productivity
of the formation. Typically, hydraulic fracturing is performed on sandstone formations,10 and acid
treatment is performed on formations of limestone or dolomite.7
Hydraulic fracturing injects fluids into the well under high pressure, approximately 10,000 pounds
per square inch. This causes openings in the formation to crack open, increasing their size and creating
new openings. The fracturing fluids contain inert materials referred to as "proppants," such as sand,
ground walnut shells, aluminum spheres, and glass beads, that remain hi the formation to prop the
channels open after the fluid and pressure have been removed.7'13 Hydraulic fracturing is rarely done in
offshore operations because the unconsolidated sandstone formations in the Gulf of Mexico do not require
fracturing and the operation requires significant logistical support (i.e., deck space, pumps, mixing
equipment, etc.) that is expensive to provide offshore.4
Acid stimulation is done by injecting acid solutions into the formation. The acid solution
dissolves portions of the formation rock, thus enlarging the openings in the formation. The two most
IV-16
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4.0 PRODUCTION AND DRILLING: CURRENT ACTIVITY AND FUTURE
PROJECTIONS n
4.1 INDUSTRY SUBCATEGORIZATION
In evaluating the feasibility and costs of the various treatment technologies being considered, EPA |
developed subcategories, or sectors, within the offshore subcategory. These subcategories are based on
water depth or distance from shore of the production platform or the location of the drilling project. I
-
In 1985, EPA presented an industry subcategorization based on a structure's location in shallow I
or deep waters. EPA proposed variable depth limits for different offshore areas and evaluated several
regulatory options related to the shallow/deep subcategorization. This evaluation discovered certain I
nonwater-quality impacts associated with the options that warranted further investigation and/or
consideration of a change in the subcategorization scheme. In an effort to mitigate potential nonwater- I
quality environmental impacts, EPA developed a subcategorization based on distance from shore.
I*
In the 1991 proposal, EPA presented a subcategorization based on distance from shore. EPA
developed profiles based on 3, 4, 6, and 8 miles from shore. The distance from shore approach to I
industry subcategorization has enabled EPA to consider various options of the treatment technologies
considered for this rulemaking, while minimizing the associated nonwater-quality environmental impacts. HA
4.1.1 Industry Profile m
For each geographical region, the industry was characterized as consisting of a platform
population divided among different platform structure types, or model platforms. A model platform is B
defined by the number of available well slots on the platform. Each producing well is brought to the
wellhead on the platform through a dedicated well slot. Platforms are constructed with a fixed number
of well slots. Well slots that are not producing are considered dry holes. The number of dry holes was ^
determined from the difference between the number of slots on the platform and the number of producing
well slots. The count of the total number of platforms, including the number of well slots versus the
number of producing well slots on each platform, was generated by EPA using data compiled from the
following sources: the MMS Platform Inspection Complex/Structure database, the California Division of
Oil and Gas, and the California Coastal Commission.
The model platforms were further divided into three production type categories: (1) oil facilities,
(2) oil and gas facilities, and (3) gas facilities. For each model platform EPA reported the number of
TV-IS
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producing wells and the quantity of produced water generated using data compiled from the MMS
Complex/Structure Data Base.
Appendix 1 presents the industry profiles for the 3- and 4-mile from shore delineation. These
profiles contain regional information on the number of platforms, the number of producing wells, the
average daily produced water flow rate, and the maximum daily produced-water flow rate.
4.2 EXISTING PLATFORMS
EPA's industry profile estimates reflect structures that would incur costs under this rulemaking
effort. The estimate of existing structures includes only those platforms meeting the following guidelines:
(1) in production, (2) with specific products (i.e., oil, gas, or both), (3) with a specific number of wells
drilled or in production, (4) discharging, and (5) in the offshore subcategory. For the Gulf of Mexico,
two major sources of data are used. EPA conducted a mapping effort to identify structures in production
in the offshore subcategory of State waters. Using maps and electronic data, EPA accomplished the
following: (1) identified wells whose wellhead location lay seaward of the baseline that separates the
coastal and offshore subcategories, (2) identified wells belonging to common platforms, and (3) verified
which wells were still in production. This effort was undertaken to fill a data gap that existed at the tune
of the March 1991 proposal and identified an additional 284 structures. The second data source, the
March 1988 version of the "Minerals Management Service (MMS) Platform Inspection System,
Complex/Structure Data Base," was used to estimate the number of structures in the Federal waters of
the Gulf of Mexico that are likely to bear costs under this rulemaking effort. The estimated count of
2,233 in structures in Federal waters in the Gulf of Mexico is unchanged from the March 1991 proposal.
For the Pacific, 32 structures are included in the BAT count of existing structures. There are no
structures in the Atlantic at this time. Structures off Alaska hi Cook Inlet are in the coastal subcategory
and are not included in this rulemaking. Currently, there is only one existing project hi Alaskan waters
that is seaward of the inner boundary of the territorial seas. This facility is already required by State
regulations to reinject produced water; incremental compliance costs associated with this regulation are
minimal. No existing Alaskan structures are projected to incur significant incremental compliance costs
under this rule. A total of 2,549 offshore structures is used in the BAT analysis. Table IV-2 presents
the estimated number of existing structures.
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TABLE IV-2
EXISTING STRUCTURES IN OFFSHORE WATERS
Gulf of Mexico
California
Alaska
Total
Distance from Shore (nautical miles)
, 0-3
120
10
0
211
3-4
209
3
0
212
>4
2,107
11
0
2,118
Total
2517
32
0
2,549
4.3 NEW SOURCES
4.3.1 Drilling Activity
Offshore drilling efforts vary from year to year depending on such factors as the price and supply
of oil, the amount of State and Federal leasing, and reservoir discoveries. EPA estimates future drilling
activity averaging 759 wells per year during the 15-year period, from 1993-2007, after the regulation.
Estimated activity in the Gulf of Mexico and Alaska are based on MMS 30-year regionalized forecasts
with an average barrel of oil equivalent (BOB) price of $21/bbl (1986 dollars) for the 15-year period.
Recent moratoria and restricted leasing in the Pacific constrain drilling estimates to the level of
activity associated with drilling on installed structures and existing leases. Due to the Presidential
decision to cancel lease sale 96 (Georges Bank region in the North Atlantic) and strictly limit any activity
in this planning area until after the year 2000; no activity is projected for the Atlantic during the 1986-
2000 time period. EPA anticipates that these restrictions will remain applicable until after the year 2007.
This set of projections corresponds to the "restricted" or "constrained" well forecast presented in the
March 1991 proposal.
The projection of 759 wells drilled per year includes all new wells - productive, non-productive,
exploratory, and development. The well projections therefore include both BAT and NSPS wells. BAT
wells are exploratory wells and development .and production wells for which significant site preparation
takes place immediately prior to the promulgation of the regulation. NSPS includes any facility or
activity of this subcategory where the process of surveying, clearing, or preparing an area of the ocean
floor for the purpose of constructing or placing a development or production facility on or over the site
IV-20
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has commenced after promulgation of the regulation. Table IV-3 is a summary of the BAT and NSPS
wells by region. Approximately one-third of the new wells may be classified as existing sources. (The
actual percentage of wells classified "as; existing sources will vary in time. Most will be exploratory
efforts. The number of new wells drilled on existing platforms will decrease in time as those platforms
complete their drilling programs. The numbers given in Table IV-3 reflect the annual average number
of wells during the 15-year period after promulgation of the regulation.)
TABLE IV-3
AVERAGE ANNUAL NEW WELL DRILLING
(Wells/Year)
Region
Gulf
Pacific
Alaska
Total
Percent
Existing Sources
251
32
3
250 .
33%
New Sources
500
0
9
509
67%
Total
715
32
12
759
4.3.2 Production .
Platform projections were made based on the number of productive wells. An estimated 759
platforms are installed during the 15-year period after promulgation of the regulation. The fact that the
estimated annual average number of wells (759) is the same as the total number of platforms (759)
installed during the 15-year period is coincidental. Table IV-4 presents the total projected new structures.
TABLE IV-4
TOTAL PROJECTED NEW STRUCTURES - (1993-2007)
Gulf of Mexico
California
Alaska
Total
Distance from Shore {nautical miles)
0-3
102
0
2
104
3-4
38
0
0
38
>4
615
0
2
617
Total
755
0
4
759
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5.0
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
i
REFERENCES
American Petroleum Institute, " 1973 through 1990 Joint Association Survey on Drilling Costs. "
American Petroleum Institute, "Basic Petroleum Data Book" Volume V, No. 3, September 1985.
Baker, Ron, "A Primer of Offshore Operations," Second Edition, Petroleum Extension Service,
University of Texas at Austin, 1985.
James P. Ray, "Offshore Discharges of Drill Cuttings," Outer Continental Shelf Frontier
Technology. Proceedings of a Symposium, National Academy of Sciences, December 6, 1979.
(Offshore Rulemaking Record Volume 18)
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.
American Petroleum Institute, "Detailed Comments on EPA Supporting Documents for Well
Treatment and Workover/Completion Fluids." Attachment to API Comments on the March 13,
1991 Proposal, May 13, 1991. (Offshore Rulemaking Record Volume 146)
Walk, Haydel and Associates, "Industrial Process Profiles to Support PMN Review; Oil Field
Chemicals," prepared for EPA, undated but received by EPA on 6/24/83. (Offshore Rulemaldng
Record Volume 26)
Parker, M.E. "Completion, Workover, and Well Treatment Fluids," June 29, 1989. (Offshore
Rulemaking Record Volume 116)
Memorandum from Allison Wiedeman, Project Officer to Marv Rubin, Branch Chief.
"Supplementary Information to the 1991 Rulemaking on Treatment/Workover/Completion
Fluids," December 10, 1992
Wilkins, Glynda E., Radian Corporation. "Industrial Process Profiles for Environmental Use
Chapter 2 Oil and Gas Production Industry," for U.S. EPA, EPA-600/2-77-023b. February
1977. (Offshore Rulemaking Record Volume >J8)
Gray, George R., H. Darley, and W. Rogers, " Composition and Properties of Oil Well Drilling
Fluids," January 1980.
Arctic Laboratories Limited, et. al., "Offshore Oil and Gas Production Waste Characteristics,
Treatment Methods, Biological Effects and their Applications to Canadian Regions," prepared
for Environmental Protection Services, April 1983. (Offshore Rulemaking Record Volume 110)
U.S. Environmental Protection Agency. Report to Congress, "Management of Wastes from the
Exploration, Development and Production of Crude Oil, Natural Gas, and Geothermal Energy,"
Volume 1, EPA/530-SW-88-003. December 1987. (Offshore Rulemaking Record Volume 119)
IV-22
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14. Hudgins, Charles M., Jr. "Chemical Treatments and Usage in Offshore Oil and Gas Production
Systems." Prepared for American Petroleum Institute, Offshore Effluent Guidelines Steering
Committee. September, 1989. (Offshore Rulemaldng Record Volume 145)
15. Acosta, Dan. "Special Completion Fluids Outperform Drilling Muds." Oil and Gas Journal,
March 2, 1981. (Offshore Rulemaldng Record Volume 25)
16. American Petroleum Institute. "Exploration and Production Industry Associated Wastes Report."
Washington, D.C. May 1988.
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1.0 INTRODUCTION
The data gathering efforts conducted for the 1985 rulemaking focused on toxic pollutant effluents
from produced water, drilling fluids, and drill cuttings. In addition, EPA evaluated wastes associated
with the offshore development and production industry for certain conventional and nonconventional
pollutants.
Several areas were identified that required further study to support the 1985 proposal of effluent
limitations guidelines and standards. These included: an evaluation of priority pollutant levels in
produced water discharges, an evaluation of alternative produced water control and treatment
technologies, a characterization of drilling fluids and additives, an investigation of alternative disposal
practices for drilling fluids and drill cuttings, an assessment of the impacts of discharging drilling and
production wastes into the marine environment, and updated projections on the location, size, and
configuration of new sources.
Since the 1985 proposal, EPA has acquired additional information on oil and gas effluents and
their treatment technologies. Such information has been obtained by way of public comments, industry
data, and EPA-sponsored studies. Much of this information was discussed in a Federal Register Notice
of Data Availability and request for comments (53 FR 41356) in October 1988. In response to public
comments on the 1985 proposal and the 1988 notice, EPA reproposed BCT, BAT, and NSPS limitations
on March 13, 1991 (56 FR 10664). The 1991 proposal did not supersede the 1985 proposal entirely.
The 1985 proposal was revised in certain areas based on information that had been acquired regarding:
waste Characterization, treatment technologies, industrial practices, industry profiles, analytical methods,
environmental effects, compliance costs, and economic impacts.
The major studies presenting information on offshore oil and gas effluents and treatment
technologies which have bearing on the final rule are summarized hi the following sections.
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2.0 DRILLING FLUIDS AND DRILL CUTTINGS
2.1 CHARACTERIZATION OF WATER-BASED DRILLING FLUIDS
In 1933, EPA initiated a program to evaluate the characteristics of water-based drilling fluids.
Water-based drilling fluids may be broadly classified as either clay muds (those that depend on clay for
viscosity) or polymer muds (those that depend on polymer for viscosity). The program evaluated the
acute toxicity of water-based muds and the physical and chemical characteristics of water-based muds and
drill cuttings from water-based muds. The program also included an evaluation of the organic chemical
characterization of diesel and mineral drilling fluid additives. In addition to the characterization of water
based drilling fluids, the program examined the test procedures that were being proposed as analytical
methods for measuring acute toxicity and for detecting the presence of diesel oil in drilling fluids.
"f7.>
The basis of the program was the selection of the types of water-based muds to be analyzed. The
primary criteria of the mud selection process was to select the most common types of muds being used
in the offshore industry. The mud selection process included information gathered during the
development of the Mid-Atlantic NPDES drilling permit issued in 1978 and guidance from the Petroleum
Equipment Suppliers Association (PES A).l The final set of muds selected consisted of eight generic muds
whose characteristics encompass the spectrum of water-based muds used in offshore drilling operations.
The formulations of the eight generic muds selected for analysis did not include specialty additives,
however two of the generic muds were evaluated with different concentrations of mineral oil ranging from
0 to 10 percent by volume. The generic muds were formulated by PESA and sent to two different
laboratories for analysis. Table V-l presents descriptions for the eight generic muds selected for the
program.2 The EPA's Environmental Research Laboratory in Gulf Breeze, Florida, "Gulf Breeze,"
performed the acute toxicity testing and an EPA contract laboratory performed the physical and chemical
analyses.
The Gulf Breeze laboratory conducted acute toxicity testing of the eight generic muds with mysid
shrimp (Mysidopsis bahia) during August and September of 1983. To confirm the validity of the toxicity
tests conducted at Gulf Breeze, two of the drilling fluids were tested at the EPA's Environmental
Research Laboratory hi Narragansett, Rhode Island. The test material was the suspended particulate
phase (SPP) of each fluid. The SPP was prepared by mixing volumetrically 1 part drilling fluid to 9 parts
seawater and allowing the resulting slurry to settle for one hour. A positive control, in which mysid
shrimp were exposed to the reference toxicant (sodium lauryl sulfate), was maintained for each drilling
fluid toxicity test.3
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TABLE V-l
GENERIC MUD DESCRIPTIONS2
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GENERIC MOD
1. Potassium/polymer
2. Seawater/lighosulfonate
3. Lime (or calcium)
4. Nondispersed
5. Spud
6. Seawater /freshwater gel
7. Lightly treated
lignosulfonate
freshwater/seawater
8. Lignosulfonate
freshwater
NATURE AND UTILITY
An inhibitive mud used for drilling through soft formations like
shale where sloughing may occur. Polymers are used to maintain
their viscosity. These fluids require little thinning with fresh or salt
water.
An inhibitive mud that functions well under a variety of conditions.
This'mud maintains viscosity by binding lignosulfonate cations onto
the brpken edges of clay particles, reducing flocculation and
maintaining gel strength. This mud can control fluid loss and
maintain borehole stability. They are easily altered for more
complicated downhole conditions, e.g., higher temperatures.
An inhibitive mud in which calcium binds onto clay. The clay
platelets are pulled together, dehydrating them and releasing
absorbed water. The size of the particles is reduced, and water is
released, resulting in reduced viscosity. More solids may be
maintained in these systems with a minimum of viscosity and gel
strength! These fluids are used in hydratable, sloughing shale
formations. . . '
An inhibitive mud in which acrylic serves to prevent fluid loss and
maintain viscosity. This mud also provides unproved penetration,
:which is impeded by clay particles in dispersed fluids.
A noninhibitive, simple mixture used in the first 1,000 (300m) or
so of drilling.
An inhibitiye mud used early in drilling or in simple drilling
situations. This mud provides good fluid control, shear thinning,
and lifting capacity. Prehydrated bentonite that flocculates is used
in such freshwater or saltwater fluids. Attapulgite is used in
saltwater fluids when fluid loss is not important.
This mud resembles seawater/lignosulfonate fluids (type 2) except
that the salt content is less. The viscosity and gel strength of these
: fluids are adjusted through additions of lignosulfonate and caustic
soda. . ,
This mud resembles fluid types 2 and 7, except that lignosulfonate
concentrations are higher. These fluids are suited to high-
temperature drilling. Increased concentrations of lignosulfonate
will result in heavily treated fluids of this type.
V-3
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The physical and chemical analyses were conducted on the eight generic muds without any
additives and on an additional six mud compositions with varying degrees of mineral oil. The EPA
contract laboratory also analyzed drill cuttings from oil-based muds and additional drilling fluid samples
with varying degrees of diesel and mineral oils. A total of 34 mud samples were shipped to the EPA
contract lab by the industry. These muds consisted of generic formulations with no additives, with
varying concentrations of mineral oil, with varying concentrations of an emulsifier, and with varying
concentrations of diesel oil. Also analyzed were six samples of washed and unwashed drill cuttings from
three drilling operations in the Gulf of Mexico. The drill cuttings Were from drilling programs using oil-
based (mineral and diesel) mud systems,. The physical and chemical analyses consisted of the following
parameters: biological oxygen demand, total organic carbon, chemical oxygen demand, sheen test, oil
and grease, organics, and metals.4
Table V-2 presents a list of the muds and cuttings analyzed for toxity and for chemical
composition.
2.2 AMERICAN PETROLEUM INSTITUTE DRILLING FLUIDS SURVEY
In 1983, the American Petroleum Institute (API) conducted a survey among eleven offshore
operators in the Gulf of Mexico to obtain information on diesel and mineral oil usage in water-based
drilling fluids. Because the number of mineral oil applications in 1983 was small, API conducted an
additional survey hi 1984 to obtain more data on mineral oil usage.5
The survey data indicate that mineral oil is more commonly used as a lubricant, while diesel oil
is more commonly used for spotting purposes. Data from the 1983 survey indicated that diesel oil was
used for spotting purposes in 79 percent of all pills, and mineral oil Was used in 21 percent of all pills
using hydrocarbons. The survey indicated that the success rate of freeing stuck pipe was 48 percent for
diesel oil pills and 33 percent for mineral oil pills. Data from the 1984 survey indicated that
hydrocarbons (diesel or mineral oil) were added for lubricity in 12 percent of all water based fluids.
Mineral oil and diesel oil were used hi 8 percent and 4 percent of the wells, respectively. For drilling
fluids, to which a hydrocarbon-based lubricity agent was added, typically 3 percent (by volume) of the
mud formulation was composed of a hydrocarbon additive. The data also indicated that in 1984, 47
percent of all wells drilled used a water-based drilling fluid.
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TABLE V-2
SUMMARY OF DRILLING FLUIDS ANALYSIS PROGRAM4
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2
3
4
5
6
7
8
2-01
2-05
2-10
8-01
8-05
8-10
Sample Description
Generic Muds
Seawater/Potassium/Polymer Mud
Seawater/Lignosulfonate Mud
Lime Mud
Nondispersed Mud
Spud Mud
Seawater/Freshwater Gel Mud
Lignosulfonate Freshwater/Seawater Mud
Lignosulfonate Freshwater Mud
Spiked with 1 % by volume mineral oil
Spiked with 5% by volume mineral oil
Spiked with 10% by volume mineral oil
Spiked with 1 % by volume mineral oil
Spiked with 5% by volume mineral oil
Spiked with 10% by volume mineral oil
Additional Muds
008-0-0
008-0-.075
008-0-.15
008-0-.3
008-1-0
008-1-.075
008-1-.15
008-1-.3
008-5-0
008-5-.075
008-5-.15
008-5-.3
008-10-0
008-10-.075
008-10-. 15
008-10-.3
2
2-01-HSD
2-03-HSD
2-05-HSD
2-08-HSD
2-01-LSD
2-03-LSiD
2-05-LSD
2-08-LSD
8
8-01-HSD
8-03-HSD
8-05-HSD
8-08-HSD
8-01-LJiD
8-03-LSD
8-05-LSD
8-08-LSD
Generic Mud # 8 Unspiked
Spiked with 0% mineral oil; 0.075 ppbbl emulsifier
Spiked with 0% mineral oil; 0.15 ppbbl emulsifier
Spiked with 0% mineral oil; 0.3 ppbbl emulsifier
Spiked with 1 % mineral oil; no emulsifier
Spiked with 1 % mineral oil; 0.075 ppbbl emulsifier
Spiked with 1 % mineral oil; 0.15 ppbbl emulsifier
Spiked with 1 % mineral oil; 0.3 ppbbl emulsifier
Spiked with 5% mineral oil; no emulsifier
Spiked with 5% mineral oil; 0.075 ppbbl emulsifier
Spiked with 5% mineral oil; 0.15 ppbbl emulsifier
Spiked with 5% mineral oil; 0.3 ppbbl emulsifier
Spiked with 10% mineral oil; no emulsifier
Spiked with 10% mineral oil; 0.075 ppbbl emulsifier
Spiked with 10% mineral oil; 0.15 ppbbl emulsifier
Spiked with 10% mineral oil; 0.3 ppbbl emulsifier
Generic Mud # 2 Unspiked
Spiked with 1 %, high sulfur content diesel
Spiked with 3%
Spiked with 5%
Spiked with 8%
Spiked with 1 %, low sulfur content diesel
Spiked with 3%
Spiked with 5%
Spiked with 8%
Generic Mud #8 Unspiked
Spiked with 1 %, high sulfur content diesel
Spiked with 3%
Spiked with 5%'
Spiked with 8%
Spiked with 1 %, low sulfur content diesel
Spiked with 3%
Spiked with 5%
Spiked with 8%
Toxkiiy
Testing
Chemical
Analysis
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes ;
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Pass Static
Sheen
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Pass
Fail
Fail
Fail
Pass
Fail
Fail
Fail
Pass
Fail
Fail
Fail
Pass
Fail
Fail
Fail
Pass
Pass
Fail
Fail
Fail
Pass
Fail
Fail
Fail
Pass
Fail
Fail
Fail
Fail
Fail
Fail
Fail
Fail
'- '" ' " ' ' JE>rOI Cuttiass
1A
IB
2A
21!
3A
31!
Before washing with Baroid Invelmol mineral oil
After washing oil-based mud
Before washing with Milchem Carbotec
After washing oil-based mud
Before washing Vermillion Mageobar Faze-Kleen mineral oil
After washing oil-based mud
No
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Fail
Fail
Fail
Fail
Fail
Fail
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2.3 API/OOC DRILLING FLUIDS BIOASSAY STATISTICS
The Offshore Operators Committee (OOC) submitted drilling fluid toxicity data collected in 1985
and 1986 from drilling projects in the Gulf of Mexico. The toxicity data was compiled from an
API/OOC guidelines questionnaire on used mud composition and toxicity. The following information
was gathered by the questionnaire: toxicity, mud type, mud composition, mud weight, and type of
hydrocarbon added. Approximately 42 percent of the drilling fluids tested for toxicity were below (more
toxic than) the 30,000 parts per million value.6
2.4 OFFSHORE OPERATORS COMMITTEE SPOTTING FLUID SURVEY
The industry submitted the results of a retrospective survey comparing the success rates of diesel
and mineral oil pills hi freeing stuck pipe. This project was conducted in 1986 by the Offshore Operators
Committee (OOC) and evaluated data from 1983 to 1986.7
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 survey asked for the date the event
took place, the type of oil used in the pill, the time interval between sticking and spotting activities, the
depth at which the stuck pipe incident occurred, 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 drilled with water-based muds, 506 stuck pipe incidents were identified in which
the operator chose to use an oil additive to free the stuck pipe. Of the 506 incidents, 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 oil pills exclusively. Diesel oil
pills were successful 52.7 percent of the time and mineral oil pills were successful 32.7 percent of the
time in freeing stuck pipe.
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The OOC also examined mud and formation characteristics as factors in successful pill addition.
These factors include: base oil type, time expired before 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 less dramatic trend was observed for
mineral oil pills. The diesel oil success rate was 61 percent if the pill was spotted in less than 5 hours.
The rate dropped to 41 percent if the time until spot exceeded 10 hours. The mineral oil success rate was
35 percent if the pill was spotted in less than 5 hours; the rate dropped to 31 percent if the time until the
spot exceeded 10 hours.
Other factors examined by OQC 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 operator 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 percent of their stuck pipe incidents experienced an average 42 percent
success rate with such pills.
Some of the operators with extensive mineral pill experience 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 percent. The highest success rates among
operators using diesel pills were 60 and 64 percent.
2.5 THE EPA/API DIESEL PILL MONITORING PROGRAM
The Diesel Pill Monitoring Program (DPMP) was a jointly funded effort by EPA's Industrial
Technology Division (currently Engineering and Analysis Division), the American Petroleum Institute,
and Gulf of Mexico operators to investigate the practice of recovering diesel pills. The program involved
the collection and analysis of samples from active mud systems prior to use and after removal of diesel
pills. The primary purpose of the DPMP was to provide a mechanism to collect data for consideration
V-7
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in developing waste discharge regulations for the offshore oil and gas industry. The Gulf of Mexico was
selected for this study because of the large number and diversity of drilling operations in this region.8
The program was implemented as part of EPA Region IV and VI's Final NPDES General Permit
for the Outer Continental Shelf (OCS) of the Gulf of Mexico (U.S. EPA Permit No. GMG 280000,1986,
51 FR 24897) that became effective on July 2, 1986. The DPMP was effective for one year under the
general permit and was extended until September 30, 1987 by a Federal Register Notice dated July 6,
1987 ( 52 FR 25303). The permit implemented the DPMP which prohibited the discharge of mud to
which diesel was added unless: (1) The diesel was added as a pill in an attempt to free stuck pipe,
(2) The diesel pill and at least 50 barrels of drilling fluid on either side were removed from the active
drilling fluid system and not discharged to the waters, and (3) Samples of the drilling fluid after pill
removal and other additional data were provided to EPA in accordance with the Diesel Pill Monitoring
program.
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 is 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 the
method described in the DPMP Program Manual. Drilling fluid bioassay tests were conducted according
to The Drilling Fluids Toxicity Test described in the 1985 proposal (50 FR 34592). The toxicity test is
determined on the suspended paniculate phase by exposure ofMysidopsis 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 hi 56 wells. Three sets of data evolved from this program. Dataset 1 was
used for examining relation-ships between diesel concentration and toxicity and between analytical
methods used to measure total oil content and diesel content. Dataset 2 was used in calculating success
rates for freeing stuck pipe. Dataset 3 was used in determining correlations with diesel recovery levels.
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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. Diesel recovery varies with the volume of the
"extra buffer" captured. Extra buffer refers to the amount of drilling fluid in excess of the buffer volume
required by the DPMP; which is 100 barrels, 50 barrels on each side of the pill. As shown in Table
V-3, the diesel recovery for the overall program ranged from 4.2 to 100 percent. The mean recovery
level was 76.5 percent while the median recovery level was 83 percent. Increasing buffer volume had
little or no effect on the mean, median, or maximum recoveries, however, it did increase the minimum
recovery level of the pill (from 32.1 to 72.9 percent over the entire extra buffer interval).
TABLE V-3
PERCENT DIESEL RECOVERED VS QUANTITY OF
EXTRA BUFFER* HAULED ASHORE FOR DISPOSAL8
Extra Buffer
(BBLS)
0'
0300
Totals
Number of
Incidents
11
18
10
13
6
58
% Percent Diesel Recovered
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 barrels
**Next lowest value is 61.4.
Mud toxicity varies with diesel content. At low diesel concentrations, mud LC50 values decrease
rapidly with increasing diesel content. At higher diesel concentrations, mud LC50 values decrease
gradually. Most of the muds sampled before spotting had LC50 values higher than those sampled after
spotting (the median LC50 values of the mud samples before and after spotting were 52,000 ppm and
6,000 ppm respectively). The mud samples with low LC50 values before spotting 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 the first or second pill had already been spotted. Thus, mud toxicity is
observed to be a strong function of diesel content, especially at low diesel concentrations.
V-9
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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 these two mud types, the DPMP muds were classified as clay or polymer muds.
At very low diesel oil concentrations the mean LC50 values for both basic mud types are greater than
400,000 ppm. Mean LC50 values for both mud types decrease similarly with increasing diesel oil
content. Thus, it appears that toxicity related to the presence of diesel oil is not a function of mud type.
The overall rate of success for freeing stuck pipe was 40.0 percent (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 percent (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 hi this program.
To examine the effect of density on success rate, the incidents in Dataset 2 were divided into two groups
based on pill density. Approximately half of the incidents in Dataset 2 had pill densities less than 12.0
pounds per gallon (ppg) and the other half had pill densities greater than 12.0 ppg. The success rate for
those cases where the pill density was less than 12 ppg was 62.5 percent, while the success rate for those
cases where the pill density exceeded 12 ppg was only 21 percent.
Based on analyses of information generated during the DPMP, EPA concluded that use of the pill
recovery techniques implemented during this program do not result in recovery of sufficient amounts of
the diesel pill or 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 percent (by weight) after introduction of a diesel pill and subsequent pill recovery efforts. In
addition, mud systems for approximately 80 percent of the DPMP wells failed the 30,000 ppm LC50
limitation after pill recovery. Forty percent of the DPMP wells using water-based mud systems that
contained residual diesel oil following pill recovery showed LC50 values of less than (more toxic than)
5,000 ppm.
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2.6 STATISTICAL ANALYSIS OF THE API-USEPA METALS DATABASE
The API-USEPA metals database is a compilation of 24 datasets containing information on metals
concentrations in barite, drilling fluids, drill cuttings, and formation sediments. The dataset includes data
collected by industry, and state and federal regulatory agencies. EPA determined each of the dataset's
suitability for use in a statistical analysis through evaluation of: the sampling design, the pertinent
materials sampled, and the precision and accuracy of the physical and chemical methods used. EPA
identified seven of the 24 datasets that were suitable for analysis in determining the metals characteristics
in barite, drilling fluids, and drill cuttings. EPA used the following datasets in its statistical analysis: the
Fifteen Rig Study, Discharge Monitoring Report Data from Region 9, Discharge Monitoring Report Data
from Region 10, Determination of Mercury and Cadmium in Drilling Fluids and Cuttings, Determination
of Mercury, Cadmium and Density in Drilling Fluids and Barites, and the Diesel Pill Monitoring Program
- Report #5.9-35
Data from the; seven datasets were used to statistically determine the following:
The distributional assessments of cadmium and mercury concentrations in barite, drilling
fluids, and drill cuttings.
The contribution of the geological formations to cadmium and mercury concentrations in
drill cuttings.
The correlation of cadmium and mercury concentrations with the other metals in barite
and drilling fluids.
A descriptive statistics for metals concentration in commercially available drilling fluids.
The statistical analysis was primarily descriptive, however, three specific conclusions can be
drawn from the analysis. The first two conclusions pertain to the hypothesis of an increase in cadmium
and mercury due to formation contributions and the third conclusion pertains to the correlation of
cadmium and mercury with other metals in barite and drilling fluids. The conclusions are as follows:
1) The hypothesis of an increase in mercury concentrations in drill cuttings due to
the geological formation is not supported from the two sets of data used in this
analysis.
2) The hypothesis of an increase in cadmium concentrations in drill cuttings was
supported by the statistical analysis of one dataset, but the analysis of the second
relevant; dataset was inconclusive.
V-ll
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3) In general, there is a positive correlation between the concentrations of cadmium
and mercury and concentrations of other metals found in barite and drilling
fluids.
2.7 STUDY OF ONSHORE DISPOSAL FACILITIES FOR DRILLING WASTE
In 1987, EPA conducted a survey of onshore waste disposal facilities available for disposal of
drilling fluids and drill cuttings generated from offshore oil drilling operations.10 The focus of the survey
was' to:
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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 as
landfill, land treatment, deep well injection, etc.
Determine the available and projected future 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.
i.
Information regarding the method of waste treatment and disposal was obtained from 16 operating
companies with disposal facilities in California, Louisiana, and Texas.
A variety of treatment and disposal systems were employed by the companies surveyed; ranging
from disposal of contaminated drilling fluids with and without treatment to treatment Of the fluids and
transferral of the treated material to another facility for final disposal. The typical methods of disposal
were: landfills, land treatment, deep well injection, and mud reclamation. This study is discussed further
in Section VD.5.2.4.
2.8 ONSHORE DISPOSAL OF OFFSHORE DRILLING WASTE - CAPACITY OF ONSHORE DISPOSAL
FACILITIES
This study evaluated the permitted capacities of onshore disposal facilities that accept offshore
drilling wastes and whether these facilities had adequate capacity to dispose of projected waste volumes.
The initial survey was conducted in 1989 and is documented in "Onshore Disposal of Drilling Waste:
Capacity and Cost of Onshore Disposal Facilities," prepared for EPA by ERCE, March 1991.11 The
evaluation focused on the three major geographic areas where onshore disposal of offshore drilling waste
V-12
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I would be encountered: the 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 onshore disposal volumes. Treatment and
i disposal 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.
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The survey conducted in 1989 estimated the projected available capacity for drill waste by
reviewing permitted capacity and projections of future permitted capacity. At that time, data on the
degree to which disposal capacity was used were not available. In 1992, updated estimates of capacities
were made using currently permitted volumes and data on the volumes of wastes treated at the disposal
sites were obtained to derive more accurate projections of the "excess" available capacity.12-13
Section XVIII.2.2 presents a detailed discussion on the original survey (1989= survey) and the
1992 update survey on the available existing and projected future landfill capacity as it pertains to the
offshore oil and gas industry.
2.9 OFFSHORE DRILLING SAFETY
In 1992, EPA evaluated data associated with personnel casualties that occurred on mobile offshore
drilling units (MODUs) and offshore supply vessels (OSV) for the years 1981 through 1990. The
personnel casualty data was compiled from the U.S. Coast Guard's Personnel Casualty file (PCAS). The
study focused on accidents related to the handling and transportation of material, since this would be most
similar to the additional activities required should a zero discharge limitation be imposed.14-IS
Sections XVIII.2.4.2 presents a detailed discussion on the findings of the EPA's evaluation of
safety as it relates to drilling activity and increased offshore supply vessel activity due to zero discharge
requirements on drilling waste.
V-13
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3.0 PRODUCED WATER DATA GATHERING
3.1 INTRODUCTION
EPA'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 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 which is common for produced water.
In 1981, EPA collected produced water effluent samples from 10 platforms in the Gulf of
Mexico. The objectives of the study were to: characterize the produced water with respect to oil content,
identify the factors contributing to the oil content in produced water, and evaluate approaches to reduce
the oil content in produced water effluents. The study included platforms with three types of gravity
separators and nine of ten platforms had gas flotation treatment. The study characterized the removal
efficiency of oils from produced water using the following criteria: oil and grease analysis, susceptibility-
to-separation test, suspended solids test, crude oil equilibrium, particle-size distribution, and operational
characteristics consisting of well and process data.16
3.2 30 PLATFORM STUDY
In 1981, EPA and OOC coordinated efforts to develop and implement a sampling program to
characterize the priority pollutants hi produced water effluents. This sampling effort is known as the "30
platform study." The 30 platform study consisted of two phases; the development of analytical protocols
for quantifying priority pollutants in produced water, and the sampling and analysis of produced water
effluents.
In Phase I, produced water samples were collected from two production platforms in the Gulf of
Mexico and sent to ten EPA and industry laboratories for comparative testing. Analytical efforts were
conducted to determine: (1) the precision and accuracy, (2) the level of detectability, and (3) the level
of quantification of the proposed methods on produced water samples. Final analytical protocols were
established employing: standards purged from 10 percent 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 metal analysis.17
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Phase II of the analytical program was conducted to confirm the presence and quantify the
concentrations of toxic pollutants in produced water discharges from 30 production facilities in the Gulf
of Mexico using the established protocols.18 Selection of the thirty platforms was based on the following
criteria: production rate, water cut, hydraulic loading, operating companies, and geographical
distribution. Twenty-five of thirty platforms utilized gas floatation technology.
Pollutants analyzed were: the priority organics, chloride, iron, oil and grease (O&G), total
dissolved solids (TDS), and certain metals, namely cadmium (Cd), chromium (Cr), copper (Cu), lead
(Pb), nickel (Ni), silver (Ag), and zinc (Zn).
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The sampling program was designed to include an evaluation of the major components of
variability which include: (1) Analytical variability, (2) Intra-platform variability, and (3) Inter-platform
variability. To evaluate these components of variability, several platforms were sampled for consecutive
days and more than once per day. A description of the types and numbers of samples taken is as follows:
Number of
Platforms
16
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30
Sample Type
1 Day Effluent
1 Day Influent/Effluent
2 Day Influent/Effluent
3 Day Influent/Effluent
Number of
Samples
16
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IS
64
In addition, 10 duplicate effluent and 5 duplicate influent samples were collected which results
in a total of 79 samples collected for the sampling program. Tables A2-1, A2-2, and A2-3 in Appendix
2 present analytical data from this study.
3.3 ALASKA AND CALIFORNIA SAMPLING PROGRAMS
In 1982, priority pollutant sampling efforts were conducted at Alaska and California sites.
Produced water samples were collected from coastal and onshore treatment facilities in Cook Inlet and
Prudhoe Bay, Alaska and from three offshore production platforms in California's Santa Barbara Channel.
Data obtained from these sampling efforts are presented in the report entitled Priority Pollutants In
Offshore Produced Oil Brines.19
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3.4 PRODUCED WATER TREATMENT TECHNOLOGY EVALUATIONS
Since the 1985 proposal, EPA evaluated additional technologies for consideration as add-on
technologies to BPT technology and better performance of gas flotation, one of the BPT technology bases.
The add-on technologies evaluated by EPA were multi media filtration and crossflow membrane filtration.
EPA also evaluated the technical feasibilities of produced water reinjection in offshore regions. Ifhis
section details the EPA's evaluations for these produced water treatment technologies.
3.4.1 Three Facility Study
In June of 1989, EPA conducted a comprehensive 4-day sampling program at three oil and gas
production facilities to evaluate the performance of granular filtration technology and to characterize
produced water and other miscellaneous discharges such as produced sand, well treatment fluids and deck
drainage. The study also evaluated two different analytical methods for measuring oil and grease. Oil
and grease content was determined using an analytical method that measures the total oil and grease,
consisting of certain soluble and insoluble compounds using freon as an extraction solvent, and another
analytical method that only measures the insoluble compounds contained in oil and grease. EPA selected
facilities for the three facility study based on: (1) their use of granular filtration, and (2) the oil and
grease level being comparable to the BPT level prior to filtration. The facilities selected were not all in
the offshore subcategory because granular filtration is not in widespread use on offshore platforms. The
only operating granular filtration unit on a platform was located offshore California. The three facilities
selected for this study were: Thums Long Beach Island Grissom (coastal subcategory), Shell Western,
E & P, Inc. - Beta Complex (offshore subcategory), and Conoco's Maljamar Oil Field (onshore
subcategory) .20>2I>22
The three facility study collected operating and analytical data from each of the granular filtration
units. The filter influent, effluent, and backwash streams were analyzed for oil and grease, total
suspended solids, and radionuclides. The study also evaluated the wastes associated with the backwash
cycle and the potential of accumulation and/or concentration of radionuclides in the backwash stream.
In addition to sampling, granular filtration system design parameters, such as space requirements,
maintenance requirements, and capital and annual costs were collected.
Analytical data and a discussion of the results of the three facility study are presented in Section
IX.4 and in Table A2-4 in Appendix 2.
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3.4.2 Ceramic Crossflow Membrane Filtration
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EPA conducted a week-long study at a production platform in the Gulf of Mexico that operates
the only full-scale ceramic membrane filtration unit treating oilfield produced water in the United States.
The membrane study, conducted April 3 through April 10, 1991, consisted of a seven day sampling
period and sampled all of the major streams around the unit. The streams sampled were: influent,
effluent (permeate), recycle (retenate), solids blowdown, oil float, and the acid wash. The analytes
examined for each of these streams are as follows: oil and grease (EPA Methods 413.1 (total) and
M413.1 (soluble)), total petroleum hydrocarbons, metals, volatile organic analysis, extractable organics,
radionuclides (radium 226, radium 228, and gross alpha and beta), and total suspended solids.23
The unit studied has a design rated capacity of 5,000 barrels per day and is processing a portion
(slip stream) of the BPT produced water stream for pretreatment prior to waterflood. The membrane
filters consist of two ceramic membrane modules operating in parallel. The membranes have an absolute
pore size of 0.8 microns. The complete filtration system consists of the following equipment: filtration
modules, feed tank, backpulse tank, feed pump, backpulse pump, chemical feed system, and chemical
wash system. The system is skid mounted and .occupies a total area of four hundred square feet.
Analytical data and a discussion of the results of the membrane study are presented in Section
IX.5.2.4.
3.4,3 Evaluation of Gas Flotation Performance
EPA received gas flotation operating data from industry and conducted a literature search on the
operating characteristics of gas flotation units.
In 1991, as comments to the proposed rule, API submitted information on produced water
effluents that were from systems considered operating with improved performance. EPA's evaluation
of this data included a statistical analysis.24 Results of the statistical analysis are presented hi the report
entitled "Analysis of Oil and Grease Data Associated with Treatment of Produced Water by Gas
Flotation."
In 1992, EPA conducted a literature search on the operating characteristics of gas flotation
technology used for separation of oil from produced water. The literature search identified approximately
V-17
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ten useful documents detailing the operating characteristics of gas flotation technology.25 The results of
the literature search are contained in the report entitled "Oil/Water Separation by Gas Flotation."
t
3.4.4 Technical Feasibility of Brine Reinfection
The technical feasibility of offshore reinjection of produced water was evaluated to determine any
technical limitations that would preclude reinjection as a basis for zero discharge of produced water.26
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 knowledgeable of the offshore regions
subsurface geology. The offshore regions were evaluated for their sedimentological and tectonic history
to determine if suitable formations and conditions are available for disposal operations. Information was
also collected from onshore and coastal brine disposal operations. Also, 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 evaluation included the following findings:
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In general and except for the technical situations outlined below, brine reinjection, in the
coastal and offshore areas, as a form of pollution control is technologically feasible in all
coastal and offshore areas of the United States. The geology of these 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.
These areas will be rather site specific and reinjection in these areas will require careful
evaluation.
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
reinject because the oil is very viscous and waterflooding is necessary to obtain maximum
recovery. The capital investment in equipment thus has a definitive 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 hi
areas of known active faults, solution of in situ salt formations, and areas where the
geology is not detailed enough to a make a reasonable determination as to where injected
water may eventually migrate.
3.5 LITERATURE DATA COLLECTION FOR RADIOACTIVITY IN PRODUCED WATER
In 1992, EPA reviewed data presented in literature on the presence of radium in produced water
generated from onshore, coastal, and offshore production activities. The information and data obtained
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is presented in the following two reports: Presence of Radium in the Gulf of Mexico27 and Summary of
Produced Water Radioactivity Studies.
4.0 DATA COLLECTION FOR MISCELLANEOUS AND MINOR DISCHARGES
Previous data collections relating to miscellaneous and minor waste streams have been sporadic
in the numerous studies of offshore oil and gas discharges. EPA therefore conduced 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.29 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.
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.
5.0 ANALYTICAL METHODS
5.1 REVIEW OF STATIC SHEEN TESTING PROCEDURES
Since the proposal of the static sheen test in 1985, several variations to the method proposed in
1985 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 protocol of the 1985 proposal and the Region IX suggested methods is presented below:
Receiving water - The procedures proposed in 1985 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 procedure proposed in 1985 calls 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
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"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 paniculate
surface deposits. This appears to be the reason Region IX discourages mixing or stirring
activities.
Sample volumes/weights - The procedures proposed in 1985 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 procedure proposed in 1985 requires 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 1985 proposed method. Under Region DC 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 DC method.
The "minimal volume" test procedure requires a sample volume of 5 ml or weight 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.
A study was performed by industry which compared these static sheen methods.30 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 percent false
positives. The Region X method showed 2.5 percent and the minimal volume method showed 21.86
percent false positives.
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In 1989, EPA conducted an additional study solely on the minimal volume test.31 Twenty-six
individuals made observations on 56 muds samples at EPA's Gulf Breeze Laboratory. The results of this
evaluation were that for muds without oil, 6.0 percent false positives were recorded. The study revealed
that false negatives were more likely to occur if mineral oil was present in the sample as opposed to
diesel oil.
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5.2 ANALYTICAL METHOD FOR DIESEL OIL DETECTION
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, was subsequently modified based on experience gamed during the Diesel Pill
Monitoring Program. The revised version of Proposed Method 1651, "Oil Content and Diesel Oil in
Drilling Muds and Drill Cuttings by Retort Gravimetry and GCFID" appeared in Appendix A of the 1988
Federal Register Notice of Availability. However, this version was incomplete and later correctly
published in a 1989 Federal Register Notice (54 FR 634).
In the March 13, 1991 proposal notice (56 FR 10676), EPA identified the EPA Method 1651 as
adequate for use hi identifying the presence of diesel oil. However, work was continued on alternative
extraction and analysis techniques to simplify the operational portions of the method: and enable better
identification of diesel oil in the presence of interferences. As a result, EPA has developed test methods
for the measurement of the hydrocarbons normally found in oil, including the polynuclear aromatic
hydrocarbon (PAH) content of the oil. Combined, these techniques can be used to discern diesel oil in
the presence of other components likely to be found in drilling wastes. This section gives a brief history
of the efforts to develop test methods for the determination of diesel oil in drilling fluids and drill cuttings
and a description of test methods that have been developed to measure and differentiate diesel oil, mineral
oil, and crude oil.
In late 1990, the American Petroleum Institute (API) undertook a study of extraction and
determination steps necessary to identify unambiguously diesel oil in the presence of interferences, and
to overcome difficulties using Method 1651 . These studies involved the evaluation of alternate extraction
and determination techniques.
Extraction techniques included ultrasonic, Soxhlet/Dean-Stark, and supercritical fluid.
Determinative techniques included high performance liquid chromatography with ultraviolet detection
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(HPLC/UV), and gas chromatography with flame ionization detection (GC/FID). One device combined
extraction and determination. In this device, the drilling waste sample was placed in a small chamber
and heated rapidly to desorb the oil into a flowing gas stream. The components of oil entrained in the
gas stream were separated by gas chromatography, and detection by flame ionization.
On these devices, Soxhlet/Dean-Stark extraction provided the most precise results and the results
closest to true value, and HPLC/UV was found reliable for determining polynuclear aromatic
hydrocarbons (PAHs) in the extract. Results of these studies are summarized in an April 1992 API
Report, entitled, "Results of the API Study of Extraction and Analysis Procedures for the Determination
of Diesel Oil in Drilling Muds" (the API Report). A copy of the API Report is included in the record
for the rulemaking.
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Based on the additional methods work resulting from comments on the proposed Method 1651,
EPA is promulgating, in addition to the Method 1651, a test protocol measuring the PAH content by
HPLC/UV to demonstrate that the oil is mineral oil, and will allow measurement of the normal
hydrocarbon distribution by GC/FID to demonstrate that the oil is crude oil. However, EPA will not
allow use of the total oil content to demonstrate that the mud is free of diesel oil.
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EPA recognizes that in certain regions compliance with the diesel oil prohibition is accomplished
by GC analysis of end-of-well samples. In other regions, compliance with the diesel prohibition is
accomplished by review of well records maintained by platform operators to prove that diesel oil has not
been added to the mud system. Both methods of determining compliance are acceptable. However, in
the latter case where the enforcement agency believes that the well record is in error or has been falsified,
the authority may insist that further testing be conducted to prove that diesel oil has not been used.
In this further testing for the presence of diesel oil, the drilling fluid or drill cuttings are extracted
with a solvent and the amount of total extractable material is measured. If the material extracted exceeds
the amount attributable to additives, the material could be diesel oil, crude oil, or mineral oil, and the
next phase of testing must be conducted.
In this next phase, the PAH content of the oil in the drilling waste is determined using the
HPLC/UV Method. If the PAH content is less than that attributable to mineral oil, the mud may be
discharged; if greater than that attributable to mineral oil, the oil could be either diesel or crude oil. To
determine whether the oil is diesel or crude, the absence of n-alkanes hi the diesel range or the percent
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of C25 - C30 alkanes using the GC/FID Method must be used to show that the oil was crude oil from
the formation. If the oil was crude oil, the mud may be discharged providing it meets the other discharge
limitations of the rule.32
5.3 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 which is based on a freon extraction and is referred to as the
"gravimetric" method; and Standard Method 503E, known as EPA Method M413.1 and referred to as
the "silica gel" method.
Standard Method 503A is designed to extract dissolved or emulsified oil and grease from water
using trichlorotrifluoroethane (freon). This method measures total (soluble and insoluble) oil and grease.
Special precautions regarding temperature and solvent vapor displacement are included in the procedure
to minimize the oxidation of certain extractables. This method, measuring total (freon extractable) oil
and grease was used in developing the limitations for BPT, and this method is incorporated in the NPDES
discharge permits.
Standard Method 503E utilizes silica gel to extract polar materials, such as fatty acids, from the
sample before the extraction with freon. This method measures only a portion of the total 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.
5.4 DRILLING FLUIDS TOXICITY TEST
Final BAT and NSPS regulations include a limitation on the toxicity of discharged drilling fluids
and drill cuttings. The toxicity limit is expressed as the concentration of the suspended paniculate phase
(SPP) from a sample of drilling fluid that would be lethal to 50 percent of a particular species exposed
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to that concentration of the SPP, i.e., the LC50 of the discharge. The species used in the toxicity test
is mysidopsis bahia, also called mysid shrimp. In 1985, EPA proposed a toxicity limitation of 30,000
ppm based on the toxicity of the most toxic of eight generic drilling fluids that were in general use at the
time of the proposal. Since 1985, permit writers have set this limit as their best professional judgment
of BAT, and it is currently included in the general permits for oil and gas activities in the outer
continental shelf of the Gulf of Mexico and offshore of California and Alaska.
In 1991, EPA conducted a two phase study on the variation in results from the toxicity test for
drilling fluids 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 proposal.33-34-36-37
In Phase I, each lab was required to conduct one toxicity test on a sub-sample of generic drilling
fluid Number 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. At the time, the
Agency knew of over 100 commercial, academic, and industry labs that were potentially capable of
conducting the required test.
In Phase n, each selected lab was required to conduct two toxicity tests on sub-samples of generic
drilling fluid Number 8 (lignosulfonate freshwater mud) and two toxicity tests on sub-samples of generic
drilling fluid Number 8 with 3 percent mineral oil. A total of 12 labs were selected at random from those
Phase I labs that demonstrated the ability to conduct the toxicity test at a competitive price. However,
one of the labs selected for Phase II failed to complete the study.
A summary of the results for the 9 contract labs which completed the Phase II portion of the
study is presented in Table V-4. The results shown for the "selected" labs in the summary for generic
fluid Number 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 whereas the other 12 labs (making up the
total of 28 labs shown under the "all" category) did not completely follow the correct protocol.
The primary summary statistics included in the table are the average toxicity (LC50), standard deviation
(SD), predication intervals, and the coefficient of variation (CV).
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The average LC50 was slightly higher (less toxic) than expected for the sample of generic drilling
fluid Number 3 and for the sample of generic drilling fluid Number 8. However, the average LC50 I
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TABLE V-4
SUMMARY OF RESULTS FOR THE VARIABILITY STUDY36
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Combined Within and Between Lab Variation
Drilling Fluid
Generic #3
Generic #3a
Generic #8
Generic #8 with 3%
Oil
Number of
Contract Labs
28
16
9b
9b
Average LC50
(% spp)
25.6
22.6
46.9
0.33
Standard
Deviation
12.0
6.0
19.3
0.46
Between Lab Variation
Generic #8
Generic #8 with 3%
Oil
9b
9b
46.9
0.33
16.3
0.33
Coefficient of
Variation (%)
47.1
26.4
41.2
139.7
/
34.8
100.0
Within Lab Variation
Generic #8
Generic #8 with 3%
Oil
9b
9"
46.9
0.33
10.3
0.32
22.0
96.6
a "Well performing" contract labs
b Two contract labs had non-estimable LC50 values
Notes:
1)
2)
3)
4)
All LCSOs were 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.
Standard Deviation (SD) for combined within and between lab variation is the square root
for the sum of the within and between lab variances estimates.
Coefficient of Variation (CV) is equal to (SD)/(Average LC50)xlOO%.
reported for generic drilling fluid Number 8 with 3 percent 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.
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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 deviation (SD) reported hi Table V-4 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 Number 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 EPA is primarily interested in estimates
of within lab variation so these estimates are presented for generic drilling fluid Number 8 and generic
drilling fluid Number 8 with 3 percent mineral oil. Estimates of within lab variation 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,
for the most part, is caused by inconsistent lab practices and thus it can be modified through learning
from experience.
Coefficients of variation (CV) indicate how much, on a percentage basis, the LC50 could vary
within a single standard deviation. The CVs presented in Table V-4 are useful for comparison with lab
variation CVs estimated for other mysid toxicity tests, such as the American Petroleum Institute's niysid
toxicity test for drilling fluids, on materials of equal toxicity. Since the CV is calculated by dividing the
estimated standard deviation by the average LC50, it is important to realize that a large CV can occur
due to an average LC50 that seems small or an estimated standard deviation that seems large. That is
why lab CVs should only be compared between samples of equal toxicity. In the case of this lab
variability study, the average LCSOs seem to decrease, with increased toxicity, more rapidly than the
estimated standard deviations decrease. Hence, the CV appears to increase as the absolute variation,
measured by the standard deviation, decreases. However, since only three drilling fluids were tested by
appropriately selected labs, the basis for concluding mat a trend exists is weak.
Analysis of the multi-lab results for toxicity tests from this study continue to support the
conclusion that results from EPA's toxicity test for drilling fluids are reproducible in the sense that test
results for a single fluid appear to vary about an average toxicity. As the test is reproducible, it is
adequate for use hi a regulatory framework.
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6.0 REFERENCES
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1. Proposed Formulations for Generic Mud Samples. Letter to B. Telliard, Effluent Guidelines
Division, U.S. Environmental Protection Agency, from William J. Sallans, Petroleum Equipment
Suppliers Association, June 20, 1983. (Offshore Rulemaking Record Volume 12)
2. Jones, Maurice (Mo), "The Basics of Drilling Fluids," Georges Bank Hydrocarbon Exploration
and Development Conference, Proceedings Published by the American Society for Environmental
Education, Inc., April 27-30, 1982. (Offshore Rulemaking Record Volume 23)
3. T.W. Duke et al., "Acute Toxicity of Eight Laboratory-Prepared Generic Drilling Fluids to
Mysids (Mysidopsis bahia)," Gulf Breeze Environmental Research Laboratory, Office of
Research and Development, U.S. Environmental Protection Agency, May 1984. (Offshore
Rulemaking Record Volume 12)
4. CENTEC Analytical Services Inc., "Results of Laboratory Analysis and Findings Performed on
Drilling Fluids and Cuttings - Draft," submitted to Effluent Guidelines Division, U.S.
Environmental Protection Agency, April 3, 1984. (Offshore Rulemaking Record Volume 13)
5. Survey Results on "Use of Hydrocarbons for Fishing Operations," and "Use of Hydrocarbons
as Lubricity Agents." Attachments to Letter from J.A. Burgbacher, Shell Offshore, Inc., to D.
Ruddy, Industrial Technology Division, U.S. Environmental Protection Agency, October 30,
1985. (Offshore Rulemaking Record Volume 60)
6. API Drilling Fluids Survey Results. Letter from T.M. Randolph, American Petroleum Institute's
NSPS/BAT Offshore Guidelines Committee, to D. Ruddy, Industrial Technology Division, U.S.
Environmental Protection Agency, October 23, 1986. (Offshore Rulemaking Record Volume 60)
7. Offshore Operators Committee, "Gulf of Mexico Spotting Fluid Survey," by R.C. Ayers., Jr.,
and J.E. O'Reilly, Exxon Production Research Company, and L.R. Henry, Chevron, USA, Inc.,
April 4, 1987. (Offshore Rulemaking Record Volume 60)
8. R.C. Ayers et al., "The EPA/API Diesel Pill Monitoring Program," presented at the 1988
International Conference on Drilling Wastes, Calgary, Alberta, Canada, April 5-8, 1988.
(Offshore Rulemaking Record Volume 65)
9. SAIC, "Descriptive Statistics and distributional Analysis of Cadmium and Meircury
Concentrations in Barite, Drilling Fluids, and Drill Cuttings from the API/USEPA Metals
Database," prepared for Industrial Technology Division, U.S. Environmental Protection Agency,
February 1991. (Offshore Rulemaking Record Volume 120)
10. Kohlmann Ruggiero Engineers, P.C., "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," prepared for Industrial Technology Division, U.S.
Environmental Protection Agency, March 25, 1987. (Offshore Rulemaking Record Volume 66)
1 1 . ERCE, "Onshore Disposal of Offshore Drilling Waste - Capacity and Cost of Onshore Disposal
Facilities," prepared for Industrial Technology Division, U.S. Environmental Protection Agency,
January 1990. (Offshore Rulemaking Record Volume 129)
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12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
Minerals Management Service, New Orleans Field Office, "An Analysis of Oil-Field Waste
Commercial Facility Capacity for Receipt of OCS-Generated Wastes," June 3, 1992.
SAIC, "California Landfill Capacity," prepared for Engineering and Analysis Division, U.S.
Environmental Protection Agency, December 1992.
SAIC, "Evaluation of Personnel Injury/Casualty Data Associated with Drilling Activity for the
Offshore Oil and Gas Industry," prepared for Engineering and Analysis Division, U.S.
Environmental Protection Agency, October 8, 1992.
Collinge, J. Alan, "Auditing Reduces Accidents by Eliminating Unsafe Practices," Oil & Gas
Journal, August 24, 1992.
Crest Engineering Inc., "Oil Content in Produced Brine on Ten Louisiana Production Platforms,"
prepared for Municipal Environmental Research Laboratory, U.S. Environmental Protection
Agency, Cincinnati, Ohio, 1.981. (Offshore Rulemaking Record Volume 27)
Burns and Roe Industrial Services Corp., "Sampling Plan, Preliminary Sampling Program for
Priority Pollutants, Offshore Oil and Gas Industry," Prepared for Effluent Guidelines Division,
U.S. Environmental Protection Agency, May 1981. (Offshore Rulemaking Record Volume 4)
Burns and Roe Industrial Services Corp., "Sampling and Logistics Plan for EPA Priority
Pollutant Sampling Program, Offshore Oil and Gas Industry," prepared for Effluent Guidelines
Division, U.S. Environmental Protection Agency, October 5, 1981. (Offshore Rulemaking
Record Volume 5)
Rockwell International Corp., "Priority Pollutants in Offshore Produced Oil Brines," prepared
for Industrial Environmental Research Laboratory, and Oil and Hazardous Materials Spills
Branch, U.S. Environmental Protection Agency, December 1982. (Offshore Rulemaking Record
Volume 7)
ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the THUMS Long Beach Company Agent for the Field Contractor Long beach Unit -
Island Grissom City of Long Beach - Operator," Draft, prepared for Industrial Technology
Division, U.S. Environmental Protection Agency, March 1990. (Offshore Rulemaking Record
Volume 113)
ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the Shell Western E & P, Inc. - Beta Complex," Draft, prepared for Industrial
Technology Division, U.S. Environmental Protection Agency, March 1990. (OffshoreRulemaking
Record Volume 114)
ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the Conoco, Inc. - Maljamar Oil Field," Draft, prepared for Industrial Technology
Division, U.S. Environmental Protection Agency, revised January March 1990. (Offshore
Rulemaking Record Volume 115)
SAIC, "Trip Report for the Sampling of the Membrane Filtration Unit at the Marathon Oil Co. -
Eugene Island 349-B Platform," prepared for Engineering and Analysis Division, U.S.
Environmental Protection Agency, January 13, 1993.
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24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
Memorandum from Charles E. White, USEPA, to Ronald Jordan, USEPA, "Produced Water
Limitations for Oil and Grease that are Based on Improved Performance of Gas Flotation "
January 13, 1993.
SAIC "Oil/Water Separation by Gas Flotation," prepared for Engineering and Analysis Division,
U.S. Environmental Protection Agency, November 9, 1992.
ERCE, "An Evaluation of Technical Exceptions for Brine Reinjection for the Offshore Oil and
Gas Industry," prepared for Industrial Technology Division, U.S. Environmental Protection
Agency, January 1990. (Offshore Rulemaking Record Volume 119)
Environmental Protection Agency, "Prevalence of Radium in the Gulf of Mexico " January 11
1993. J '
SAIC, "Summary of Produced Water Radioactivity Studies," prepared for Engineering and
Analysis Division, U.S. Environmental Protection Agency, January 13, 1993.
SAIC, "Summary of Data Relating to Miscellaneous and Minor Discharges from Offshore Oil
and Gas Structures," prepared for Industrial Technology Division, U.S. Environmental Protection
Agency, February 1990. (Offshore Rulemaking Record Volume 118)
M. Jones and G. Otto, "Draft Final Report: An Evaluation of the Proposed EPA Laboratory
Static Sheen Test Procedures," prepared for the Task Force on Environmental Science, Offshore
Operators Committee, February 14, 1986. (Offshore Rulemaking Record Volume 121)
Letter from Dennis Ruddy, Industrial Technology Division, EPA, to James Ray, Shell Oil
Corporation, "Minimal volume static sheen test method and the results of the Agency's evaluation
of this test method," May 30, 1989. (Offshore Rulemaking Record Volume 121)
Methods for the Determination of Diesel, Mineral, and Crude Oils in Offshore Oil and Gas
Industry Discharges, U.S. Environmental Protection Agency, Office of Water, Engineering and
Analysis Division, EPA 821-R-92-008, December 1992.
Avanti Corporation and Technical Resources, Inc., "A Variability Study of the NPDES Drilling
Fluids Toxicity Test," prepared for the Industrial Technology Division, U.S. Environmental
Protection Agency, January 31, 1991. (Offshore Rulemaking Record Volume 121)
Avanti Corporation and Technical Resources, Inc., "A Variability Study of the NPDES Drilling
Fluids Toxicity Test: Results of the Telephone Questionnaire," prepared for the Industrial
Technology Division, U.S. Environmental Protection Agency, January 31, 1991. (Offshore
Rulemaking Record Volume 121)
Memorandum from Charles White, EPA, to Marvin Rubin, EPA, "Transmittal of Report on
Analyses Requested to Support Limitations of Metals in Drilling Wastes," February 28, 1991.
White, Charles E., "Variability Study of the EPA Toxicity Test for Drilling Fluids: Preliminary
Statistical Analysis," March 4, 1991.
Variability Study of the EPA Toxicity Test for Drilling Fluids: Statistical Analysis, Office of
Science and Technology, U.S. Environmental Protection Agency, January 13, 1993.
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SECTION VI
SELECTION OF POLLUTANT PARAMETERS
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1.0 INTRODUCTION
This section of the document presents information concerning the selection of the pollutant
limitations for the Final Offshore Oil and Gas Extraction Effluent Limitations Guidelines and Standards.
The information consists of identifying the pollutants for which limitations and standards are set and
discussions of the pollutants controlled by the "indicator" pollutants that have limitations in the rule and
pollutants not specifically limited in the rule.
The section identifies and discusses the pollutant by wastestream.
2.0 DRILLING FLUIDS AND DRILL CUTTINGS
In the Offshore Oil, and Gas Effluent Guidelines and Standards, EPA is controlling pollutants
found in drilling fluids and drill cuttings as follows: zero discharge of drilling fluids and drill cuttings
within three miles from shore; and for discharge of drilling fluids and drill cuttings at distances greater
than three miles from shore: a prohibition on the discharge of diesel oil, a prohibition on the discharge
of free oil, limitations on tfie toxicity of the drilling fluids and drill cuttings, and limitations on mercury
and cadmium in stock barite. These limitations represent the appropriate level of control under BAT,
BCT and NSPS for these indicators and the constituents they control.
The specific, conventional, toxic and nonconventional pollutants found to be present and their
concentrations in drilling fluids and drill cuttings, including compositions with diesel and mineral oils
added, are summarized in Table YE-5, "Pollutant Analysis of Generic Drilling Fluids," Table VD:-6,
"Organic Pollutants Detected hi Generic Drilling Fluids, Table VII-7, "Metal Concentrations in Generic
Drilling Fluids," and Table VII-9, "Organic Constituents of Diesel and Mineral Oils." Toxic organic
compounds and metals identified in these data summaries include naphthalene, phenanthrene, phenol,
zinc, lead, chromium, and copper.
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In addition, these data summaries include the conventional pollutants, BOD and oil and grease,
along with nonconventional pollutants, including chemical oxygen demand (COD) and numerous alkylated
phenols, benzenes, fluorenes and others. EPA has determined that it is not technically feasible to control
specifically each of the toxic constituents of drilling fluids and drill cuttings that are controlled by the
limits on diesel oil and free oil. The prohibitions on discharge of free oil and diesel oil contained in the
rule (in addition to the zero discharge requirement within three miles) effectively remove these toxic
pollutants from the discharges and reflect control at the BAT and NSPS levels. In addition, limitations
on toxicity and cadmium and mercury content in barite control toxic and rionconventional pollutants in
drilling fluids and drill cuttings waste discharges at the BAT and NSPS levels, as is set forth below. EPA
has determined that it is not technically feasible to control specifically the toxic pollutants controlled by
the mercury and cadmium limits.
Use of these limitations as indicators for the control of other specific constituents or for removing
specific compounds is discussed further below.
2.1 DIESEL OIL
In the Offshore Guidelines, EPA is prohibiting the discharge of drilling fluids and drill cuttings
containing diesel oil. Drilling fluids containing diesel oil contain a number of toxic and nonconventional
pollutants as discussed above (also see Table VH-9). Diesel oil may contain from 20 to 60 percent by
volume polynuclear aromatic hydrocarbons (PAHs) which constitute the more toxic components of
petroleum products. Diesel oil also contains a number of nonconventional pollutants, including PAHs
such as methylnaphthalene, methylphenanthrene, and other alkylated forms of the listed organic priority
pollutants.
Prohibiting discharge of diesel oil, therefore, eliminates discharge of the above listed constituents
of diesel oil. As shown in Table VII-6, the generic water-based drilling fluids with and without mineral
oil contain substantially less biphenyl and phenanthrene (especially without mineral oil).
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 drilling fluids, as
compared to the quantity of these pollutants present when using diesel oil as an additive. Mineral oUs,
with their lower aromatic hydrocarbon content and lower toxicity, contain lower concentrations of some
of the same pollutants than diesel oil.
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2..Z FREE OIL
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In the Offshore Guidelines, EPA is also prohibiting the discharge of drilling fluids and drill
cuttings containing free oil. The technology basis for this limitation is substitution of water-based fluids
for oil-based fluids, non-petroleum oil containing additives and minimization of the use of mineral oil.
An additional technology basis for compliance with the prohibition on the discharge of free oil is
transporting the drilling wastes to shore for treatment and either disposal or reuse. Transporting the
drilling wastes to land would be used instead of product substitution when crude oil contaminates the used
drilling fluids due to the contribution of the oil from the formation being drilled. In these situations,
toxic and nonconventional pollutants contained in crude oil are eliminated from discharge. Free oil is
being regulated under BAT and NSPS as an "indicator" pollutant for the control of toxic pollutants. Free
oil is being regulated under BCT as well. Although it is not a listed 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, including crude oil from the formation being drilled.
Free oil and diesel oil are both related to the concentration of toxic as well as conventional and
nonconventional pollutants present in those oils. The pollutants "diesel oil" and "free oil" are considered
to be "indicators" and to control, respectively, specific toxic pollutants present in the complex
hydrocarbon mixtures used in drilling fluid systems. These pollutants include benzene, toluene,
ethylbenzene, naphthalene, phenanthrene, and phenol.
Prohibiting discharge of free oil eliminates discharge of the above-listed constituents, to the extent
that these constituents are present to a lesser degree in substitute fluids and additives. Prohibiting the
discharge of free oil also reduces the level of oil and grease present in the discharged drilling fluids and
drill cuttings.
2.3 TOXICITY
Acute toxicity is a measurement used to determine levels of pollutant concentrations which can
cause lethal effects to a certain percentage of organisms exposed to the suspended particulate phase (SPP)
of the drilling fluids and drill cuttings. As is the case with the other limitations for control of drilling
fluids and drill cuttings, the technology basis for the toxicity limitation is product substitution, i.e.,
substitution of less toxic drilling fluids for the more toxic drilling fluids, or if the toxicity limitation
cannot be met, transporting the drilling fluids and drill cuttings to shore for disposal. By limiting
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toxicity, operators use less toxic drilling fluids (basic compositions and additives), and the result is lower
amounts of pollutants being discharged.
Additives such as oils and some of the numerous specialty additives, especially biocides, may
greatly increase the toxicity of the drilling fluid and the drill cuttings due to the adherence of drilling fluid
to the cuttings. The toxicity is, in part, caused by the presence and concentration of toxic pollutants.
However, control of free oil and diesel oil, in some cases, is not an effective means of regulating these
additives since they are not diesel oil nor do they contain constituents with a free oil component. A
toxicity limitation requires that operators also must consider toxicity in selecting additives and select the
less toxic alternatives. Thus, the toxicity limitation will also serve to reduce discharges of toxic and
nonconventional pollutants. The limitation would encourage the use of the lowest toxicity generic water-
based drilling fluids (see Section VII) or newer drilling fluid compositions with lower toxicity than the
generic fluids, and the use of low-toxicity drilling fluid additives (i.e., product substitution).
Toxicity of drilling fluids and drill cuttings is being regulated as a nonconventional pollutant that
controls certain toxic and nonconventional pollutants. The results of the round robin toxicity testing
summarized in Table V-4, Section V of this document show how regulation of toxicity directly controls
the type and amount of mineral oil (and the pollutants, such as the PAHs, identified as constituents of
mineral oil). Addition of three percent mineral oil resulted in a significant increase in toxicity which
would have resulted in noncompliance and transport of the drilling muds to land for disposal.
Barite is mined from either bedded or veined deposits. Research has shown that bedded deposits
are characterized by substantially lower concentrations of heavy metal contaminants including mercury
and cadmium. (See Table Vn-2.)
In the final rule, EPA is limiting mercury and cadmium to 1 mg/1 and 3 mg/1 in stock barite.
This limitation indirectly controls the levels of toxic pollutant metals because cleaner barite that meets
the mercury and cadmium limits is also likely to have reduced concentrations of other metals. Evaluation
of the relationship between cadmium and mercury and the trace metals in barite shows a correlation
between the concentration of mercury with the concentration of arsenic, chromium, copper, lead,
molybdenum, sodium, tin, titanium and zinc; and the concentration of cadmium and concentrations of
arsenic, boron, calcium, sodium, tin, titanium and zinc. (SAIC, "Descriptive Statistics and Distributional
Analyses of Cadmium and Mercury Concentrations in Barite, Drilling Fluids, and Drill Cuttings from
the API/USEPA Metals Database," February 1991).
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2.4 POLLUTANTS NOT REGULATED
While the four limitations above limit the discharge of toxic and nonconventional pollutants found
in drilling fluids and drill cuttings, and the conventional pollutant oil and grease, EPA has determined
that certain of the toxic and nonconventional pollutants are not controlled by the limitations on diesel oil,
free oil, toxicity, and mercury and cadmium in stock barite. EPA exercised its discretion not to regulate
these pollutants because EPA did not detect these pollutants in more than a very few of the samples within
the subcategory and does not believe them to be found throughout the offshore subcategory; the pollutants
when found are present in trace amounts not likely to cause toxic effects; and due to the large number
and variation in additives or specialty chemicals that are only used intermittently and at a wide variety
of drilling locations, it is not feasible to set limitations on specific compounds contained in additives or
specialty chemicals.
3.0 PRODUCED WATER
In the Offshore Guidelines, EPA is controlling pollutants contained in produced water by limiting
oil and grease to 29 mg/1 monthly average and a 42 mg/1 daily maximum. These limitations represent
the appropriate level of control under BAT and NSPS. Pollutants contained in produced water discharges
from platforms with treatment systems used to meet the BPT level permit limits were identified by
evaluating effluent data from the 30-platform study. A summary of the data from the 30 platforms is
contained in Appendix 2 of this document. This study identified seven organic toxic pollutants and one
priority metal as being present in produced water discharges following treatment for oil and grease (oil
removal). The toxic pollutants are toluene, phenol, naphthalene, ethylbenzene, benzene, 2,4-
dimethylphenol, bis(2-ethylhexyl) phthalate and zinc, and the long-term concentrations of these analytes,
as determined from the 30-platform data set, are contained in Table IX-9, Section IX of this document.
Additional toxic metals are identified as a result of the data evaluation (cadmium, copper, lead, nickel
and silver) at much lower concentrations than zinc. The concentration of 2,4-dimethylphneol (at 14.4
/t/1) is also much lower than the other organic priority pollutants contained in Table IX-9. In addition,
as shown in Table IX-8, the percent occurrence for other toxic organic pollutants in the effluent samples
was lower for several analytes (10-32 percent), very low for a number of analytes (2-7 percent), and! not
detected at all for a large number of the priority organic pollutants. Results of this evaluation are used
since the 30 platforms were selected for characteristics such as wide geographical distribution and type
of production.
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Oil and grease serves as an indicator for toxic pollutants in the produced water waste stream,
including phenol, naphthalene, ethylbenzene, and toluene. EPA has determined that it is not technically
feasible to control these toxic pollutants specifically, and that the limitations on oil and grease in produced
water reflect control of these toxic pollutants at the BAT and NSPS levels.
As part of the Agency's evaluation of pollutant loading reductions for the various technology
based options considered, additional data on discharges of priority toxic and nonconventioiial pollutants
were evaluated. A number of studies, in addition to the 30-Platform Study, were evaluated and estimates
concerning other pollutants being discharged and their concentrations at the various levels of control
technology were made. The results of these estimates are contained in Section IX of the document in
Table K-9, Pollutant Concentrations in BPT Treated Produced Water From the 30 Platform Study. A
summary of the pollutant data from these studies is also shown in Appendix 2.
Data from these studies, except for the 30-Platform Study data discussed previously in this
section, are not appropriate for use in either setting limitations or in evaluating their removals directly
or incidental to the use of technology for removal of oil and grease. For most of the studies, i.e., those
submitted by industry during the development of the limitations, there is a lack of sufficient information
on sampling protocols, analytical procedures and the quality control assurance, and production activity
during the tune of sampling. For the three-facility filtration study, the data is an estimate of BFf level
treatment (prior to filtration) since these facilities were selected because of the use of filtration
technology, and were not treating the waters for discharge since the facilities were reinjecting the
produced water for secondary recovery purposes.
The feasibility of regulating separately each of the constituents of produced water determined
from the 30-Platform Study data was evaluated. As discussed above, because of the limitations of the
other data sets all of the pollutants used for loadings estimates were not deemed appropriate for
consideration for discharge limits without more data. Other factors considered in the determination that
setting limitations on all of those pollutants is not feasible or is not necessary in some cases are: the
variable nature of the number of constituents in the produced water, impracticality of measuring a large
number of analytes, many of them at or just above trace levels, use of technologies for removal of oil
(as oil and grease) which are effective in removing many of the specific pollutants, and that many of the
organic pollutants are directly associated with oil and grease because they are constituents of oil thus are
directly controlled by the oil and grease limitation. EPA believes that the limitations on oil and grease
contained in the Offshore Guidelines effectively control levels of certain toxic and nonconventional
pollutants. EPA has data that demonstrate that control of oil and grease controls the toxic pollutants
shown in Table IX-9.
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Use of the gas flotation technology with chemical addition removes both metals and organic
compounds. The insoluble metal hydroxide particle formation and adsorption by the chemical (polymer)
floe of oil and the action of the gas bubbles forces both the oil (oil and grease) containing floe and metal
hydroxide floe to the surface for removal (skimming), thus resulting in lower concentration levels in the
discharge for the above priority pollutants. (See Section IX for discussions of gas flotation technology.)
3.1 POLLUTANTS NOT REGULATED
While the limitations above limit the discharge of toxic and nonconventional pollutants determined
to be present in produced water treated to meet BPT control > EPA has determined that certain of the toxic
priority pollutants, such as pentachlorophenol, 1,1-dichloroethane, and bis(2-chloroethyl) ether are not
controlled by the limitations on oil and grease in produced water. EPA exercised its discretion not to
regulate these pollutants because EPA did not detect them in more than a very few of the samples within
the subcategory (see Table IX-8, Percent Occurrence of Organics for Treated Effluent Samples, 30
Platform Study); and the pollutants when found were present in trace amounts not likely to cause toxic
effects.
4.0 WELL TREATMENT, COMPLETION AND WORKOVER FLUIDS
In the Offshore Guidelines, EPA is controlling pollutants found in well treatment, completion and
workover fluids commingled and treated with produced water by limiting oil and grease to 29 mg/1
monthly average and a 42 mg/1 daily maximum. Separate discharges of these wastes are limited by both
the above oil and grease limitations and a prohibition on the discharge of free oil. These limitations
represent the appropriate level of control under BAT and NSPS.
The pollutants identified to be present in well treatment, completion and workover fluids are
summarized in Tables X-12, X-13, and X-14 for workover, completion and well treatment fluids.
Oil and grease serves as an indicator for toxic pollutants in the well treatment, workover and
completion fluids waste stream, including, phenol, naphthalene, ethylbenzene, toluene, and zinc. EPA
has determined that it is not technically feasible to control these toxic pollutants specifically, and that the
limitations on oil and grease in well treatment, workover, and completion fluids reflect control of these
toxic pollutants at the BAT and NSPS levels.
EPA has determined, moreover, that it is not feasible to regulate separately each of the
constituents in well treatment, completion and workover fluids because these fluids in most instances
become part of the produced water wastestream and take on the same characteristics as produced water.
Due to the variation of types of fluids used, the volumes used and the intermittent nature of their use,
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EPA believes it is impractical to measure and control each parameter. However, because of the similar
nature and commingling with produced water, the limitations on oil and grease in the Offshore Guidelines
will control levels of certain toxic priority and nonconventional pollutants for the same reason as stated
in the previous discussion on produced water.
4.1 POLLUTANTS NOT REGULATED
While the oil and grease and, in certain instances, the no free oil limitations limit the discharges
of toxic and nonconventional pollutants found hi well treatment, completion and workover fluids, certain
other pollutants are not controlled. EPA exercised its discretion not to regulate these pollutants because
EPA did not detect them in more than a very few of the samples within the subcategory and does not
believe them to be found throughout the offshore subcategory; and the pollutants when found are present
in trace amounts not likely to cause toxic effects.
5.0 PRODUCED SAND
In the offshore Oil and Gas Effluent Guidelines, EPA is controlling all pollutants found hi the
produced sand wastestream by a zero discharge limitation. This limitation represents the appropriate level
of control under BAT, BCT and NSPS.
Produced sand consists of the slurried particles used in hydraulic fracturing and the accumulated
formation sands and other particles (including scale) generated during production. This wastestream also
includes sludges generated by a chemical polymer used in the flotation or filtration (or other portions)
of the produced water treatment system. Produced sand is generally contaminated with crude oil from
oil production or condensate for gas production. In addition, some produced sand contains elevated levels
of naturally occurring radioactive materials (NORM).
The specific conventional, toxic and nonconventional pollutants found to be present in produced
sand are summarized in Table X-2, Average Oil Content in Produced Sand, Tables X-3 and X-4,
Summary of Radioactivity Data for Produced Sand from OOC Survey and Average Radioactivity Levels
in Produced Sand, respectively, and Table Xffl-2, Produced Sand Characteristics. The specific pollutants
controlled by the limitation are oil and grease, TSS, and priority and nonconventional pollutants
constituents of oil including those described previously in this section. In addition, radium 226 and
radium 228, which are NORM and considered to be nonconventional pollutants are controlled with the
elimination of discharges of produced sand that contain elevated levels of NORM.
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6.0 DECK DRAINAGE
In the Offshore Oil and Gas Effluent Guidelines, EPA is controlling pollutants found in deck
drainage by the prohibition on the discharge of free oil. This limitation is the current BPT level of
control and represents the appropriate level of control under BCT, BAT and NSPS.
The specific conventional, toxic and nonconventional pollutants found to be present in deck
drainage are those primarily associated with oil, with the conventional pollutant oil and grease being the
primary constituent. In addition, other chemicals used in the drilling and production activities and stored
on the structures have the potential to be found in deck drainage. The specific pollutant concentration
ranges found in untreated deck drainage are summarized in Table X-16, Characteristics of Deck Drainage
from Offshore Platforms and Table X-17, Pollutant Concentrations in Untreated Deck Drainage.
The specific conventional, toxic and nonconventional pollutants controlled by the prohibition on
the discharges of free oil are the conventional pollutant oil and grease and the constituents of oil that are
toxic and nonconventional pollutants (see previous discussion in Subsection 2.2 of this section describing
the chemical constituents of oil). EPA has determined that it is not technically feasible to control these
toxic pollutants specifically, and that the limitation on free oil in deck drainage reflects control of these
toxic pollutants at the BAT and NSPS level. In addition, the use of best management practices in order
to prevent the buildup of waste material on deck surfaces due to spillage, minimize the use of soaps and
detergents in deck cleaning, and perform deck washdowns more often to prevent overload of the oil
separating devices during rainfall events will reduce the amount of pollutants entering the deck drainage
waste stream.
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As discussed in the Basis for Regulation, Section XV of this document, additional controls on
deck drainage were rejected based on the technical infeasibility of deck drainage add-on systems to
existing sump and skim pile systems currently being used. Deck drainage discharges are not continuous,
vary significantly in volume, and contain a wide range of chemical constituents and concentration levels
of the constituents, many of which are at or near trace levels. At tunes of platform washdowns, the
discharges are of relatively low volume and anticipated; during rainfall events, very large, unanticipated
volumes may be generated.
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7.0 REFERENCES
SAIC, "Descriptive Statistics and distributional Analysis of Cadmium and Mercury Concentrations in
Barite, Drilling Fluids, and Drill Cuttings from the API/USEPA Metals Database," prepared for
Industrial Technology Division, U.S. Environmental Protection Agency, February 1991. (Offshore
RuIemaJdng Record Volume 120).
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SECTION VII
DRILLING FLUIDS -
CHARACTERIZATION, CONTROL AND TREATMENT TECHNOLOGIES
1 .0 INTRODUCTION
The first part of this section describes the sources, volumes,
generated from offshore oil and gas exploration and development
section describes the control and treatment technologies currently
drilling fluids and the quantities of pollutants discharged to surface
2.0 DRILLING FLUIDS SOURCES
and characteristics of drilling fluids
activities. The second part of this
available to reduce the volume of
waters.
i Drilling fluids, or muds, are suspensions of solids and other materials in a base of water or oil
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which is specifically formulated to: lubricate and cool the drill bit,
the surface, and maintain downhole hydrostatic pressure. Drilling
carry drill cuttings from the hole to
fluids typically contain a variety of
specialty chemicals to: control density (weight) and viscosity, reduce fluid loss to formation, and inhibit
corrosion, etc.
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formulated, the fluid is pumped down the drill pipe and ejected to the borehole through the drill bit. The
drilling fluid returns to the surface through the annulus (space between the casing and the drill pipe).
As the mud travels up the annulus, it carries the drill cuttings in suspension. The mud passes through
the solids control equipment (shaleshaker, screens, hydrocyclones, etc.) to remove the cuttings, and is
returned to the mud tank for recirculation.
Excess drilling fluids are removed from the mud circulation system during the drilling operation
and at the end of the drilling program for various reasons. Excess drilling fluids are generated during
drilling because: (1) At deeper depths the borehole is smaller, requiring less volume of drilling fluid,
(2) The mud is diluted to maintain constant Theological properties, and (3) The entire mud system is
periodically changed over in response to changing drilling conditions. At the end of the drilling program,
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the remaining mud left over in the circulation system and the storage tanks is either considered waste or
recycled and/or regenerated for future use.
3.0 DRILLING FLUIDS VOLUMES
Drilling fluids discharges are typically in bulk form and occur intermittently during well drilling
and at final well depth. Low volume bulk discharges are the most frequent and are associated with mud
dilution, the process of maintaining the required level of solids hi the fluid system. High volume bulk
discharges occur less frequently during a well drilling operation, and are associated with drilling fluid
system changeover and/or emptying of the mud tank at the end of the drilling program.
The volume of drilling fluid generated and the volume of drill cuttings recovered at the surface
will depend on the following:1
Size and type of drill bit
Hole enlargement
Type of formation drilled
* Efficiency of solids control equipment
Type of drilling fluid
Density of drilling fluid.
The size and type of drill bit determine the borehole diameter and the characteristics of the drill
cuttings generated. Drill bits with large teeth produce large cuttings while other bits, like diamond bits,
produce small cuttings, often in the powder form. Very fine solids from drill cuttings are entrained into
the drilling fluid and can significantly effect the mud's Theological properties.
The amount of hole enlargement and type of formation determine the amount of drill cuttings
brought to the surface. The hole volume can increase by as much as fifty percent due to erosion of the
borehole from mud circulation. The amount of borehole wall erosion, or sloughing, is also dependent
on the type of the formation being drilled. Soft formations will erode more than hard stable formations.
The type of formation also determines the characteristics of the drill solids that disperse into the drilling
fluid.
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The efficiency of the solids control system is a major factor in the amount of excess drilling fluids
generated. The solids control system is a mechanical separation process designed to separate the drilled
solids from the drilling fluid. The combined drilling fluid and drill cuttings stream is processed in the
solids control system and the drilling fluid is pumped downhole after the drill solids are removed. Solids
control efficiency is based on the system's ability to remove a high percentage of low gravity drill solids
from the mud. The low gravity solids adversely affect the Theological characteristics of the mud
(viscosity, density, gel strength, etc.). The only method to counter the effect of the low gravity solids
concentrating in the drilling fluid (after mechanical solids control) is mud dilution or displacement.
Dilution and displacement are techniques of reformulating the mud to its original characteristics through
removing a portion of mud from the system and adding water or fresh mud to the existing mud system.
Poor solids control efficiency results in a large volume of excess drilling fluid because of the frequent
dilutions required to maintain the required mud characteristics.
The type and density of the drilling fluid also determines the amount of excess drilling fluid
generated. The Drilled solids well disperse less in some muds than others. For example drilled solids
disperse less in potassium chloride and oil based-muds than in water-based muds. The density of the
drilling fluid determines the total volume of the drilling fluid generated since- more mud products are
added to the fluid to increase the density.
A distinction should be made between the volume of drilling fluids formulated, or generated, and
the volume of drilling fluids discharged. Some drilling fluid is lost to the geologic formations or left hi
the well annulus at the completion of drilling. Ayers, et al.2 presented a materials balance estimate of
drilling fluids components used in a Mid-Atlantic drilling operation. Of the 866 metric tons of barite
used, 87 percent was discharged, 6 percent was left downhole, and 7 percent was unaccounted for. For
bentonite plus drilled solids, 89 percent was discharged, 1 percent was left downhole, and 10 percent was
unaccounted for. For the combined usage of lignite, chrome lignosulfonate, and cellulose polymer, 95
percent of the material was discharged and 5 percent was unaccounted for. The volumes not accounted
for were assumed to be lost to the formations and/or left downhole.
A report by the Offshore Operators Committee presented data from two drilling projects in the
Gulf of Mexico.1 The report presented drilling data from a 10,000 foot well and a 18,000 foot well.
Table VE-l presents volumes of drilling fluids and drill cuttings discharged for both wells. The drilling
fluid system used in both drilling projects was a seawater/bentonite mud to 4,500 feet and a lignosulfonate
mud to final well depth. The volumes of drilling fluids generated includes fluids lost to the formation
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and drilled solids incorporated into the drilling fluid. The solids control system was assumed to be
operating at fifty percent efficiency. In estimating the amount of cuttings and muds generated for the
compliance cost analysis, EPA used the volume estimates presented in this report as a basis.
TABLE VIM
VOLUME OF DRILLING FLUID & CUTTINGS DISCHARGED1
Depth of Interval
(Feet) ;
0-150
150-1,000 (850)
1,000 - 4,500 (3500)
4,500 - 10,000 (5500)
4,500 - 12,000 (7500)
12,000 - 18,000 (6000)
)tfc% Sfe0 {In,)
10,000
36
25
18
11
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18,000
36
32
20
-
15
10
tbtal Volume
Hole Volume
(Bfafc.)
10,000
188
516
1,102
647
-
-
2,453
18,000
188
846
1,361
-
1,641
583
4,619
Cuttings
Discharge
10,000
188
258
551
433
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-
1,430
18,000
188
423
680
-
1,100
390
Z,7&
Fluid Generated
(Bhls.)
10,000
-
3,133
6,691
2,593
-
-
EM17
18,000
-
5,136
8,263
-
6,575
2,336
;&ฃซ
TOuid Vol.
Discharge
C&bte.)
10,000
-
1,477
2,012
1,860
-
-
5,34$
18,000
-
1,956
2,237
-
3,713
2,580
U&6
4.0 DRILLING FLUIDS CHARACTERIZATION
Several broad categories of drilling fluids exist such as: water-based fluids (fresh or salt water),
low solids polymer fluids, oil-based fluids, and oil emulsion fluids. This document discusses only the
characteristics of water-based and oil-based fluids because they represent the majority of drilling fluids
currently used in offshore drilling operations.
Oil-based muds are only used for specific drilling conditions because they cannot be discharged
and thus are more expensive to use than water-based muds. The discharge of oil-based muds and
associated cuttings is prohibited under the BPT limitation of "no discharge of free oil." Industry has
indicated that oil-based drilling fluids continue to be the material of choice for certain drilling conditions.
These conditions include the need for thermal stability when drilling high-temperature wells, specific
lubricating characteristics when drilling deviated wells, and the ability to reduce stuck pipe or hole wash-
out problems when drilling thick, water-sensitive shales. In 1991, the industry estimated that oil-based
muds are used for approximately 15 percent of wells drilled greater than 10,000 feet.3 A primary
concern when using conventional, oil-based mud systems is their potential for adverse environmental
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impact in the event of a spill. Because of the relatively high toxicity of diesel oil, some mineral oil-based
mud systems have recently replaced diesel oil-based muds.
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The majority of mud systems used in offshore drilling are water-based fluids. Water-based
drilling fluids are dense colloidal slurries in a water phase of either fresh or saturated salt mixtures. Salt
water-based drilling fluids may be comprised of: seawater, sodium chloride (NaCl), potassium chloride
(KC1), magnesium chloride (MgCy, calcium chloride/bromide (CaCyCaBra), or zinc chloride/bromide
(ZnCyZnBr^. All freshwater muds contain bentonite (sodium montmorillonite clay) and caustic soda
(NaOH), while saltwater muds may contain attapulgite clay instead of bentonite. Clays are a basic
component of drilling fluids used to enhance the fluid viscosity. The most common required mud
properties and the additives used to enhance these properties are discussed below.
4.1 PROPERTIES OF DRILLING FLUIDS AND ADDITIVES
Several different formulations of drilling fluids and additives can be created to achieve the
required downhole conditions. The most common properties of the drilling fluid that the mud engineer
controls are:
Rheology
Density
Fluid Loss Control
Lubricity
Lost Circulation
Corrosion and Scale Control
Solvents
Low Solids/Polymer Fluids
Bactericides.
0
Each of these properties can be tailored to each well and drilling condition through the addition
of active solids, inactive solids, and chemicals to the base drilling fluid. The following paragraphs
provide a discussion of these properties and the additives that yield these properties.4
Rheology: During the drilling program, drilled clays may thicken the mud requiring that thinners
and dispersants be added to control rheological (fluid flow) properties. There are four major thinners
VII-5
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used for this purpose: lignosulfonate (where some contain chrome, ferrochrome, iron, calcium, sodium,
titanium), lignite (sometimes treated with chrome, sodium, or potassium hydroxide), phosphates (sodium
acid pyrophosphate and tetrasodium pyrophosphate), and plant tannis (quebracho is the most
predominant).
Density: Materials of high specific gravity are required to control downhole pressure. These
materials, however must be inert to the liquid phase of the drilling fluid. Many high density materials
can be used. Of these barite (naturally occurring barium sulfate ore) is the most widely used. The
amount of weighting agent required will depend upon the desired mud density, and the specific gravity
of the weighting agent used.
Fluid Loss Control: A properly designed drilling fluid system will deposit a filter cake on the
well bore wall during drilling to retard the passage of the liquid phase into the formation. Bentonite and
drilled clays are the prime builders of this filter cake. When the drilling formations are extremely
porous, additional fluid loss control additives are necessary. Some of the most common fluid loss control
additives are: starch (corn or potato), sodium carboxymethyl-cellulose, polyanionic cellulose polymer,
sodium polyacrylonitrile polymer, lignite, co-polymers of acrylamide and acrylic acid, xanthan gum,
sodium polyacrylates, and hydroxyethylcellulose.
Lubricity: Under normal drilling procedures, the drilling mud alone is sufficient for adequate
lubrication of the drill bit. When extreme loading to the drill bit is observed, a lubricant is added to the
drilling fluid to improve bit life and performance. The most commonly used lubricity agents in the
offshore drilling industry are mineral and diesel oils as well as the newly introduced synthetic lubricants.
However, lubrication can also be achieved through the use of products composed of one or more of the
following chemicals: acetophones, alcohol ester, aluminum stearate, asphalts, calcium oleate, coconut
diethanolamides, coconut oil alkanolamide, diesel oil, diphenyl oxide sulfonate, ethoxylates, ethoxylated
alcohol, fatty acids soaps, gilsonite, glycerol dioleate, glycerol monoleate, glass beads, graphite, lanolin,
low order paraffinic solvents, mineral oil, organic phosphate ester, rosin soap, sodium alkylsulfates,
sodium asphalt sulfonate, sodium phosphates, sorbitan ester sulfonate, stearates, sulfonated alcohol ether,
sulfonated tall oil, sulfonated vegetable oil, triethanolamine, vegetable oils, and wool greases.
Lost Circulation: Lost circulation is one of the most common problems encountered in rotary
drilling. Lost circulation refers to the loss of the whole drilling fluid to formations that are extremely
porous or cavernous. Lost circulation additives plug the holes and/or gaps that allow the mud to enter
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the formation. These additives are either fibrous, filamentous, or granular/flakes. The materials used
for lost circulation control are: ground nut shells, mica, ground cellophane, diatomaceous earth, baggasse
(cane fiber), vegetable fibers, cottonseed hulls, ground or shredded paper, animal hair or feathers.
Corrosion and Scale Control: Corrosion of downhole tubular pipe is a serious problem to the
drilling industry. Corrosion and scaling are minimized or eliminated through the addition of corrosion
inhibitors to the mud system. There are three major sources of corrosion encountered in drilling
operations. They are: oxygen, carbon dioxide, and hydrogen sulfide. Oxygen corrosion is due to oxygen
entering the mud system from different points and being dissolved. Carbon dioxide corrosion is due to
carbon dioxide entering the mud system from the formation and attacking the metal surface as gas or
carbonic acid. Hydrogen sulfide corrosion (hydrogen embrittlement) is due to the presence of hydrogen
sulfide hi formations. Corrosion is inhibited through the use of mud additive products composed of one
or more of the following chemicals: sodium sulfite, ammonium bisulfite, sodium dichromate, sodium
chromate, zinc chromate, tall oil, amines, high molecular weight morpholines, organically chelated zinc,
calcium sulfate, sodium hydroxide, zinc carbonate, copper carbonate, zinc oxide, iron oxide, phosphates.
Solvents: Some of the additives are liquid blends which require solvents for fluidity and freezing
point depression. The following solvents are used in certain specialty products: water, isopropanol, n-
butanol, glycerol, naphtha, isobutanol, 2-ethyIhexanol, amyl alcohol, ethylene glycol, ester alcohols,
diesel oil, other alcohols (C3 -
Low Solids/Polymer Drilling Fluids: There are many conditions, such as normal formation
pressures with no sloughing or heavy shales, where drilling with clear water fluids is desirable. These
fluids provide excellent rate of penetration. The fluids typically contain less than 5 percent solids and
are comprised of water, bentonite, and various polymers.
There are two types of polymers used, based on their action as either adsorbents or viscosifiers.
Adsorbents work on the clay solids while viscosifiers work on the liquid phase, both of which result in
increased viscosity. The most commonly used polymers are: polyvinyl acetate - maleic anhydride co-
polymer, co-polymer of acrylamide and acrylic acid, xanthan gum, polyanionic cellulose polymer, sodium
polyacrylates, hydroxypropyl guar, sodium polyacrylate and polyacrylamide, starchs (com, potato),
carboxymethylcellulose, hydroxyethylcellulose.
VH-7
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Bactericides: Bactericides are occasionally required in muds subject to bacterial degradation.
Under the current regulatory requirements, all bactericides used in drilling fluids are regulated by EPA
under the Federal Insecticide, Fungicide, Rodenticide Act (FIFRA).
4.2 COMPONENTS OF DRILLING FLUIDS
EPA conducted a survey of drilling fluids used hi wells drilled between 1981-1984 in the Gulf
of Mexico.5 Chemical inventories of base components and specialty additives used for 74 exploratory
and development wells were collected. Survey findings indicate that four basic components account for
about 90 percent by weight of all materials used in the mud systems for these wells. The four basic
components are: barite, clays, lignosulfonates, and lignites. Other mud systems' components are lime,
caustic soda, soda ash, and a multitude of specialty additives. A detailed description of these compounds
follows.
Barite: Barite, also known as baryte or heavy spar, is a heavy, soft, and chemically inert
mineral. Pure barite contains 58.8 percent barium (Ba) and 41.2 percent sulfate (SO4) by weight.
Commercial forms can run as low as 92 percent BaSO4 and contain such impurities as silica, iron oxide,
limestone, and dolomite, as well as trace metals.
The use of barite as a weighting material in drilling fluids accounted for 90 percent of the total
United States consumption in 1989. Offshore wells, which on the average are deeper and have higher
subsurface pressures than onshore wells, account for a disproportionately higher percentage of the total
consumption.
Barite is considered a ubiquitous material because both barium and sulfur are common minerals
in the earth's crust (16th and 14th in abundance, respectively), and because barium sulfate (BaSO4) is
virtually insoluble in seawater. Barite tends to form a fine precipitate and is found in a range of grain
and textures.
Barite deposits are classified into three categories: (1) vein and cavity filling deposits; (2) bedded
deposits; and (3) residual deposits. Residual deposits typically are mined in open pits 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 at the extraction site, usually by
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rigging or flotation. If deposits are pure enough beneficiatiori is not necessary. The purified barite is
shipped to processing plants for crushing and grinding.
Surveys were conducted to determine the concentration of trace metals in vein and bedded barite
deposits. Kramer, et. al., analyzed barite samples to determine trace metals concentrations. The data
reported in this study are summarized in Table VII-2. Vein deposits show a much wider range of trace
metals concentrations than do bedded sources. Some vein deposits contain trace metal at levels below
ocean sediment and crustal averages, while others contain mercury, cadmium, and zinc in quantities on
the order of 100 times greater.6 Barite is the primary source of toxic metals in drilling fluid discharges.
The principal metals of concern are mercury and cadmium.
Clays: Bentonite is the most widely used clay. Bentonite has a crystalline structure which causes
it to swell upon contact with water. This gelatirig property has two benefits: it suspends solid material,
and aids in the removal of drill cuttings from the borehole. The sealing properties of bentonite also
enable it to form an impermeable filter cake on the wellbore wall. However, highly concentrated brine
(formation water), will substantially reduce the swelling properties of bentonite. In these cases,
attapulgite or sepiolite clays are used as substitutes for bentonite.
Lignosulfonates: Lignosulfonates, by-products of pulp and paper processes, are considered; the
best all-purpose deflocculants for water-based drilling fluids. Deflocculants are generally used to maintain
the mud in a fluid state.
The most widely used form of lignosulfonates is ferrochrome lignosulfonate. This compound is
preferred over other forms of lignosulfonates because it retains its properties in fluids with high soluble
salt concentrations and over a wide alkaline pH range, it is resistant to common mud contaminants, and
it is temperature stable to approximately 177ฐC (350ฐF). Chromium can represent up to 3 percent by
weight of seawater ferrochrome lignosulfonate. The aqueous fraction of spent seawater ferrochrome
lignosulfonate drilling fluid contains about 1 ppm chromium. Most of this chromium is in the less toxic
trivalent form, and is bound to clay particles.7
Lignites: Lignites are used, like lignosulfonates, as deflocculants. Lignites are substantially less
soluble in seawater than lignosulfonates. Lignite products are mostly used as thinners in freshwater muds
and to reduce drilling fluid loss to formation, and control drilling fluid gelation at elevated temperatures.
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.Other Additives: Other compounds such as lime, caustic soda, soda ash, and specialty additives
are used as drilling fluids components as dictated by well drilling requirements. Table VII-3 lists several
common drilling fluid additives and their functions. Their quantities vary considerably from well to well.
Based on the survey data of the 74 wells completed between 1981-1984 in the Gulf of Mexico certain
trends were observed. Wells in federal OCS waters require on the average, more drilling fluids and
specialty additives than do wells in state waters. Also, exploratory wells require more drilling fluids and
specialty additives than do 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.5
4.3 DRILLING FLUID COMPOSITION
In 1983, EPA initiated a program to evaluate the characteristics of water-based drilling fluids for
the 1985 rulemaking. The program selected eight generic mud types to represent water-based drilling
fluids commonly used in the offshore drilling industry. See Section V.2.1 for more details on the
analytical program. Table VII-4 identifies the individual components and concentrations for each generic
mud type. The results of chemical and physical analyses are summarized in Table VH-5.
The eight generic drilling fluids were also analyzed for "free oil" by the static sheen method.
Sheen tests were also conducted on two generic muds (generic mud No. 2 and No.8) that contained
varying volumes of mineral oil. None of the generic muds caused a visible sheen on the test waters. The
additional drilling fluids submitted by industry containing varying concentrations of mineral and diesel
oil all showed positive static sheen test results.10 Washed cuttings from oil-based mud systems all
indicated positive static sheen test results. The results of the static sheen'tests for the drilling fluids and
drill cuttings analyzed by the EPA contract laboratory are presented in Table V-2 in Section V.2.4.
The generic drilling fluids were also analyzed for organic pollutants and metals. Organic priority
pollutants, analyzed by gas chromatography/mass spectrometry (GC/MS), were not detected in any of
the water-based generic drilling fluid formulations without lubricity additives. Priority organic pollutants
were detected in the muds spiked with mineral oil. Table VH-6 presents the organic pollutants detected
in the generic drilling fluids. The presence of metals in the generic muds were determined by atomic
absoqrtion spectrometry. A total of 10 of the 13 priority metals were detected in the generic
formulations. In particular, for all the generic muds, cadmium and mercury were both present at
concentrations below 1 mg/kg. Table VII-7 presents the metals concentrations in the generic muds.
vn-ii
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TABLE Vn-3
FUNCTIONS OF COMMON DRILLING FLUID CHEMICAL ADDITIVES8
Action
Alkalinity and pH
Control
Bactcricides
Calcium Removers
Corrosion Inhibitors
Defoamcrs
Emulsifiers
Filtrate Loss
Reducers
Flocculants
Foaming Agents
Lost Circulation
Additives
Lubricants
Shale Control
Inhibitors
Surface Active
Agents (Surfactants)
Thinners
Weighting Material
Petroleum
Hydrocarbons
- ,- Typical Additives
Caustic Soda; Sodium bicarbonate; Sodium carbonate;
Lime
Paraform aldehyde; Alkylamines; Caustic soda; Lime;
Starch
Caustic soda; Soda ash; Sodium bicarbonate;
Polyphosphates
Hydrated lime; Amine salts
Aluminum stearate; Sodium aryl sulfonate
Ethyl hexanol; Silicone compounds; Lignosulfonates;
Anionic and nonionic products
Bentonite; Cellulose polymers; Pregelated starch ,
Brine; Hydrated lime; Gypsum; Sodium tetraphosphate
Wood chips or fibers; Mica; Sawdust; Leather; Nut
shells; Cellophane; Shredded rubber; Fibrous mineral
wool; Perlite
Hydrocarbons; Mineral oil; Diesel oil; Graphite powder;
Soaps
Gypsum; Sodium silicate; Polymers; Lime; Salt
Emulsifiers; De-emulsifiers; Flocculants
Lignosulfonates; Lignites; Tannis; Polyphosphates
Barite; Calcite; Ferrophosphate ores; Siderite; Iron
oxides (hematite)
Diesel oil; Mineral oil
Function
1. Control alkalinity
2. Control bacterial growth
Reduce bacteria count
NOTE: Halogenated phenols are no longer
permitted for DCS use
Control calcium buildup in equipment
Reduce corrosion potential
Reduce foaming action in brackish water
and saturated salt muds
Create homogeneous mixture of two liquids
Prevent invasion of liquid phase into
formation
Cause suspended colloids to group into
"floes" and settle out
Foam in the presence of water and allow air
or gas drilling through formations
producing water
Used to plug pores in the well-bore wall to
stop fluid loss into formation
Reduce friction between the drill bit and the
formation
Reduce wall collapse caused by swelling or
hydrous disintegration of shales
1 . Reduce relationship between viscosity
and solids concentration
2. Vary the gel strength
3. Reduce the fluid plastic viscosity
Deflocculate associated clay particles
Increase drilling fluid density
Used for specialized purposes such as
freeing stuck pipe
vn-12
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TABLE VII-4
GENERIC DRILLING FLUIDS COMPOSITION9
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Generic Drilling Fluid Type
1. Potassium/Polymer
2. Seawater/Lignosulfonate
3. Lime
4. Nondispersed
5. Spud (slugged intermittently with seawater)
6. Seawater/Freshwater Gel
7. Lightly Treated Lignosulfonate
Freshwater/Seawater
8. Lignosulfonate Freshwater
Base Components
KC1
Drispac (Super-Lo)
X-C Polymer
Barite
Starch
Seawater
Attapulgite
Chrome Lignosulfonate
Lignite
Polyanionic Cellulose
Caustic
Barite (17-18 ppg mud)
Seawater
Benitonite
Lime
Barite
Chrome Lignosulfonate
Caustic
Lignite
Distilled Water
Bentonite
Acrylic Polymer (for Suspension)
Arcylic Polymer (for fluid loss control)
Barite
Deionized
Bentonite
Lime
Barite
Seawater/Freshwater
Caustic
Bentonite
Polyaninic Cellulose Sodium
Carboxymethyl
Cellulose
Barite
Sodium Hydroxide
Seawater/Freshwater, 1:1
Bentonite
Chrome Lignosulfonate
Lignite
Soda Ash
Carboxymethyl Cellulose
Barite
Bentonite
Chrome Lignosulfonate
Lignite
Carboxymethyl Cellulose
Sodium Bicarbonate
Barite
Deionized Water
Concentration
50.0 g
0.5 g
1.0 g
283.2 g
2.0 g
257.6 ml
30.0 ppbbl
15.0 ppbbl
10.0 ppbbl
0.25 ppbbl
To pH 10.5-11.0
As Needed
20.06 g
5.01 g
281.81 g
15.04 g
1.00 g
, 8.02 g
257.04ml
13.0 ppbbl
0.5 ppbbl
0.25 ppbbl
190.7 ppbbl
299.6 ppbbl
12.5 ppbbl
0.5 ppbbl
50.0 ppbbl
1.0 bbl
To pH 10.0
20.0 ppbbl
0.50 ppbbl
0.25 ppbbl
20.0 ppbbl
TopH9.5
As Needed
20.0 ppbbl
5.0 ppbbl
3.0 ppbbl
1.0 ppbbl
0.5 ppbbl
178.5 ppbbl
15.0 g
15.0 g
10.0 g
0.25 g
1.0 g
487.0 g
187.0 ml
g = Grams; ml = Milliliters; ppbbl = Pounds per barrel; ppg = Pounds per gallon
VII-13
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TABLE VII-7
METAL CONCENTRATIONS IN GENERIC DRILLING FLUIDS10
Generic
Mud
NO.
1
2
3
4
5
6
7
8
2-01
2-05
2-10
8-01
8-05
8-10
Generic
Mud
No.
1
2
3
4
5
6
7
8
2-01
2-05
2-10
8-01
8-05
8-10
Zn
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
Nl
<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
-
Be
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
<1.0
Pfe
7.74
1.82(b)
41.2
52.5
3.51(b)
1.53(b)
1.42(b)
17.80
6.83
6.20
1.17(b)
24.50
13.00
9.48
Concentrations (sng/kg Dry Weight Basis)
. Al
190
1,150
743
876
347
536
541
1,150
1,200
1,400
955
988
862
857
Hg
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
Ba
246.0
74.0
41.2
286.0
293.0
65.4
408.0
54.6
71.3
144.1
23.8
1,240.0
27.0
39.5
Ag(b)
0.089
0.126
0.314
0.228
< 0.060
< 0.060
< 0.060
0.244
0.110
0.124
0.110
1.390
1.110
1.140
Fe
1,890
2,860
2,170
1,120
833
392
660
5,110
2,520
3,350
1 2,800
4,980
3,940
5,020
As(b)
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
,Cd
0.220
0.472(b)
0.378(b)
0.446(b)
0.074(b)
0.042(b)
0.142(b)
0.36
0.395(b)
0.717(b)
0.470(b)
0.18
0.28
0.36
Se{b)
<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
Cr
<3.0
764
908
<3.0
<3.0
<3.0
299
770
740
720
640
610
541
560
Sb(b)
4.000
0.260
1.060
0.473
<0.060
<0.060
< 0.060
0.794
0.239
0.522
0.160
2.650
2.700
2.020
Cut
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
Ti{b)
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) Average of two samples
(b) Samples run by graphite furnace
(c) Single analysis
VII-16
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The acute toxicity of the generic drilling fluids range considerably.9 No median effects (50%
mortality) were observed for three of the eight mud types. Potassium polymer mud was found to be the
most toxic. The suspended paniculate phase showed a 96-hour LC50 of 3 percent by volume, as
measured by the bioassay test method proposed in Appendix 3 of the regulation to the 1985 proposal.
A summary of bioassay results are presented in Table VII-8.
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TABLE VII-8
RESULTS OF ACUTE TOXICITY TESTS WITH
GENERIC DRILLING FLUIDS AND MYSIDS (MYSIDOPSIS BAfflA)9
t&t Location
EPA/ORD
Gulf Breeze
EPA/ORD,
Narragansett
Generic
Mud No.
1
2
3
4
5
6
7
8
1
5
Definitive Test (a)
^HrLC50&9S%CL)
2.7% SPP (2.5 - 2.9) (c)
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 -3 1.5)
2.8% SPP (2.5 - 3.0)
No mortality in 100% SPP
Positive Control (a)
0<rLC&ft*$*CMi
5.8 ppm (4.3 - 7.6) (d)
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- 11.0)
3.3 ppm (2.6 - 3.8)
Definitive Test (b)
(96-Hr LCSft & 9S& CL>
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 (27.2 - 32.3)
LC50 - Lethal concentration to 50% of test organisms
SPP - Suspended participate phase
CL - Confidence limit
(a) Calculations by moving average; no correction for control mortality unless started.
(b) Calculation by SAS probit; correction for all control mortality.
(c) The suspended paniculate phase was prepared by mixing 1 part drilling fluid with 9
These values should be multiplied by 0.1 in order to relate the 1:9 dilution tested to
whole drilling fluid.
(d) Corrected for 13% control mortality.
parts seawater.
the SPP of the
Drilling fluid toxicity has been shown to increase with addition of mineral and diesel oil. Drilling
fluids spiked with mineral oil were less toxic than those spiked with diesel oil. These findings are
consistent with results of other research activities conducted at EPA's Environmental Research Laboratory
in Gulf Breeze, Florida.11 This study also showed that mud toxicity is more closely related to diesel
content than to mud type.
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The Gulf of Mexico Offshore Operators Committee (OOC) conducted a study in 1984 to examine
the composition of mineral and diesel oil.12 Three mineral oils and six diesel oils were examined using
both the EPA GC method and a series of GC/MS methods measuring such parameters as individual
aromatic compounds, alkylated phenols, organic sulfur compounds and several others. Data gathered
from this study indicate that there are similar constituents in both diesel and mineral oils but at
significantly higher concentrations in the diesel. The analysis revealed quantitative differences in the total
aromatic, total sulfur and organic sulfur contents, as well as in the concentrations of individual
polyaromatic hydrocarbons (benzene, naphthalene, biphenyl, fluorene and phenanthrene alyl homologue
series) and sulfur- and nitrogen- polycyclic aromatic compounds (PAC) (debenxothiophene and carbazole
alkyl homologue series, respectively). Thus, the differences in amounts of these compounds in mineral
and diesel oils accounts for the lower toxicity of mineral oil. The results of this study are presented in
Table VH-9.
TABLE VII-9
ORGANIC CONSTITUENTS OF DIESEL AND MINERAL OILS12
Cone, in mg/ml, unless noted otherwise
Organic Constituents
Benzene
Ethylbenzene
Naphthalene
Fluorene
Phenanthrene
Phenol (ug/g)
Alkylated benzenes (a)
Alkylated naphthalens (b)
Alkylated fluorenes (b)
Alkylated phenanthrenes (b)
Alkylated phenols (ug/g) (c)
Total biphenyls (b)
Total dibenzothiophenes (ug/g)
Aromatic content (%)
Gulf of
Mexico
Diesel
ND
ND
1.43
0.78
1.85
6.0
8.05
75.68
9.11
11.51
52.9
14.96
760
23.8
Calif.
Diesel
0.02
0.47
0.66
0.18
0.36
ND
10.56
18.02
1.60
1.41
106.3
4.03
1200
15.9
Alaska
Diesel
0.02
0.26
0.48
0.68
1.61
1.2
1.08
25.18
5.42
4.27
6.60
6.51
900
11.7
EPA/API
Ref.
Fuel 0U
0.08
2.01
0.86
0.45
1.06
ND
34.33
38.73
7.26
10.18
12.8
13.46
2100
35.6
Mineral
Oil A
ND
ND
0.05
ND
ND
ND
30.0
0.28
ND
ND
ND
0.23
ND
10.7
Mineral!
DUB
ND
ND
ND
0.15
0.20
ND
ND
0.69
1.74
0.14
ND
5.57
370
2.1
Mlma-al
oac
ND
ND
ND
0.01
0.04
ND
ND
ND
ND
ND
ND
0.02
ND
3.2
Note: The study characterized sic diesel oils and three, mineral oils. For the purpose of the general comparison and
summary presented above, the Alaska, California, and Gulf of Mexico diesels are assumed to be representative of those
used in offshore drilling operations.
ND =2 Not Detectable
(a) Includes C, through C6 alkyl homologues
(b) Includes C, through C5 alkyl homologues
(c) Includes cresol and Cj through C4 alkyl homologues
VH-18
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5.0 CONTROL AND TREATMENT TECHNOLOGY
5.1 BPT TECHNOLOGY
BPT effluent limitations for offshore drilling fluids prohibit the discharge of free oil. Oil-based
muds cannot be discharged to surface waters because they have been shown to cause a visible sheen upon
the receiving waters. Compliance with these limitations can be achieved either by product substitution
(substitute a water-based mud for an oil-based mud to comply with no discharge of oil-based muds;
substitute mineral oil for diesel oil to comply with no free oil limitation for water-based muds), recycle
and/or reuse of the drilling fluid, or by onshore disposal at an approved facility.
5.2 ADDITIONAL WASTE MANAGEMENT PRACTICES AND TECHNOLOGIES CONSIDERED
Waste management practices to control releases of priority pollutants from discharges of drilling
fluids include:
Product substitution - acute toxicity limitations
Product substitution - clean barite
Product substitution - mineral oil
Onshore treatment and/or disposal
Waste minimization - enhanced solids control
Conservation and recycle/reuse.
A detailed discussion of these practices is presented in the following sections. In addition, several
technologies are also discussed which were evaluated during the study of controlling drill waste
discharges, including:
Thermal Distillation/oxidation
Solvent extraction
Grinding/reinjection
Incineration.
5.2.1 Product Substitution - Acute Toxicity Limitations
EPA's acute toxicity analysis of the eight generic muds indicated that low toxicities can be
achieved through the use of water-based drilling fluids and low toxicity specialty additives. Thus, acute
VII-19
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toxicity limitations would encourage operators to substitute low toxicity additives for high toxicity
additives.
The eight generic muds were formulated to represent the wide range of drilling conditions
encountered by the offshore drilling industry. The results of the toxicity testing for the eight generic
muds were presented in Table VII-8. The toxicity analysis indicates that they all exhibit low toxicity
except for the potassium chloride (KCL) polymer mud, generic mud Number 1. The suspended
paniculate phase 96-hour LC50 of this mud was 3 percent by volume, with a 95 percent confidence
interval ranging from 3.0 percent to 3.5 percent. The potassium chloride polymer mud was considered
to be a specialty mud for drilling projects hi the Gulf of Mexico.
EPA considers that mud formulations similar to the eight generic muds can be substituted, along
with low toxicity additives, for higher toxicity water-based muds. The eight generic muds demonstrate
that low toxicity components and additives can be formulated to generate a functional low toxicity drilling
fluid. By selecting the drilling fluid with the least common formulation and the highest toxicity level as
the basis for the drilling fluid toxicity limitation (generic mud No. 1), EPA is confident that the toxicity
limitation is achievable and will significantly reduce the discharges of toxic muds without significantly
affecting offshore drilling industry.
5.2.2 Product Substitution - Clean Barite
Barite is a major component of drilling fluids which can represent as much as 70 percent of the
weight of a high-density drilling fluid. Barite has been shown to contain varying concentrations of metals
of toxic concern, particularly cadmium and mercury. Barium sulfate, the natural source of barite, has
also been shown to contain varying concentrations of metals depending on the characteristics of the
deposit from where the barite was mined. EPA's statistical analysis of the API/USEPA Metals Database
indicate that there is some correlation between cadmium and mercury and other trace metals in the
barium.13 Thus, regulating the concentration of cadmium and mercury hi barite would indirectly regulate
all other metals present in barite.
EPA used six datasets to evaluate the achievability of compliance with a metals limitation hi
Barite.13 These datasets come from the Diesel Pill Monitoring Program (DPMP), the Offshore Operators
Committee's (OOC) Fifteen Rig Study (15RS), monitoring data from EPA's Region IX, and monitoring
data from Region X, as well as two other studies performed in 1986 and 1988.
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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 iin 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. ,
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The 15RS contains 14 cadmium and mercury measurements from a joint effort of API and OOC.
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 pperators who were in the process of drilling.
The Region IX data, measurements from four samples, are from discharge monitoring rejports
submitted by offshore oil and gas operators under the requirements of their permits. The Region EX
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.
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.
5.2.2. 1 Compliance Rates Achievability
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.14
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All of the data sets show passing rates to some degree for all limitation options; Table VII-10 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 VH-11 shows the percent of samples passing
the three sets of standards for cadmium and mercury in the drilling fluids. Again, 100 percent
compliance with all standards was exhibited by data from Region IX. Region IX shows a 100 percent
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 of 3/1 mg/kg cadmium and mercury, respectively, in barite composition, shows a 67 percent
compliance rate for 1/1 mg/kg cadmium and mercury in drilling fluids. Data from Gulf facilities show
a lower percentage of compliance; however, there are currently no metals limitations in their general
permit. For comparative purposes, EPA evaluated 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 hi the barite composition). EPA is also taking into account comments submitted
by industry that 3/1 mg/kg (Cd/Hg) is technologically available and economically achievable.
TABLE VH-10
PERCENT OF SAMPLES PASSING BOTH CADMIUM AND MERCURY
PROPOSED LIMITATIONS ON BARITE14
Standard
Standard 1
5 mg/kg
Cadmium '
3 mg/kg
Mercury
Standard 2
3 mg/kg
Cadmium
1 mg/kg
Mercury
Study
OOC86
OOC88
REG10
REG9
15RS
15RSEPA
OOC86
OOC88
REG10
REG9
15RS
15RSEPA
Samples
15
48
52
11
14
14
15
48
52
11
14
14
Number of Samples Passing
Both Cd and Hg
14
44
52
11
12
12
11
32
52
10
7
6
Fercetit Passing
CdandHg
93
92
100
100
86
86
73
67
100
91
50
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TABLE VII-11
PERCENT OF SAMPLES PASSING BOTH CADMIUM AND MERCURY
PROPOSED LIMITATIONS ON DRILLING FLUIDS14
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Standard
Standard 1
1 mg/kg
Cadmium
1 mg/kg
Mercury
Standard 2
2.5 mg/kg
Cadmium
1.5 mg/kg
Mercury
Standard 3
1.5 mg/kg
Cadmium
0.5 mg/kg
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
37
31
112
4
14
13
Number of Samples Passing
Both Cd and Hg
6
4
78
4
8
3
19
27
102
4
12
12
8
9
82
4
7
4
Percent Passing
CdandHg
16
13
70
100
57
23
50
87
88
100
86
92
21
29
73
100
50
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5.2.2.2 Clean Barite Availability
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.15 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.16 Results of
this survey, extrapolated to 1985 production, are shown in Table VII-12. 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 percent of 1985 production might have met either cadmium
and mercury limitation. For the most adversely affected producer, Peru, none of the samples met the
VII-23
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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 percent met
the 1 mg/kg each limitation for these metals.
TABLE VH-12
AMOUNT OF BARITE MEETING CADMIUM AND MERCURY
LIMITATIONS -1985 DATA15
Country
Chile
China
India
Mexico
Morocco
Peru
Thailand
U.S.
Total of Listed
Countries
U.S. Barite Use in
Well Drilling
Total
Onshore
Offshore
\ Quantity Produced
or Imported to U.S.
(000,sbort tows)
24
1,100
670
540
468
180
190
739
5,911
2,042
1,096
946
Meeting flg and Cd Limits;
of 1 and 1 rng/kg
%-
57
56
81
36
34
0
33
82
Quantity
{000 shi tns.)
14
616
543
194
159
0
63
606
2,195
Meeting Hg and Cd Limits
of 3 and ง mg/kg
*
93
81
100
79
78
33
100
100
Quantity
{OOOsht, tosf.)
22
891
670
427
365
59
190
739
3,363
., ป ' S < f
V >" ffff sfS s
For the countries surveyed, 2,195 thousand short tons or 3,363 short tons of "clean" barite would
have been available from 1985 production depending on the limits chosen for cadmium and mercury.
Total U.S. barite use in 1985 for well drilling was 2,042 thousand tons. In other words, even though
only 59 percent of world production was extrapolated, there would have been sufficient "clean" barite
to meet all U.S. drilling needs, not just offshore.
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Table VlI-13 compares the projected barite needs to the "clean" barite available based on 1985
production levels, assuming three different oil price scenarios. Under the 1 mg/kg each limitation, barite
needs exceed 1985 domestic production but form only 28 to 41 percent of the production of the tested
countries. Additional supplies are likely to be available from the untested countries as well.
TABLE VII-13
COMPARISON OF PROJECTED BARITE NEEDS AND SUPPLIES15
IVice
Assumption
($/bbl)
15
21
32
Average
Annual Barite
Requirements
613
742
894
Available Barite (1985 Production) (000 shorj tons)
Hg and Cd Limits of
1 and 1 mg/kg
United States
Quantity
606
606
606
%
101
122
148
Tested
Countries
Quantity
2,195
2,195
2,195
%
28
34
41
Hg and Cd Limits of
3 and $ mg/kg
United States
Quantity
739
739
739
%
83
100
121
Tested
Countries
Quantity
3,365
3,365
3,365
%
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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 percent of the 1985 production from the tested countries.
In response to comments that noncompliance would be caused by contributions from the
formation, EPA has analyzed data from the American Petroleum Institute's Fifteen Rig Study.13 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
tune the first two samples were taken. Splits or duplicates of these samples were also analyzed by EPA.
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 hi 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 EPA
indicates that 13 out of 13 rigs, for which results were reported, had higher cadmium concentrations in
their drilling fluid than in their barite.
VII-25
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Based on the results of this analysis, EPA developed a profile of metals concentrations in drilling
fluids where both "clean" and "dirty" barite were used. This information was compiled from the
statistical analysis of the API/EPA Metals Database. Table XI-4 in Section XI presents these profiles as
they were used to calculate regulatory options for metal pollutants reductions.
5.2.3 Product Substitution - Mineral Oil
In addition to using low toxicity drilling fluids, low toxicity lubrication additives can reduce the
overall toxicity of the drilling fluid. For many years, diesel oil was the preferred additive for lubrication
purposes and for spotting jobs. EPA has evaluated other lubricants that have similar properties to diesel
but are less toxic. One of these products which has become a common substitute for diesel oil hi recent
years is mineral oil. Mineral oil is an adequate substitute for diesel as a torque-reducing agent and a
spotting fluid, as demonstrated by the API Drilling Fluids Survey and the OOC Spotting Fluids Survey
(see Section V.2).
An'OOC sponsored analysis of organic chemical characterization of diesel and mineral oils used
as drilling fluid additives indicated that there are similar constituents in both diesel and mineral oils but
at significantly higher concentrations hi the diesel.17 The analysis revealed quantitative differences in the
total aromatic, total sulfur and organic sulfur contents, as well as in the concentrations of individual
polyaromatic hydrocarbons (benzene, naphthalene, biphenyl, fluorene and phenanthrene alyl homologue
series) and sulfur- and nitrogen- polycyclic aromatic compounds (PAC) (debenxothiophene and carbazole
alkyi homologue series, respectively). Thus, the differences in amounts of these compounds in mineral
and diesel oils accounts for the lower toxicity of mineral oil.
In 1984, industry representatives acknowledged that mineral oil is an adequate substitute for diesel
as a torque-reducing lubricity agent.17 Several industry studies investigated the effectiveness of using
diesel oil versus mineral oil hi freeing stuck pipe. The data gathered from these studies indicated that:
mineral oil was commonly used by operations in the Gulf of Mexico, mineral oil is an available
alternative to the use of diesel oil, and success rates comparable to those with diesel oil can be achieved
with mineral oil.
There are also several available synthetic hydrocarbon lubricants such as polyolefins and low
toxicity vegetable oils that are effective in reducing torque and freeing stuck pipe.
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5.2.4 Onshore Treatment/Disposal
Drilling fluids that do not meet the effluent limitations guidelines and standards of this rule can
be hauled to shore for treatment and/or disposal. EPA determined that transporting drilling wastes to
shore is currently practiced and technologically and economically feasible. EPA estimates that
approximately 12 percent of all drilling fluids are brought to shore for treatment/disposal under the
current regional BPJ NPDES General Permits. To evaluate the impact of increased onshore disposal
volumes required under this rule, the EPA studied the availability and capacity of land disposal facilities.
This section will describe the methods of onshore disposal of drilling wastes. Section XVHI.2.2 presents
information on the available capacity of land facilities for disposal of offshore drilling waste.18
In 1987 sixteen disposal facilities from California, Louisiana, and Texas were surveyed to
determine the disposal methods, costs, and available space. A variety of treatment/disposal systems were
employed by the companies ranging from disposal of contaminated drilling fluids with and without
treatment to treatment of the fluids and transferral of the treated material to another facility for final
disposal. The typical methods of disposal were: landfills, land treatment, deep well injection, and mud
reclamation. The number of companies utilizing each of the various methods is summarized as follows:
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Companies Disposal Method
7 Landfill
2 Land treatment (landfarm)
1 Mud reclamation
1 Deep well injection (has applied for landfill
permit)
5 Waste treatment
- Gravity settlers, electroflotation
- Evaporation using hot oil system
- Drying/incineration
- Thermal oxidation
- Incineration.
The typical waste handling method for land disposal of drilling muds and cuttings noted in the
survey was stabilization (i.e., solidification and fixation) of the mud with kiln dust or fly ash followed
by landfilling. Solidification techniques consist of adding chemicals to the mud which react to form a
solid material which can be disposed. The equipment consists of a specially designed blender to mix the
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drilling fluids and chemicals and to pump the slurry inco the proposed areas for solidification. Six of the
facilities surveyed used this method of disposal.
One facility disposes of the waste in lined impoundments. Upon arrival of the spent drilling
waste at this facility, it is classified either as solid or liquid, and disposed accordingly. Solid and liquid
wastes are placed in different lined impoundments.
One facility handles only bulk or drummed solids. The waste must have under 5 percent
hydrocarbons present. All solids are placed in lined pits.
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 into a saltwater disposal well.
One company included La the survey is a supplier of muds to the industry that reclaims 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 used
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 content 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:
supply boats or barges for oil, mud slurries, and liquids; and dump trucks for land transport of drill
cuttings or wastes which are 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. In addition, the total volume of material to be
disposed and the total acreage necessary to support disposal of this material were estimated. The total
required acreage was compared with an assessment of actual land availability for this purpose.
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The companies were also asked to supply information on the costs of disposal. Reported costs
for landfilling after solidification of the drilling muds ranged 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.
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Costs for waste treatment were quoted by two of the five companies providing processes for
treating waste drilling 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 percent 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.
5.2.5 Waste Minimization - Enhanced Solids Control
Solids control equipment is used to remove drill cuttings and other fines and minimize the build-
up of drilled solids in the drilling mud system. Reported benefits of enhanced solids control efficiencies
include: " '
Reduced drilling torque and drag
Reduced swab and surge pressures
Reduced tendency for differentially stuck pipe
Fewer stuck logging tools
Better cement jobs
Higher penetration rates with reduced bit and stabilizer balling
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Better ability to run casing to bottom
Longer bit runs
More hole stability
Reduced equipment wear and tear
Reduced land disposal areas and disposal costs
Reduced drilling fluids costs.19
Solids control equipment is typically provided and maintained by the drilling contractors.20
Typically, a turnkey contractor will provide the equipment specified by: (1) the standard drilling contract
- shale shaker, desander, desilter, or (2) additional requirements placed by the operator - high
performance shale shaker, mud cleaner, centrifuge, etc.
The separation efficiency of the solids.control equipment is defined as the percentage of low
specific gravity solids removed from the active mud system in each drilling cycle. The separation
efficiency is dependent on several factors such as: mud rheology, mud density, formation characteristics,
low gravity solids concentration in the mud (typically maintained at no more than 5-7%), fluid flow rate,
equipment design capacity, equipment piping and plumbing configuration, and equipment operator
experience.3
ป
Solids control equipment is used by the industry to remove drill cuttings and minimize the buildup
of drilled solids in the drilling fluid system. In addition to enhancing drilling fluid properties;, by
minimizing solids buildup in the mud system the operator can reduce the extent to which dilution of the
drilling fluid is required. All drilling operations utilize solids control equipment to some degree and the
efficiency of the system, hi determining the extent to which dilution is required, affects the volume of
drilling wastes generated. A relatively low efficiency (40 percent) solids control system requires a
substantial level of dilution in order to maintain proper mud system properties. Intermediate level of
efficiency (about 60 percent), in providing greater solids removal from the mud system, substantially
reduces the level of dilution required for the mud system and reduces the volume of drilling wastes
generated. The intermediate level system will result in an increased volume of drill cuttings and a
decreased volume of drilling fluids. (While the total drilling waste volume is reduced because of the
reduced dilution, a portion of drilled solids discharged along with drilling fluids in low efficiency solids
control systems will be removed by the higher efficiency solids control and included with the drill cuttings
wastes.)
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Finally, closed-loop solids control systems can provide approximately 80 percent solids removal
efficiency, further reducing the overall drilling waste volume (the drill cuttings volume would increase,
but the drilling fluid volume decreases by a greater amount.) While the closed-loop system provides
volume reductions over the intermediate-level system, the volumetric reductions in waste generation are
not linearly proportional to the solids control efficiency. As a result, operators gain significantly greater
reductions in drilling waste volumes in going from low efficiency to intermediate level solids control
equipment than achieved in going from intermediate-level equipment to closed loop systems.
In developing the final rule, EPA considered solids control equipment practices used in the
offshore oil and gas industry. In evaluating the potential for enhanced solids control systems to reduce
drilling waste volumes (and thus reduce non-water quality environmental impacts), EPA reviewed industry
literature and solids control equipment currently used in offshore drilling situations and data on solid
removal efficiencies. Based on the limited data available, EPA has determined that the offshore oil and
gas industry, while not using the highest efficiency solids control systems available, is in general using
a fairly high level of solids control in drilling operation.
While most platforms and drilling rigs may have a basic level (relatively low efficiency) of solids
control equipment permanently installed, it is common industry practice for lease owners/operators, in
contracting with the service firms providing drilling services, to require some level of enhanced solids
control equipment to be used. EPA used industry data on drilling waste discharges, (for which solids
information was unavailable) in conjunction with theoretical estimate of drilling waste volumes (calculated
from the theoretical hole volume and use of solid control equipment with differing efficiencies), to
determine that waste volumes generated in the offshore subcategory are demonstrative of a fairly high
solids control efficiency.
A factor to be considered in offshore operations is whether available space exists on the platform
or mobile drilling rig to support installation of higher efficiency solids control equipment. In onshore
and coastal areas, drilling operations typically are not severely limited in terms of equipment space. (In
coastal regions, additional equipment can often be added on the drilling barge or an additional barge
brought to the drilling site.) Offshore, however, operators must balance the benefits of adding additional
solids control equipment with the need to reserve space on the platform or drilling rig for storage of drill
cuttings boxes. If the available space for storage of drill cuttings boxes becomes too limiting, additional
boat trips to remove the drill cuttings are required if interruptions to the drilling operation are to be
prevented. Also, installing higher-efficiency solids control equipment produces a greater drill cuttings
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H
volume, further limiting drilling operations, (While the drilling fluid volume is decreased, a
corresponding space availability does not result since the muds are stored in tanks which have a smaller
"footprint, " or surface area requirement. Operators are limited in the extent to which cuttings boxes may
be stacked.) Operators may retrofit additional platform space on platforms or mobile drilling rigs; B
however, in some cases such modifications may not be feasible and in any case would be made based _
upon economic consideration of modification costs and onshore waste disposal costs. B
In evaluating the impact of enhanced solids control equipment drilling waste volumes requiring B
onshore disposal, EPA used its estimates of current industry practice, platform addition costs, and
onshore disposal costs to assess the potential for operators to further enhance their solids control systems. |
EPA was limited in this analysis by the lack of facility-specific data regarding the installed solids control
equipment. Because the industry is already using a fairly high level of solids control (limiting the extent ฃ
to which benefits could be realized through further efficiency increases), facility-specific data is lacking,
and because the selection of the type of solids control system used at a particular drilling location depends |o
on site-specific drilling conditions and economic variables, EPA was unable to determine the extent to
which the industry would implement higher-efficiency solids control systems. To the extent that higher- B
efficiency solids control equipment may be utilized, some reduction in the total drilling waste volumes
generated could be realized. Considering the fairly high level of efficiency already implemented offshore, B*
such volume reductions would not likely be significant. Thus, EPA believes non-water quality
environmental impacts estimated for drilling fluids and drill cuttings effluent limitations and NSPS would B
not change significantly with implementation of higher-efficiency solids control equipment.
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5.2.6 Conservation and Reuse/Recycling
Depending on the type and cost of the drilling fluid selected, recycle and reuse of spent drilling B
fluids may be an attractive alternative to reducing pollutants discharged from offshore drilling operations. *
This is particularly true of fluids that have a hydrocarbon (diesel or mineral) liquid base. Economically B
attractive reuse practices for spent oil-based and synthetic-based drilling fluids are:
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Mud company buys back the used drilling fluid which is hauled to shore, processed, and
reused. B
The spent drilling fluid is treated with additional solids-suspending agents and used as a
packer fluid. m
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5.2.7 Thermal Distillation/Oxidation
In 1988, EPA investigated thermal distillation and oxidation processes for their potential in
reducing the oil content of drilling wastes. Oil-based drilling fluids can typically contain 30 percent or
more oil by volume. Because of the high oil content (and low water content) of oil-based fluids,
significant quantities of oil can be recovered by these technologies. Four different thermal distillation
and oxidation processes were evaluated for the removal of oil from drilling wastes (53 FR 41375, October
21,1988).
I
One type of system (designated T-l) consists of an electrically heated chamber in which, the
drilling wastes are exposed to controlled heat sufficient to volatilize the residual oil and water in the
wastes. The electrical energy required by the process is provided by onsite generators. The processed
wastes in the form of a granular material are cooled and slurried with seawater before being discharged.
Water and hydrocarbon vapors are condensed and separated in an oil/water separator. The recovered
hydrocarbons can potentially be recycled and reused in active mud systems. Exhaust gases from the
heating chamber and from the condenser would also have to be treated to achieve appropriate air emission
standards. The results of sampling performed by the vendor and by EPA indicate that this technology
is capable of reducing oil content levels to 1 percent or less by weight in processed cuttings associated
with oil-based muds.
Another variation of the thermal distillation process (designated T-2) was developed to reduce
hydrocarbons in drilling fluids and drill cuttings. In this process, the drilling wastes are fed into the
drying section of the process where hydrocarbons and water are driven off from the wastes. The water
and hydrocarbon vapors are passed through condensers and the resultant liquid is processed to separate
the oil from the water. The oil is placed in storage for further purification and the water is farther
processed for additional oil/water separation. A prototype unit of this system was used to process drill
cuttings. An oil content of less than 0.5 percent by weight was reportedly achieved in a test of this unit.
However, a full-scale unit was not tested under actual field conditions.
A third variation of the thermal distillation process (designated T-3) uses indirect heat to vaporize
water and hydrocarbons adhering to drilling wastes. Drilling wastes are first fed to a blender which
maintains a homogeneous slurry feed to the unit process. A closed heat transfer system provides the heat
required to vaporize the water and the hydrocarbons from the drilling waste. Heat to the processing unit
is supplied by the exhaust gases from the rig electricity generator. The processed wastes are dry and
VII-33
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granular in nature. Water and hydrocarbons vapors are condensed for recovery. The results of the pilot
scale skid-mounted mobile unit reportedly produced cuttings with an oil content of 6 percent or less by
weight. This process was not tested on a full scale basis.
A thermal oxidation process (designated T-4) consists of a direct fired, countercurrent rotary kiln
where the wastes are thermally oxidized at temperatures in the range of 1600 F to 2500 F. The kilns can
be over 200 feet in length. The dried solids produced in this process are reportedly suitable for use as
aggregates or fill materials. The hydrocarbons driven from the wastes are partially oxidized in the kiln,
while virtually complete combustion is achieved in an oxidation chamber and afterburner. In 1988, at
least two of these facilities were known to be operating on the Gulf of Mexico. However, due to the
scale of the equipment, this process can not be implemented offshore or moved from site-to-site.
However, drilling wastes could be transported to such land-based facilities for processing.
Although these technologies appeared to be capable of reducing the oil content in oil-based
drilling wastes, EPA rejected them from further consideration because of difficulties associated with the
placement of such equipment at offshore drilling sites, operation of die equipment, intermediate handling
of raw wastes to be processed, and handling of processed wastes and by-products streams. Finally,
(1) full scale thermal distillation/oxidation treatment has not been successfully demonstrated on offshore
platforms; (2) it requires excessive input of thermal energy when processing water-based drilling wastes;
and (3) it does not reduce pollutants below the capability of BPT technology.
5.2.8 Solvent Extraction
In 1984, EPA evaluated a solvent extraction technology for reducing the oil content in drilling
wastes.21 The high oil content (and low water content) of oil-based fluids have resulted in highly efficient
removal and recovery of the oil by solvent extraction.
In this process, the drilling wastes are fed to an extraction column and contacted with solvent to
extract the oil. The oil-rich solvent flows from the extractor column to an evaporator, a separation
column and an oil/solvent separator. The oil phase flows to the fluidizing oil holding tank and the solvent
is recycled back to the process. Oil contents as low as 0.3 percent by weight in the processed wastes
were reportedly achieved by this process. Two types of solvents have been used in the solvent extraction
processes investigated by the Agency: chlorofluorocarbons and carbon dioxide. Although the solvents
are used in a closed-loop type process, there exists the potential of solvent losses to the atmosphere.
VH-34
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Although solvent extraction appeared to be capable for the reduction of oil content in drilling
wastes, EPA rejected it from further considerations because of difficulties associated with the placement
of such equipment at offshore drilling sites, operation of the equipment, intermediate handling of raw
wastes to be processed, and handling of processed wastes and by-products streams. In addition the
Agency is particularly concerned about the potential losses of chlorofluorocarbons to the atmosphere
Finally, this technology has not been successfully demonstrated on offshore platforms, and it does not
. Deduce pollutants below the capability of BPT technology.
5.2.9 Grinding/Reinjection
In the March 13, 1991 proposal, EPA solicited comments on rejection as a basis of zero
discharge for drill waste, muds and cuttings. EPA received comments from the Alaskan Oil and Gas
Association,(AOGA) on a prototype cuttings grinder and washing system being tested onshore at Prudhoe
Bay, Alaska ป In 1992, EPA obtained information on a drill waste injection system from a company
operating a pilot injection system on a platform in the Gulf of Mexico.23
Drill waste injection systems consist of a slurrificatkm system and an injection system The
cuttmgs are processed in a vibrating ball mill into a slurry that can be combined with the spent fluids and
excess liquids from the drilling process. The slurry particle size for the system operating in Prudhoe Bay
is 74 microns. The slurry is then pumped into the formation through a well annulus or into a dedicated
disposal well.
This technology is very promising for application where there are suitable receiving zones and
confining layers. Since the injection process depends on fracturing the receiving formation, there must
exist a suitable formation that can be safely fractured. Furthermore, that formation must be confined by
layers which will not be affected by the fracturing so that the injected material remains in place.
The system operating at Prudhoe Bay is reinjecting ground cuttings through a well annulus at
about 3,000 ft into the Cretaceous zone. The disposal formations consist of poorly consolidated
sediments with high permeability and a porosity estimated at 20 to 25 percent. These formations are
easily fractured because they are not tightly cemented. In addition, the formations are isolated by
confining layers, and there are no underground sources of drinking water.
VII-35
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The size of the system operating at Prudhoe Bay occupies 3,180 square feet. A similarly
designed smaller unit is also planned for a onshore drilling location on the North Slope of Alaska. The
particle size for the injection slurry is 100 microns. The area requirement for this unit is 1,280 square
feet.
While ongoing design work may result in more compact units, this technology is not available
for application to offshore platforms due to the lack of suitable formations across regions or the whole
subcategory for injection and the inability of platforms to accommodate the large size of these systems.
5.2.10 Incineration
Incineration was considered as an alternative treatment option for drilling wastes. The Agency
rejected incineration because of equipment size, energy costs, and possible fire hazards if used OE
offshore platforms. However, incineration may be applicable for treatment of drilling wastes that are
transported onshore for reconditioning, treatment, and/or disposal, or the treatment of residuals from the
processing of the wastes.
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6.0 REFERENCES
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Offshore Operators Committee, "Alternate Disposal Methods for Muds and Cuttings, Gulf of
Mexico and Georges Bank," December 7, 1981. (Offshore RulemaJdng Record Volume 28)<
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.
Letter from James F. Branch, Offshore Operators Committee, to Ronald P. Jordan, Engineering
and Analysis Division, U.S. Environmental Protection Agency, "Offshore Operators Committee
Response to EPA Effluent Guidelines Questions in Letter Dated August 2, 1991," August 30,
1991. (Offshore Rulemaking Record Volume 28)
Petroleum Equipment Suppliers Association, Environmental Affairs Committee, "Chemical
Components and Uses of Drilling Fluids," Appendix A, March 25, 1980. (Offshore Rulemaking
Record Volume 28)
Dalton-Dalton-Newport, "Analysis of Drilling Muds from 74 Offshore Oil and Gas Wells in the
Gulf of Mexico," prepared for the U.S. Environmental Protection Agency, Monitoring and Data
Support Division, June 1, 1984.
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.
(Offshore RulemaJdng Record Volume 26)
McCulloch, W.L., J.M. Neff, and R.S. Carr, "Bioavailability of Selected Metals from Used
Offshore Drilling Muds to the Clam Rangia cuneata and the Oyster Crassostrea gigas."
Symposium - Research on Environmental Fate and Effects of Drilling Fluids and Cuttings,
Sponsored by API, Lake Buena Vista, Florida, January 1980.
Dalton-Dalton-Newport, "Assessment of Environmental Fate and Effects of Discharges from
Offshore Oil and Gas Operations," 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.
T.W. Duke et al., "Acute Toxicity of Eight Laboratory-Prepared Generic Drilling Fluids to
Mysids (Mysidopsis bahid)," Gulf Breeze Environmental Research Laboratory, Office of Research
and Development, U.S. Environmental Protection Agency, May 1984. (Offshore Rulemaking
Record Volume 26)
CENTEC Analytical Services Inc., "Results of Laboratory Analysis and Findings Performed on
Drilling Fluids and Cuttings - Draft," submitted to Effluent Guidelines Division, U.S.
Environmental Protection Agency, April 3, 1984. (Offshore Rulemaking Record Volume 13)
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11. 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.
12. Batelle New England Marine Research Laboratory, "Final Report for Research Program on
Organic Chemical Characterization of Diesel and Mineral Oils Used as Drilling Mud Additives,"
prepared for Offshore Operators Committee, December 31, 1984. (Offshore Rulemdking Record
Volume 13)
13. SAIC, "Descriptive Statistics and distributional Analysis of Cadmium and Mercury
Concentrations in Barite, Drilling Fluids, and Drill Cuttings from the API/USEPA Metals
Database," prepared for Industrial Technology Division, U.S. Environmental Protection Agency,
February 1991. (Offshore Rulemaking Record Volume 120)
14. 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. (Offshore
Rulemafdng Record Volume 120.)
15. 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.
(Offshore Rulemaking Record Volume 73.)
16. Ampian, Sarkis, G., "Barite Minerals Yearbook 1985," Bureau of Mines, U.S. Department of
Interior, 1986.
17. Batelle New England Marine Research Laboratory, "Final Report for Research Program on
Organic Chemical Characterization of Diesel and Mineral Oils Used as Drilling Mud Additives -
Phase n," prepared for Offshore Operators Committee, December 24, 1986. (Offshore
Rulemaking Record Volume 60)
18. Kohlmann Ruggiero Engineers, P.C., "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," prepared for Industrial Technology Division, U.S.
Environmental Protection Agency, March 25, 1987. (Offshore Rulemaking Record Volume 66)
19. Attachments to Letter from Jeff Kirsner, Bariod Drilling Fluids, Inc., to Ron Jordan, U.S.
Environmental Protection Agency, "Short Course on Solids Control," September 5, 1991.
20. Petroleum Equipment Suppliers Association. Response to EPA Request on Solids Control
Equipment Used Offshore, PESA, August 1991.
21. Kohlmann Ruggiero Engineers, P.C., "Costs of Drilling Cuttings Washing, and Mud Cuttings
Transportation to Shore and Land Disposal for the Offshore Oil and Gas Industry, Gulf of
Mexico," prepared for William Telliard, Effluent Guidelines Division, U.S. Environmental
Protection Agency, July 5, 1984. (Offshore Rulemaking Record Volume 17)
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22. Alaska Oil and Gas Association (AOGA), "Comments on USEPA 40 CFR Part 435 Oil and Gas
Extraction Point Source Category, Offshore Subcategory, Effluent Limitations Guidelines and
New Source Performance Standards, Proposed Rule," May 19, 1991. (Offshore RulemaJdng
Record Volume 138)
23. Letter from Art Mazerole Sr., Apollo Services Inc., to Joe Dawley, SAIC with vendor literature
entitled "Closing the Loop with Onsite Oil Based Mud Cuttings Disposal," June 9, 1992.
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SECTION VIII
DRILL CUTTINGS -
CHARACTERIZATION, CONTROL AND TREATMENT TECHNOLOGIES
1.0 INTRODUCTION
The first part of this section describes the sources, volumes, and characteristics of drill cuttings
generated from offshore oil and gas exploration and development activities. The second part of this
section describes the control and treatment technologies currently available for the drill cuttings waste
stream.
2.0 DRILL CUTTINGS SOURCES
Drill cuttings are small pieces of formation rock that are generated by the crushing action of the
drill bit. Drill cuttings are carried out of the borehole with the drilling fluids. Fine drill solids disperse
into the drilling fluids and can significantly effect the mud's rheological properties. Solids control is the
process of maintaining the concentration of drill solids in the drilling fluid at a constant and desirable
level. The most common solids control methods are dilution, displacement, and mechanical removal.
In the offshore drilling industry, a combination of all three methods is employed to achieve the desired
solids content of the drilling fluid.
2.1 SOLIDS CONTROL SYSTEM
Upon reaching the surface, cuttings and fluids pass through the solids control system. The basic
solids control system for a weighted mud consists of a shale shaker, a desander, and a desilter. Figure
VTJI-1 is a flow diagram for a typical solids control system. The following paragraphs describe the
components of the system.1
Shaleshakers are mechanical devices consisting of: a mud box (designed to evenly distribute the
mud flow onto the screen surface), a vibrating assembly and deck, and a stationary bed which diverts the
screened drilling fluid (underflow) to the mud tank system. Shaleshakers are designed to remove drill
solids that are 74 microns and larger. The parameters that affect the performance of a shaleshaker are:
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shaker screen type and size, gravity force generated by the shaker motion, drilling fluid properties, and
solids loading.
The desander is a hydrocyclone capable of removing sand-size particles greater than 44 microns
by centrifugal force. Drilling fluids containing a high percentage of formation sands are believed to cause
excessive weight and viscosity problems.
The desilter is a hydrocyclone capable of removing silt-size particles greater than 8 microns by
centrifugal force. Drilling fluids containing a high percentage of fine silts are believed to promote side
wall sticking.
A mud cleaner is a desilter combined with vibrating screens so that the underflow solids discharge
can be screened before being discarded. This is necessary for weighted muds because a high percentage
of barite is discharged in the underflow (and out of the mud circulation system) since barite can have
particle sizes greater than 10 microns. Typically, a mesh screen with a 74 micron opening is used so that
all solids smaller than 74 microns (barite) will pass through the screen and be returned to the mud system.
"Barite recovery" centrifuges are used to control mud viscosity by increasing the fine solids
removal and barite recovery. Centrifuges are also used for secondary recovery of liquid and chemical
that is normally lost to the reserve tank. This loss would occur in the jetting of whole mud, the dumping
of sand traps, and the discard from components of the solids control equipment.
The "barite recovery" centrifuges are typically used for weighted muds with densities ranging
from 12 to 19 pounds per gallon. This centrifuge removes the ultrafine and colloidal size solids that
cause high viscosity in a weighted mud system. The barite separates from the mud in the underflow
while the water, chemicals, bentonite, and fine drill solids are separated though the overflow.
Secondary recovery centrifuges recover the liquid and chemicals that are normally lost to the
reserve tank with the cuttings. Secondary recovery centrifuges can be used to treat the underflows of the
desander and desilter, and the overflow of the barite recovery centrifuge.
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3.0 DRILL CUTTINGS VOLUMES
The volume of drill cuttings generated depends on the depth and diameter of the well drilled.
Drill solids are continuously removed via the solids control equipment during drilling. The greatest
volumes of drill cuttings are generated during the initial stages of drilling when the borehole diameter is
large. Continuous and intermittent discharges are normal occurrences in the operation of solids control
equipment. Such discharges occur for periods from less than 1 hour to 24 hours per day, depending on
the .type of operation and well conditions.
The volume of drill cuttings generated also depends on the type of formation being drilled., the
type of bit, and the type of drilling fluid. Soft formations are more susceptible to borehole washout than
hard formations. The type of drilling fluid used will minimize borehole washout and shale sloughing.
The type of drill bit determines the characteristics of the cuttings (particle size). Depending on the
formation and the drilling characteristics, the total drill solids generated will be at least equal to the
borehole volume and sometimes several times the borehole diameter.
A report by the Offshore Operators Committee presented data from two drilling projects in the
Gulf of Mexico. The report presents drilling data from a 10,000 foot well and a 18,000 foot well. Table
VB-l in Section W.3 presents volumes of drill cuttings generated for both wells. The cuttings volumes
do not equal the hole volume because approximately 50 percent of the cuttings were assumed to be
dispersed in the drilling fluid.2
4.0 DRILL CUTTINGS CHARACTERISTICS
Drill cuttings themselves are inert solids from the formation. However, drill cuttings discharges
also contain drilling fluids that have adhered to the cuttings. The composition of drill cuttings discharges
is directly dependent upon the fluid used. Cuttings associated with oil-based drilling fluids or from
petroleum bearing formations will contain trace amounts of hydrocarbons. Hydrocarbons adsorb on the
surface of drill solid particles and resist removal by washing operations. The volume of the mud
adhering to the discharged cuttings can vary considerably depending on the formation being drilled and
the cutting's particle size distribution. A general rule of thumb is that five percent (5%) mud (by volume)
is associated with the cuttings.3 Data from a drilling project in the OCS off southern California indicate
that the cuttings discharges from the solids control equipment were comprised of 96 percent cuttings and
4 percent adhered drilling fluids.4
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5.O CONTROL AND TREATMENT TECHNOLOGY
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Pollutant type and waste management practices for drill cuttings are entirely related to the drilling
fluid used. Drill cuttings associated with an oil-based drilling fluid are contaminated with hydrocarbons
(diesel or mineral oil). Cuttings associated with a low-toxicity water-based drilling fluid are considered
to have toxicity similar to the drilling fluids.
5.1 BPT TECHNOLOGY
The BPT limitations for drill cuttings prohibit the discharge of free oil based upon using the
presence of a visible sheen upon the receiving water as a test for compliance. Cuttings that create sheens
are from drilling operations that: use oils for lubricity or spotting purposes; or use oil-based muds.
Cuttings that contain free oil are either collected and transported to shore for disposal or sufficiently
washed to remove free oil prior to discharge. Cuttings that do not create a sheen can be discharged to
the surface waters.
Cuttings washing technology is a mechanical separation process. The cuttings are processed hi
a series of tanks, screens, and cyclones which separates the oil from the solids. Detergents are often used
to enhance separation. In 1983, EPA evaluated several cuttings washing systems. The evaluation
indicated that these systems can consistently reduce the oil content in cuttings to a range of 5 to 10
percent. The evaluation also indicated that the most common method of compliance for cuttings
containing some known quantity of oil is onshore disposal.5
5.2 ADDITIONAL TECHNOLOGIES
EPA evaluated several additional technologies for appropriateness as a basis for BCT, BAT, and
NSPS limitations. These technologies are summarized in the following sections.
5.2.1 Onshore Treatment and/or Disposal
Drill cuttings which are unable to comply with the NPDES permit limitations are typically hauled
to shore for treatment and/or disposal. EPA determined that transporting drilling wastes to shore is
currently practiced by industry and is both technologically and economically feasible.
A more detailed discussion of available land disposal methods for drilling wastes can be found
hi Section VII.
VIH-5
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5.2.2 Mechanical Processes
In 1988, EPA presented an evaluation of mechanical cuttings washing systems. Vendor
performance data indicated that achieving a residual oil level of less than 10 percent by weight is
achievable by mechanical washing systems.5-6 Table VIII-1 presents the technology type, equipment
features, capacity, and performance for each of the systems studied.
The mechanical process separates drilling fluids from the cuttings either by high pressure sprays
or by immersion in an agitated tank. The wash solution may be seawater or a solvent and detergents are
often used to enhance separation. The mixture of drill cuttings, drilling fluid, and wash solution is
screened for separation of solids and liquids. Liquids carrying fine solids are processed in desilters or
centrifuges for further separation. The separated oil and additives are recycled back to the mud system,
wash solutions are recycled, and the cuttings are discharged. Cleaned cuttings are discharged either
directly overboard or through a flume below the water surface. In a flume system, cuttings are
discharged below the surface of the water through the inner pipe of a double pipe system. Additional
residual oil remaining on the cuttings may separate and rise through the annulus to the seawater level.
A submersible pump recovers this separated oil and cuttings drop to the ocean floor.
Mechanical systems offered by vendors employ various combinations of the above-mentioned
techniques. The capacity of these systems varies from 1.25 to 12 tons per hour. Space requirements
vary between the different systems. Some of the subsections are modular and can be made to fit available
space. Performance of a cuttings washer system is reported in terms of the residual oil remaining on the
cuttings.
5.2.3 Theirmal Distillation/Oxidation
A detailed discussion of the thermal distillation and oxidation technologies evaluated is presented
in Section VII-5.2.7.
5.2.4 Solvent Extraction
A detailed discussion of the solvent extraction technology evaluated is presented in Section VII-
5.2.8.
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5.2.5 Grinding/Reinjection
A detailed discussion of the drill waste grinding and injection technology is presented in Section
Vn-5.2.9.
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6.0 REFERENCES
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1. Attachments to Letter from Jeff Kirsner, Bariod Drilling Fluids, Inc., to Ron Jordan, U.S.
Environmental Protection Agency, "Short Course on Solids Control," September 5, 1991.
2. Offshore Operators Committee, "Alternate Disposal Methods for Muds and Cuttings, Gulf of
Mexico and Georges Bank," December 7, 1981. (Offshore Rulemaking Record Volume 28)
3. James P. Ray, "Offshore Discharges of Drill Cuttings," Outer Continental Shelf Frontier
Technology. Proceedings of a Symposium, National Academy of Sciences, December 6, 1979.
(Offshore Rulemaking Record Volume 18)
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. Kohlmann Ruggiero Engineers, P.C., "Costs of Drilling Cuttings Washing, and Mud Cuttings
Transportation to Shore and Land Disposal for the Offshore Oil and Gas Industry, Gulf of
Mexico," prepared for William Telliard, Effluent Guidelines Division, U.S. Environmental
Protection Agency, July 5, 1984. (Offshore Rulemaking Record Volume 17)
6. 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,
Ohio, 1977. -
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SECTION IX
PRODUCED WATER -
CHARACTERIZATION, CONTROL AND TREATMENT TECHNOLOGIES
1.0 INTRODUCTION
The first part of this section describes the sources, volumes, and characteristics of produced water
from offshore oil and gas production activities. The second part of this section describes the treatment
technologies available to reduce the quantities of pollutants in produced water discharged to surface water.
2.0 PRODUCED WATER SOURCES
Produced water is the total water generated from the oil and gas extraction process. Produced
water includes: the formation water brought to surface with the oil and gas, the injection water used for
secondary oil recovery that has broken through the formation, and various well treatment chemicals added
during production and the oil/water separation process.
Formation water, which comprises the bulk of produced water, is found in the same rock
formation as the crude oil and gas. Formation water is classified as meteoric, connate, or mixed.
Meteoric water comes from rainwater that percolates through bedding planes and permeable layers.
Connate water (seawater in which marine sediments were originally deposited) contains chlorides, mainly
sodium chloride (NaCl), and dissolved solids in concentrations many times greater than common
seawater. Mixed water is characterized by both a high chloride and sulfate-carbonate-bicarbonate content,
which suggests multiple origins.
3.0 PRODUCED WATER VOLUMES
Produced water is the highest volume waste source in the offshore oil and gas industry. The
volume of wastewater generated by this industry is somewhat unique hi comparison with industries hi
which wastewater generation is directly related to the quantity or quality of raw materials processed. By
contrast, produced water can constitute from 2 percent to 98 percent of the gross fluid production at a
given platform. In general, produced water volume is small during the initial production phase when
hydrocarbon production is the greatest, and increases as the formation approaches hydrocarbon depletion.
IX-1
-------
Produced water volumes are much greater for structures producing oil or a combination of both oil and
gas as compared to gas-only platforms. The volume of produced water at a given platform is a site-
specific phenomenon. In some instances, no formation water is encountered while in others there is an
excessive amount of formation water encountered at the start of production.
According to Walk, Haydel and Associates (1984), the average produced water discharge rate
from an offshore platform is usually less than 1,800 barrels per day (bbl/day), whereas discharges from
large treatment facilities handling water from many platforms may be as high as 157,000 bbl/day.1
Produced water volumes, treatment systems information, and hydrocarbon production from platforms
sampled in EPA's 30-facility study are presented in Table IX-1. Details of this study are discussed in
Section K.4.1. As can be seen from the table, produced water volumes range from 2 to 150..000
bbl/day.
In 1982, EPA conducted a sampling program located offshore from California to characterize
produced water from this region. Three facilities were selected to represent oil production hi the Santa
Barbara Channel. The three facilities are as follows: the Carpinteria onshore treatment facility -
processing fluids from several platforms located in the summerland field, the Ellwood Facility -
processing fluid from platform Hope, and an offshore platform located in federal waters. The production
fluid characteristics of these three facilities are presented hi Table IX-2.
In 1982, sampling of produced water in Alaska was conducted at two major oil and gas producing
fields: coastal faculties in Cook Inlet (Kenai Peninsula), and at an onshore facility hi Prudhoe Bay on the
North Slope. The production fluid characteristics of these facilities is presented in Table IX-3.
To analyze the cost and impact of effluent guidelines regulations, EPA developed average annual
and peak produced water volumes for existing and future model projects. The estimates of produced
water generation rates were developed using the Minerals Management Service (MMS) Platform
Inspection Complex/Structure database. The methodologies used to develop the produced volumes are
presented in the Economic Impact Analysis for the Final Ride. Regional average annual produced water
generation rates for existing facilities (BAT) and future projected facilities (NSPS) are presented in Tables
IX-4 through IX-7. The generation rates are based on the current and projected model platforms
presented in Appendix 1.
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TABLE IX-1
CHARACTERISTICS OF PLATFORMS SELECTED FOR THE 30 PLATFORM STUDY2
No.
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
28
29
30
Platform
BM^MI
EC33A
EC 14CF
V 119D
V 255A
SMI 23B
V39D
SMI6A
El 57A-E
SMI 115A
El 120CF
SMI 130B
El 208B
El 18CF
El 238A
El 296B
SS 107(894)
SS 107(893)
SS 219A
ST177
BM2C
BDC CF5
ST135
WD90A
WD45E
WD70I
GIBDB600
WD 105C
SP62A
SP 24/27
SP65B
Company
mmmmmmt
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
OUYCondecjsate
(bbl/day)
^MMMHMB
76.6
807
890
950
228
395
250
1,200
750
3,500
21,500
1,501
2,000
40
1,500
501
2,875
3,000
2,800
10,794
873
6,000
2,244
745
5,273
554
2,091
1,800
24,000
5,000
Gas
$iMCF/<%)
HBMMiM
15.2
13.1
3.4
14
13.8
38
0.2
150
45
5
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/day)
HBOmiMH
62
2,005
2,817
1,298
495
634
625
500-2,000
1,200
2,000
9,733
350
22,000
2
1,470
4,610
12,500
800-1,000
1,072
6,590
11,028
8,400
15,000
1,578
10,721
3,796
7,532
3,100
150,000
3,000
Treatment (1)
mt^ammmmmmm
OS and DISS
OS and DISP
DISP
OS and DISP
OS and DISP
OS and DISP
OS and DISP
OS and DISP
DISP
OS and DISS
DISP
OS and DISS
DISP
DISP
DISP
OS and DISP
OS and DISP
DISP
OS and DISP
DISP
DISP
OS and DISP
DISP
OS and DISS
OS and DISP
OS and DISP
W OS - Oil Skimming; DISS = Dissolved Gas Flotation; DISP = Dispersed Gas Rotation
IX-3
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TABLE IX-2
CHARACTERISTICS OF FACILITIES SELECTED FOR
THE CALIFORNIA SAMPLING PROGRAM3
.. FadlHy
Ellwood Facility
Carpinteria Facility
Offshore Platform
Produced Water
- Volume 0>t>l)
1,230
14,000.
25,000
Oil.
WHMiMHIHIIINIMMIIIilWliiiHIHHMIII
Coastal Cook Inlet
Onshore Cook Inlet
Prudhoe Bay Oil Field
Produced Water
Volume 0>bl)
18,350
6,600
13,000
Oil (bbl)
1,300
12,500
92,100
Gas
CMO)
410
-
136,500
Treatment
Oil skimming, reinjection
(59% reinjected and 41%
discharged overboard)
Oil skimming, flotation,
reinjection (33% reinjected
and 67% discharged
overboard)
Reinjection (100%)
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TABLE IX-4
BAT PRODUCED WATER GENERATION RATES - 4 MILE PROFILE
(Millions of Barrels per Year)
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Region
Gulf of Mexico
Pacific
Alaska
Atlantic
Total
Within 4 Miles
57,075
81,773
0
0
138,848
Beyond 4 Miles
846,307
131,098
0
0
977,405
Total
903,383
212,870
0
0
1,116,253
TABLE IX-5
BAT PRODUCED WATER GENERATION RATES - 3 MILE PROFILE
(Millions of Barrels per Year)
Region ป_ |
Gulf of Mexico
Pacific
Alaska
Atlantic
Total
Within 3 Miles
14,705
58,409
0
0
73,114
: .Beyond 3 Miles
888,678
154,461
0
0
1,043,139
Total
903,383
212,870
0
0
1,116,253
TABLE IX-6
NSPS PRODUCED WATER GENERATION RATES - 3 MILE PROFILE
(Millions of Barrels per Year)
Region
Gulf of Mexico
'Pacific
Alaska
Atlanta
Total
Within 3 Miles
31,761
0
35,532
0
67,293
Beyond 3 Miles
345,482
o
9,287
0
354,769
Total
377,243
0
44,819
0
422,062
IX-5
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TABLE IX-7
NSPS PRODUCED WATER GENERATION RATES - 4 MILE PROFILE
(Millions of Barrels per Year)
Region
Gulf of Mexico
Pacific
Alaska
Atlanta
Total
Within 4 Miles
37,421
0
35,532
0
72,953
Beyond 4 Miles
339,822
0
9,287
0
349,109
Total
377,243
Q
44,819
0
422,062
4.0 PRODUCED WATER COMPOSITION
In 1980, very few data existed on the composition of produced water other than conventional
parameters! In 1981, EPA embarked on a systematic effluent sampling study to identify and quantify the
characteristics of produced water with regard to priority toxic pollutants. Sampling programs were
conducted in the three major offshore producing areas of the United States, i.e., the Gulf of Mexico,
California, and Alaska. Separate discussions on the characteristics of produced water are presented for
each of the regional offshore producing area
Since the 1985 proposal, no new EPA field sampling data have been acquired relating to the
general character of untreated produced waters generated at offshore facilities. However, studies have
been conducted on the characteristics of treated produced water either for BPT (permit limit) compliance
or reinjection. In addition, statistical evaluations of data previously and newly submitted by the public
have been conducted. The results of the studies and evaluations and how they affect the final effluent
limitations guidelines are discussed in the following sections.
4.1 GULF OF MEXICO - 30 PLATFORM STUDY
During the period of October 9-30, 1981, thirty 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 produced water discharges. Overall, 79 individual samples were
collected and analyzed. Twenty of the 79 samples collected were obtained from the influent to the
treatment systems, while the remaining 59 samples were treated effluent samples. Table IX-8 presents
IX-6
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the overall summary of occurrence of the organic priority pollutants detected in the 59 samples of
effluents. As can be seen from this table, benzene, ethylbenzene, naphthalene, phenol, toluene, 2,4-
dimethylpheriol, and bis-(2-ethylhexyl)phthalate were observed in 80 percent or more of the effluent
samples analyzed. An additional 15 organic compounds were detected far less frequently. The
occurrence for these parameters ranged from 2 percent to 32 percent of the effluent samples analyzed.
Many were either at or just above the detection limit.
TABLE IX-8
PERCENT OCCURRENCE OF ORGANICS FOR TREATED EFFLUENT SAMPLES
30 PLATFORM STUDY34
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
Dibeiazo(a,h)anthracene
Chlorobenzene
Di-n-octyl phthalate
3,4-Benzofluoranthene
1 1, 12-Benzofluoranthene
Pentachlorophenol
1 , 1-Dichloroethane
Bis(2-chloroethyl)ether
Number of Valid
Determinations (2)
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 not detected hi any of the 59 effluent samples.
(2) - Number of samples which yielded valid analytical results.
The 30-platform data were used to support the proposed 1985 effluent limitation guidelines. For
the 1991 proposal, EPA recalculated the data to reflect updated statistical procedures.4 Specific reasons
foi the reanalysis were:
IX-7
-------
Concentration values for metals were previously calculated without reference to detection
limits. The values reported in the analysis treats sample values reported below the
detection limit to be zero as shown in Table IX-9.
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 the reanalysis, where duplicate samples
were considered, 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 IX-9
POLLUTANT CONCENTRATIONS IN BPT TREATED
PRODUCED WATER FROM THE THIRTY PLATFORM STUDY4-34
Pollutant Parameter ,
Oil & Grease
TSS
Priority Organic Pollutants
Benzene
Bis(2-ethylhexyl)phthalate
Ethylbenzene
Naphthalene
Phenol
Toluene
2,4-Dimethylphenol
Priority Metal Pollutants
Cadmium
Copper
Lead
Nickel
Silver
Zinc
March 1991 1PT Effluent
89.8 mg/1
67.5 mg/1
1,823.00 jug/1
101. 00 /tg/1
505.00 /tg/1
138.00 /tg/1
954.00 /tg/1
1,545.00 /tg/1
14.40 /tg/1
29.35 /tg/1
183.42 /tg/1
350.57 /tg/1
142.64 /tg/1
59.19 /tg/1
2,360.00 /tg/1
Table EX-9 presents the recalculated pollutant concentrations from the 30-platform study used to
represent baseline effluent characteristics for priority pollutants achievable by BPT technology as
presented in the March 13, 1991 proposal. Appendix 2 Tables A2-1, A2-2, and A2-3 present the data
from this study.
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4.2 CALIFORNIA SAMPLING PROGRAM
Table IX-10 presents the analytical data from the sampling program conducted in California in
1982. Statistical analyses from the Three Facility Study were conducted to assess detection rates of
organic and metal pollutants and to generate facility-specific descriptive statistics for total suspended
solids (TSS), oil and grease (O&G), and organic and metal pollutants in both gas flotation and granular
media filtration effluent produced water. Tables IX-11 and IX-12 present analytical data from the Three
Facility Study. Gas flotation effluent aggregate estimates used data from only two facilities, both located
off California. The third facility is in New Mexico and does not utilize gas flotation in its produced
water treatment process. Appendix 2 presents the analytical data from the three facility study.
TABLE IX-10
AVERAGE EFFLUENT COMPOSITION OBTAINED
FROM THE 1982 CALIFORNIA SAMPLING PROGRAM3
'
Parameter
Oil and Grease (mg/1)
Organic Priority Pollutants:
Benzene 0*g/l)
Ethylbenzene (/ig/1)
Toluene Og/1)
Phenol (/ig/1)
2,4-Dimethylphenol (/tg/1)
Naphthalene G*g/l)
Bis(2-ethylhexyl)phthalate (jug/1)
Priority Metal Pollutants:
Copper (/tg/1)
Lead (/ig/1)
Zinc (/ig/1)
Non-conventionals:
TDS (mg/1)
Chloride (mg/1)
Pollutant Concentration
Ellwood
Facility
NA
4,000
348
2,940
1,046
213
84
<10
165
113
220
NA
NA
Carpinteria
Facility
5
1,463
148
2,750
973
772
86
ND
109
ND
46
22,700
10,500
Offshore
Facility
NA
286
140
544
19
189
127
ND
198
77
78
NA
NA
NA - Not Analyzed
ND - Not Detected
IX-9
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TABLE IX-11
PRIORITY POLLUTANT DETECTION RATES IN FILTER TREATED PRODUCED WATER
FROM THE THREE-FACILITY STUDY5
Parameter
Organic Pollutants:
Benzene
Benzoic acid
Ethylbcnzene
m-Xylene
o,p-Xylene
o-Cresol
p-Cresol
Phenol
Toluene
2-Butanone
Naphthalene
2-Mcthylnaphthalene
2-Propanone
2,4-Dimethylphenol
Bis(2-ethylhexyl)phthalate
Priority Metal Pollutants:
Aluminum
Antimony
Arsenic
Boron
Barium
Cadmium
Copper
Iron
Magnesium
Manganese
Nickel
Silver
Titanium
Yttrium
Zinc
JJetSiOrt
Limit Otg/I)
1,000
50
1,000
10
55
10
10
10
1,000
275
10
10
275
10
10
35
31
17
10
2
4
6
12
46
2
30
7
3
2
14
Shell - Beta Complex
Number/
Detects
4
1
4
4
3
2
4
4
4
4
4
4
4
2
0
4
1
0
4
4
0
1
4
4
4
0
0
2
2
4
Detect
Rate
100%
25%
100%
100%
75%
50%
100%
100%
100%
100%
100%
100%
100%
50%
0%
100%
25%
0%
100%
100%
0%
25%
100%
100%
100%
0%
0%
50%
50%
100%
Thnms * Long Beach
Number
Detects
4
0
4
3
0
0
1
0
4
1
3
0
3
0
0
4
0
1
4
4
0
4
4
4
4
0
0
3
2
4
Detect
Rate
100%
0%
100%
75%
0%
0%
33%
0%
100%
25%
100%
0%
75%
0%
0%
100%
0%
25%
100%
100%
0%
100%
100%
100%
100%
0%
0%
75%
50%
100%
ConOCo, Hqbbs, NM
Numter
Detects
4
2
4
4
4
3
3
3
4
P
3
3
1
3
0
1
2
4
4
4
0
2
4
4
4
0
0
4
4
4
Detect
Rate
100%
50%
100%
100%
100%
75%
75%
75%
100%
0
; 75%^
75%
25%
! 75%.
0
25%
50%
100%
100%
100%
0
50%
100%
100%
100%
0
0
100%
100%
100%
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TABLE IX-12
PRODUCED WATER POLLUTANT CONCENTRATIONS IN FILTER INFLUENT
FROM THREE FACILITY STUDY5
'"
-
Pollutant Parameter
Oil & Grease
TSS
Organic Pollutants:
Benzene
Benzole acid
Ethylbenzene
m-Xylene .
o,p-Xylene
o-Cresol
p-Cresol
Phenol
Toluene
2-Butanone
Naphthalene
2-Methylnaphthalene
2-Propanone
2,4-Dimethylphenol
Priority Metal Pollutants:
Aluminum
Antimony
Arsenic
Boron
Barium
Cadmium
Copper
Iron
Magnesium
Manganese
Nickel
Silver
Titanium
Yttrium
Zinc
Concentrations (/tg/1)
Shell * tf eta Complex
MIN*
43.50
13.38
949.45
50
232.51
102.66
21.21
10
115.12
116.79
1,263.0
601.23
66.34
12.18
941.64
10
56
4
NR
29,300
64,600
NR
6
657
172,000
134
NR
NR
3
2
37
MAX*
56.50
16.97
,073.17
633.77
322.97
123.32
100.00
29.53
151.11
188.27
1,292.5
1,493.6
76.0
15.35
1,237.6
286.5
103
40
NR
35,400
67,400
NR
111
880
189,000
145
NR
NR
50
3
55
MED*
50.15
13.94
971.06
50
256.73
112.24
25.09
14.10
117.82
162.11
1,330.02
1,380.5
72.17
12.93
1,135.4
123.1
71
32
NR
, 31,875
65,770
NR
6
689
175,250
140
NR
NR
2
a
46
Thums * Long Beach
MIN*
13.14
16.24
43.57
NR
19.24
10
NR
NR
10
NR
67.18
50
14.99
NR
50
NR
53
NR
2
36,900
39,300
NR
35
2,420
318,000
160
NR
NR
3
A
61
MAX*
24.42
33.51
56.7
NR
27.33
17.02
NR
NR
36.11
NR
85.68
65.84
21.53
NR
144.7
NR
145
NR
31
39,800
47,600
NR
153
16,000
350,000
364
NR
NR
7
3
96
MED*
20.75
23.63
54.6
NR
24.18
12.99
NR
NR
10
NR
84.92
50
18.94
NR
86.3
NR
136
NR
20
38,100
41,850
NR
75
5,915
321,522
193
NR
NR
5
2
65
Conoco, Hobfes, NM
MIN*
25.87
53.78
,833.8
50
950.95
279.87
138.81
10
10
10
5,081.3
NR
10
10
,500
10
35
40
33
6,710
48
NR
6
535
415,000
88
NR
NR
10
6
16
MAX*
41.83
74.72
9,135.6
2,431.15
1,039.1
317.7
157.35
158.15
551.38
611.68
5,635.2
NR
57.74
16.11
628.17
227.46
43
70
363
7,080
51
NR
146
800
467,000
93
NR
NR
14
9
34
MEP*
34.54
64.18
,031.65
976.56
,023.1
288.63
142.87
134.35
445.06
444.39
5,250.05
NR
50.54
14.89
500
173.29
35
68
220
6,760
50
NR
12
668
445,000
91
NR
NR
12
8
18
*Pollutant Concentration "Minimum Level" Values were Substituted for Non-detect Samples
NR=Not Reported
4.3 ALASKA SAMPLING PROGRAM
Table IX-13 presents the analytical results obtained from the sampling program conducted in
Alaska hi 1982. A comprehensive Cook Inlet Discharge Monitoring Study was conducted by Region 10
to investigate oil and gas extraction point discharges.6 Produced water discharges from production
facilities in Cook Inlet (coastal subcategory) were sampled and analyzed for one year, September 1988
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through August 1989. Samples were collected from two oil platforms and one natural gas platform, all
of which discharge to the surface waters, and also from three shore-based central treatment facilities.
Table IX-14 presents averages of effluent concentrations from these six facilities. Appendix 2 presents
the data from this study.
TABLE IX-13
AVERAGE EFFLUENT CONCENTRATIONS OBTAINED
FROM THE 1982 ALASKA SAMPLING PROGRAM3
Parameter
Oil and Grease (mg/1)
Organic Priority Pollutants:
Benzene (/tg/1)
Ethylberizene (/tg/1)
Toluene G*g/l)
Phenol (/ig/1)
2,4-Dimethj'lphenol (/ig/1)
Naphthalene (/ig/1)
Bis(2-ethylhexyl)phthalate (/ig/1)
Priority Metal Pollutants:
Copper (/ig/1)
Mercury (/ig/1)
Zinc (/ig/1)
Non-Conventionals:
TDS (mg/1)
Chloride (mg/1)
Coastal
Cook inlet
17
7,375
345
3,025
1,810
438
359
176
55
3
1,750
24,570
12,200
Onshore
Cook Inlet
15
7,240
170
2,805
1,683
420
330
80
55
3
21
25,880
13,000
Prodhoe
Bay
Oil Field
10
1,370
900
9,630
3,490
830
595
228
-
3
ND
19,800
10,220
"ND - Not detected
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TABLE IX-14
AVERAGE EFFLUENT CONCENTRATIONS FROM
PRODUCED WATER IN COOK INLET DMR DATA6
Parameter
Oil and Grease (mg/1)
Priority Organic Pollutants:
Benzene (/tg/1)
Toluene Otg/1)
Ethylbenzene (/ig/1)
Phenol (/ig/1)
Naphthalene Gig/1)
2,4-Dimethylphenol (jigll)
Bis(2-ethylhexyl)phthalate (jig/I)
Priority Metal Pollutant:
Zinc (^g/1)
Non-conventional Pollutants:
TOC (mg/1)
Concentration
30.3
7,452
3,326
311
825
1,150
293
-
719
389.0
4.4 STATISTICAL ANALYSIS OF EPA/API PRODUCED WATER EXPANDED DATASET
For the final rule, EPA recalculated the BPT baseline effluent characteristics based on several
industry and EPA databases. Table IX-15 presents the BPT effluent data.
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1.
TABLE IX-15 ป
1
1992 BPT EFFLUENT DATA7
,
JMV f,J S ' "***
Pollutant Parameter
Oil and Grease
TSS
Priority and Non-conventional Organic Pollutants:
Anthracene
Benzene
Benzo(a)pyrene
Chlorobenzene
Di-n-butylphthalate
Ethylbenzene
n-Alkanes
Naphthalene
p-Chloro-m-cresol
Phenol
Steranes
Toluene
Triterpanes
Total xylenes
2-Butanone
2,4-Dimethylphenol
Priority and Non-conventional Metal Pollutants:
Aluminum
Arsenic
Barium
Boron
Cadmium
Copper
Iron
Lead
Manganese
Nickel
Titanium
Zinc
Radionuclides:
Radium 226
Radium 228
Recalculated BPT
Effluent
25 mg/1
67.5 mg/1
18.51 /ig/1
2,978.69 /ig/1
11.61 /ig/1
19.47 /ig/1
16.08 /tg/1
323.62 /tg/1
1,641. 50 /ig/1
243.58 /ig/1
25.24 /ig/1
1,538.28 /ig/1
77.50 /ig/1
1,897.11 /ig/1
78.00 /ig/1
695.03 /tg/1
1,028.96 /ig/1
3 17. 13 /ig/1
78.01 /ig/1
114. 19 /ig/1
55,563.80 /ig/1
25,740.25 /ig/1
22.62 /ig/1
444.66 /tg/1
4,915.87 /ig/1
195.09 /ig/1
115,87 /ig/1
1,705.46 /ig/1
7.00 /ig/1
1,190. 13 /ig/1
2.2628X10"4 /ig/1
2.7671X1O4 /ig/1
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5.0 CONTROL AND TREATMENT TECHNOLOGIES ~|
Treatment processes for produced water are primarily designed to control oil and grease, priority *
pollutants, and total suspended solids. Currently, most NPDES permits allow the discharge of offshore
produced water to surface, saline water bodies, subject to limitations only on the oil and grease content
(BPT limitation).
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5.1 BPT TECHNOLOGY
BPT effluent limitations restrict the oil and grease concentrations of produced water to a
maximum of 72 mg/l for any one day, and to a thirty day average of 48 mg/l. BPT end^of-pipe treatment
that can achieve this level of effluent quality consists of some, or all of the following technologies:
Equalization (surge tank, skimmer tank)
Solids removal desander (with or without sand washer)
Chemical addition (feed pumps)
Oil and/or solids removal
Flotation
Filters
Plate coalescers
Gravity separators
Subsurface disposal (reinjection).
The separation of oil from produced water is directly related to the particle size of the oil droplets
dispersed in the produced water. Oil is present hi produced water .in a range of particle sizes from
molecular to droplet. Reducing the oil content of produced water involves removing three basic forms
of oil: (1) large droplets of coalesceble oil, (2) small droplets of emulsified oil, and (3) dissolved oil.
Produced water treatment processes 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 other types of
compounds in the produced water. Examples of working ranges for some produced water treatment units
are:
Unit Sizes Removed
Flotation above 10-20 microns
Parallel plate coalescers above 30-40 microns
Proprietary (API) separators above 6 microns
Skim tanks above 15 microns
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
IX-15
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agents, fine solids, and high static charges on the droplets.8 Any operational change that promotes the
formation of smaller droplets or the stabilization of small droplets through increased produced water flow
velocities and/or increased pollutant loadings can result in poor oil and water separation. Operational
changes affecting the performance of the produced water treatment system, referred to as upset
conditions, can be caused by detergent washdowns in deck drainage entering the treatment unit, high flow
volumes caused by heavy rainfall, and equipment failures.
End-of-pipe control technology for offshore treatment of produced water from oil and gas
production consists of physical and/or chemical methods. The type of treatment system selected for a
particular facility is dependent upon availability of platform space, waste characteristics, volumes, existing
discharge limitations, and other site specific factors. Oil skimming with gravity separation and/or
chemical treatment and gas flotation are widely used hi the offshore industry because of space limitations
on platforms. A description of the unit processes that may be used in the treatment scheme for produced
water is presented in the following sections.
5.1.1 Equalization
Equalization dampens flow and pollutant concentration variation of wastewater prior to subsequent
downstream treatment. By reducing the variability of the raw waste loading, equalization can
significantly improve the performance of downstream unit processes by providing uniform hydraulic,
organic, and solids loading rates. Increased treatment efficiency reduces effluent variability associated
with slug raw waste loadings. Equalization is accomplished in a holding tank. The tank should be
designed with sufficient retention tune to dilute the effects of variable flow and concentrations on the
treatment plant performance. Some oil and water separation will also take place in the equalization tank.
5.1.2 Solids Removal
The fluids produced with oil and gas may contain small amounts of sand or scale particles from
the piping which must be removed from lines and vessels. Removal of these solids can be accomplished
by blowdown, by cyclone separators (desanders), or during equipment cleanout. Desanders are not
typically used in offshore operations to remove sand (and other particles) from produced water. The most
common method of removing produced solids from the process equipment is during cleanout of the
gravity separators which accumulate solids. Equipment cleanouts typically occur every three to five
years. Additional information on produced sand generation rates and disposal practices is presented in
Section X.
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5.1.3 Gravity Separation
The simplest form of produced water treatment is gravity separation in horizontally or vertically
configured tanks or pressure vessels. Gravity separators are sometimes called skim tanks, skini vessels,
or water clarifiers. Gravity separators are designed with enough storage capacity to provide sufficient
residence time for the oil and water to separate. Performance of these systems depends upon the
characteristics of the oil, produced water, flow rates, and retention time. Gravity separation systems with
large residence tunes are typically located onshore (and have limited application) on offshore platforms
because of space and weight limitations. While a treatment system relying exclusively on gravity
separation requires large tanks with long retention times, any treatment can benefit from even short
periods of quiescent retention to allow for some oil and water separation and dampen surges in flow rate
and oil loadings.
5.1.4 Parallel Plate Coalescers
Parallel plate coalescers are gravity separators which contain a pack of parallel, tilted plates
arranged so that oil droplets passing through the pack need .only rise a short distance before striking the
underside of the plates. Guided by the tilted plate, the droplet then rises, coalescing with other droplets
until it reaches the tip of the pack where channels are provided to carry the oil away. In their overall
operation, parallel plate coalescers are similar to API gravity oil-water separators. The pack of parallel
plates reduces the distance that oil droplets must rise in order to be separated; thus the unit is much more
compact than an API separator. Suspended particles, which tend to sink, move down a short distance
when they strike the upper surface of the plate; then they move down along the plate to the bottom of
the unit where they are deposited as sludge and can be periodically removed. Particles may become
attached (scale) to the plates' surfaces requiring periodic removal and cleaning of the plate pack.
Where stable emulsions are present, or where the oil droplets dispersed in the water are relatively
small, parallel plate coalescers may not provide an effective oil-water separation.
5.1.5 Gas Flotation
Gas flotation units introduce small gas bubbles into the body of wastewater to be treated. As the
bubbles rise through the liquid, they attach themselves to any oil droplet hi their path, and the gas and
oil rise to the surface where they are skimmed off as a froth.
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The gas flotation methods currently available are generally divided into two groups: (1) dissolved-
gas flotation (DGF) and (2) induced-gas flotation (IGF). The major difference between these methods
are the techniques used to generate the gas bubbles and the size of the gas bubbles produced. In
dissolved-gas flotation, the gas bubbles are generated by the precipitation of air (gas) from a super-
saturated solution. In induced-gas flotation, gas bubbles are generated by mechanical shear or propellers,
diffusion of gas through a porous media, or homogenization of a gas and liquid stream. The size of
bubbles produced hi dissolved gas flotation (average 10 to 100 microns in diameter) are an order of
magnitude smaller than those generated hi induced-gas flotation.9
Dissolved-gas flotation processes were at one time extensively used for the final treatment of
produced oil field water.10 Currently, the majority of the offshore oil production facilities use induced-
gas flotation systems for treating their produced water before final disposal. Induced-gas flotation
requires less space than dissolved gas systems, and thus IGF is the system of choice in the offshore
industry. The 30 Platform Study's analysis of produced water effluents indicated that 23 of the 26
facilities with gas flotation were IGF.
Chemicals are commonly used to aid the flotation process. Chemicals function to create a surface
or a structure that can easily absorb or entrap air bubbles. Inorganic chemicals, such as the aluminum
or ferric salts and activated silica, can be used to bind the paniculate matter and to create a structure that
can easily entrap air bubbles. Various organic chemicals can be used to change the nature of either the
air-liquid interface or the solid-liquid interface, or both. These compounds usually collect on the interface
to bring about the desired changes.
The following sections provide further details about DGF and IGF systems.
5.1.5.1 Dissolved-gas Flotation
In dissolved-gas flotation, water is first saturated with air (gas) either under atmospheric or
elevated pressures, then air is precipitated from the solution by either applying a vacuum (referred to as
vacuum flotation) or an instantaneous reduction in system pressure (referred to as pressure flotation).
Under the reduced air pressure, the air precipitates hi the form of air bubbles which interact with the
dispersed material and carry them to the surface of the liquid. Mechanical flight scrapers are then used
to remove the floated material.
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Since the solubility of air at atmospheric conditions is low and efficiency of the flotation process
is directly proportional to the volume of gas released from solution within the flotation cell, the use of
vacuum flotation is extremely limited. With the pressure flotation method, higher gas solubilities are
possible because of the higher system pressures involved. As a result, larger volumes of gas are released
within the flotation units following a drop in the system pressure resulting in greater overall process
efficiency. In the following discussion, the term "gas flotation" refers to the process of pressure
flotation.9-11
The major components of a conventional gas flotation unit include a centrifugal pump, a retention
tank, and a flotation cell.?0>12 As the first step in the gas flotation process, gas is introduced into the
influent stream at the suction end of a centrifugal pump discharging into a small retention tank. During
this process, the gas is sheared into finely dispersed bubbles which remain in the solution for a ishort
period of time (1 to 3 minutes retention time) in the retention tank. At this point the excess gas
(undissolved air) is purged from the tank. From the retention tank, the saturated water passes through
a backpressure regulator before entering the flotation unit. This regulator facilitates for the necessary
instant pressure drop in the system and creates turbulence* for proper dispersion of gas bubbles. Floe,
which forms as air bubbles interact with the suspended material, is lifted to the surface of the flotation
cell, where it is removed by mechanical skimmers. Suspended material which is not amendable to
flotation is settled, concentrated and removed from the bottom of the flotation cell. Clean water is
collected from the lower part of the cell where there is less turbulence.
5.1.5.2 Induced-gas Flotation
In a basic induced-gas flotation system (also referred to as dispersed-gas flotation), gas is drawn
into the flotation cell either mechanically (mechanical-type) by an impeller or hydraulically (hydraulic-
type) by an eductor into a cell containing the water. The introduced gas is then sheared into finely
dispersed bubbles by a disperser or a rotating impeller. The dispersed gas is interacted with the
suspended solid and liquid particles and floats them to the surface. A skimmer system is used to remove
the floated solids generated by interaction of the air bubbles and dispersed material.
The more advanced induced-gas flotation units are generally multi-cell in design. This feature
provides these systems with improved hydraulic characteristics due to reduced short-circuiting (as
compared to a single-cell design) and sequential contaminant removal. For example, if each cell in a
IX-19
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four-cell unit removes 60 percent of its receiving waste load, the overall removal performance is 97.5
percent; at 70 percent per unit, the overall efficiency of greater than 99 percent is achieved,9
Studies have shown that induced-gas systems produce bubbles that often reach 1,000 microns
(1mm) in diameter. Bubbles from dissolved-gas flotation average between 70 to 90 microns in diameter
and can get as small as 30 microns.13 The larger gas bubbles often cause turbulence in the solution which
could lead to breakdown of the floe, thus reducing the overall system efficiency. This type of problem
has been remedied by proper modifications to existing systems or consideration in the new designs. Such
consideration may include repositioning the diffuser nozzles so that the air is released in the vertical
direction for maximum efficiency and minimum turbulence in the flotation tank.11'"
Some of the main advantages that have made IGF more popular for offshore use include: less
stringent operation and maintenance requirements, lower comparative power requirements, and
adaptability to existing facilities. In addition, because of the larger bubbles produced in this type of unit,
interactions are much faster resulting in shorter required retention time and smaller units. Hence, less
capital cost and space are required.9-11-13
Figure IX-1 presents a schematic drawing of a mechanical-type induced-air gas flotation unit.14
Mechanical-Type Induced Gas Flotation Systems - In this type of gas flotation system, a rotor
with several blades rotates hi the produced water creating a vortex. This creates a negative pressure
which draws gas from the freeboard down a standpipe for dispersion in liquid. The gas is then sheared
into minute bubbles as it passes through a disperser and therefore creates an intimate mixture of liquid
and bubbles. The rotating action of the rotors also causes liquid and solids to circulate upward from the
bottom of the cell and allows it to mix with the incoming waste stream and gas bubbles. The interaction
of oil droplets and gas bubbles occurs in the flotation region of the tank.
A dispenser hood provides a baffling effect which maintains the skim region in a quiescent state.
The rising of bubbles creates a surface flow towards the cell walls, where skimmer paddles are located.
Skim rate is generally a factor of foam characteristics and unit size. Suspended solids that are amendable
to flotation are also removed along with the oil.11-15
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The action of the rotor and dispenser generates relatively large bubbles (up to about 1000 microns
in diameter). Since the size of the bubbles is larger than in dissolve-gas flotation units, greater gas flow
is required by this type of unit to maintain a sufficient bubble population.11
Hydraulic-Type Induced Gas Flotation Systems - Hydraulic-type induced gas flotation units
consist of a feedbox, a series of cells separated by underflow baffles, and a discharge box. A gas eductor
is installed in each cell in a standpipe through which part of the cleaned discharge water is recycled back
to the unit. Gas is drawn into this stand pipe as the result of the venturi effect created by the flow of the
recycled water. The mixing of gas with the recycled water generates small bubbles which defuse and
interact with the dispersed oil droplets in the water. Eductors are often installed at an angle to create a
surface flow to the side where the skimmers and the skim trough are located. The flotation and skimming
processes are similar to those in mechanical-type systems.11
The rate at which gas flows into an eductor is a fanction of recycle rate (eductor pressure), gas
inlet orifice size, and any valve that may have been installed in the gas feed pipe. The gas flow rate and
energy dissipation are the major factors in determining the size of bubbles produced. The recycle flow
rate is generally controlled manually through control valves installed in the recycle line and between the
recycle header and each eductor. The recycle rate is the most important control parameter for optimizing
the performance of hydraulic-type systems. For example, as recycle rate increases, the gas rate increases,
resulting in a decrease hi the initial residence time. This allows for only partial treatment of the influent
water and could result hi short circuiting of the system.11
Hydraulic type units are generally less expensive, are lower hi overall operating cost, and
experience less downtime than other types of gas flotation systems. However, because the gas transfer
per unit volume of water hi this type of unit is significantly lower than hi mechanical-type units,
hydraulic-type units achieve lower removal efficiency than mechanical-type units.11'16
5.1.6 Chemical Treatment
The addition of chemicals to the wastewater stream is an effective means of increasing the
efficiency of treatment systems. Chemicals, are used to improve removal efficiencies in flotation units,
plate coalescers, and gravity separation systems. The three basic types of chemicals that are used to
enhance equipment removal efficiencies in wastewater treatment are:
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Surfactants: Surfactants, also known as surface-active agents or foaming agents, are large organic
molecules mat are slightly soluble in water and cause foaming in wastewater treatment plants and in the
surface waters into which the waste effluent is discharged. Surfactants tend to collect at the air-water
interface. During aeration of wastewater, these compounds collect on the surface of the air bubbles
creating a very stable foam.
Coagulants: Coagulating agents assist the formation of a floe and improve the settling
characteristics of the suspended matter. The most common coagulating agents are aluminum sulfate
(alum) and ferrous sulfate.
Polyelectrolytes: These chemicals are long chain, high molecular weight polymers used to bring
about particle aggregation. Polyelectrolytes act as coagulants to lower the charge of the wastewater
particles, and aid in the formation of interparticle bridging. Depending on whether their charge, when
placed in water, is negative, positive, or neutral, these polyelectrolytes are classified as anipnic, cationic,
and nonionic, respectively.
Surface active agents and polyelectrolytes are the most commonly used'chemicals in wastewater
treatment processes. The chemicals are injected into the wastewater upstream of the treatment unit
without pre-mixing. Serpentine pipes, existing piping arrangements, etc., induce enough turbulence to
evenly disperse these chemicals into the water stream.
5.1.7 Skim Pile
A skim pile is a large diameter pipe attached to the platform extending below the surface of the
water. Typical skim pile dimensions are a length of 70 meters and a diameter of one meter. Skim piles
are vertical gravity separators that remove the portion of oil which quickly and easily separates from
water. Figure IX-2 presents a diagram of a skim pile.
During the period of no flow, oil will rise to the quiescent areas below the underside of inclined
baffle plates where it coalesces. Due to the difference in specific gravity, oil floats upward through oil
risers from baffle to baffle. The oil is collected at the surface and removed by a submerged pump. The
pump operates intermittently and removes the separated liquid to a skimming vessel for further treatment.
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Inlet
Oil Risers
Quiescent Zone
Flowing Zone
Discharge to Ocean
- on :
- Oil and Water
Figure IX-2
Typical Skim Pile
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5.1.8 Reinjection
Subsurface disposal may be used in BPT treatment. Reinjection is generally used for
waterflooding (or in water quality limited areas) which, as a result, meets BPT limitations. Reinjection
is discussed in detail later in Section 5.2.2.
5.2 ADDITIONAL TECHNOLOGIES EVALUATED FOR BAT AND NSPS CONTROL
Several produced water treatment technologies were considered as add-on technologies to the
existing BPT technologies to achieve BAT and NSPS limitations. In particular, EPA evaluated the
following technologies for BAT and NSPS level of control: gas flotation, subsurface reinjection, granular
filtration, crossflow membrane filtration, and activated carbon adsorption. The following sections
describe these technologies in detail.
5.2.1 Improved Performance of Gas Flotation Technology
EPA evaluated the costs and feasibility of improved performance of gas flotation treatment
systems to determine whether more stringent effluent limitations based on this technology would be
appropriate. This technology would consist Of improved operation and maintenance of gas flotation
treatment systems, more operator attention to treatment systems operations, chemical pretreatment to
enhance system effectiveness, and possible resizing of certain treatment system components for increased
treatment efficiency.
The performance of a gas flotation process is highly dependent on the bubble-particle interaction.
The mechanisms of this interaction include: (1) precipitation of the bubbles on the particle surface, (2)
collision between a bubble and a particle, (3) agglomeration of individual particles or a floe structure as
the bubbles rise, and (4) absorption of the bubbles into a floe structure as it forms. These mechanisms
indicate that surface chemistry aspects of flotation play a critical role in improving the performance of
gas flotation. In fact, chemicals have been an integral part of the flotation process for some time.9
Three basic types of chemicals, which are previously discussed in Section 5.1.6, are generally
utilized to improve the efficiency of the gas flotation units used for treatment of offshore produced waiter;
these chemicals are surface active agents, coagulating agents, and polyelectolytes.
Researchers have demonstrated that the addition of chemicals to the water stream, is an effective
means of increasing the efficiencies of gas flotation treatment systems.11-17-18'19 Pearson, 1976, reported
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that the use of coagulants can drastically increase the oil removal efficiency of dissolved-gas flotation
units.12 The addition of alum plus polyelectrolyteto a flotation cell treating refinery wastewater increased
the unit efficiency from 40 percent to 90 percent. Luthy, et al., 1978, also demonstrated the effectiveness
of polyelecttolytes for improving the effluent quality of dissolved-gas flotation units treating refinery
wastewater.20 The addition of chemicals to gas flotation units treating produced water may result in
somewhat different removal efficiencies due to the formation specific chemical characteristics and salinity
of the produced water. Also, removal efficiencies may be different for induced gas flotation (most
common type of gas flotation hi the offshore industry).
Factors related to engineering or mechanical design aspects of the gas flotation systems which
could also affect process performance include: :
(1) Type of gas available or used
(2) Pressure supplied and temperature (DGF)
(3) Type and condition of eductor (IGF)
(4) Rotor speed and submergence (IGF)
(5) Percent recycle (DGF) or rate of recycle (IGF)
(6) Influent characteristics, concentration, and fluctuations
(7) Hydraulic and mass loadings
(8) Chemical conditioning
(9) Type and operation of skimmer.
A review of the design parameters for 32 gas flotation units surveyed by EPA in 1975 revealed
that these units were designed for maximum expected hydraulic loadings. However, none were designed
to handle mass overload conditions which may occur during start-up, process malfunctions, or poor
operating practices. The survey also indicated that those systems that were properly designed,
maintained, and operated had excellent performance. Produced water effluent oil concentrations from
these systems averaged less than 25 mg/1.19
The limitations representing the best practicable control technology (BPT) for treatment of
offshore produced water (determined by EPA based on the analysis of 138 systems) are based on the
following technologies: (1) equalization or surge tanks to provide a steady influent to the treatment system
and to prevent overloading of the system, (2) solids removal (desanders) to remove undesirable solids that
could clog-up the treatment units and damage the equipment, (3) chemical addition (feed pumps) to
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enhance the system's performance, and gas flotation for oU removal. A great majority of the existing
units either have this capability or could be modified. Most modifications are simple and could utilize
the existing tankage and equipment with minimal costs. For example, according to a case study
conducted by Rochford, 1986, an inadequately designed induced gas flotation system operating in North
Sea was successfully modified to operate as a dissolved gas flotation with minimal capital cost.21 The IGF
unit was not designed to treat produced water with very small oil droplets (5 to 40 microns), thus
achieving only 30 percent removal efficiency. The modified system simplified the equipment required
for conventional DGF systems by utilizing the existing tanks and the dissolved gas already present in the
produced water. The new system efficiency ranged between 70 to 80 percent.
In general, gas flotation systems may have removal efficiencies of 90 to 95 percent.13 With
proper operation, chemical addition, and low suspended solids concentration, a mechanical-type IGF
system can consistently achieve oil removal efficiencies greater than 90 percent, even when operating at
capacities beyond the design flowrates. Some older and larger size hydraulic-type IGF systems using one
eductor per cell have not demonstrated the capability to consistently exceed 90 percent oil removal
efficiency at one minute residence time per cell. However, the newer designs which have employed
multiple eductors in each cell, more cells for the same volume, a means of ensuring smaller bubbles, and
superior baffle design give comparable performance to mechanical-type units. As a general design rule,
gas flotation units used, for treating oily water should have a large drain piping system, at least 4-inches
in diameter, to prevent foam plugging. Also, adequate surge capacity is necessary upstream of IGF units
to protect the system from oil "slugs," eliminate flowrate surges, and to remove suspended solids.11
5,2.2 Reinjection
Disposal of produced water by reinjection into a subsurface geological formation can serve the
following purposes:
Provide zero discharge of wastewater pollutants to surface waters.
Increase hydrocarbon recovery by flooding or pressurizing the oil bearing strata.
Stabilize (support) geologic formations which settle during oil and gas extraction (a
significant problem for older, i.e onshore, more depleted reserves).
Onshore produced water reinjection is a well-established practice for disposal of produced water.
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As part of the rulemaking process, and in response to industry concerns about the feasibility of
reinjection due to the receiving formation characteristics, EPA evaluated the technical feasibility of
implementing this technology at both existing and new offshore platforms.22 The study showed that
reinjection is generally technologically feasible in all offshore areas, i.e. suitable formations and
conditions are available for disposal operations. However, some locations may experience problems in
being able to reinject due to site-specific formation characteristics or proximity to seismically active areas.
The following sections present information on the reinjection technology as a means to control
produced water discharges.
5.2.2.1 Industrial Practices
Most of the produced water generated offshore California is presently reinjected to enable
recovery of the heavy crude oil that is typically produced in that part of the country. However, in the
Gulf of Mexico, most produced water generated offshore is treated to the BPT limitations and discharged
to the surface waters. Onshore reinjection experiences in Texas and Louisiana have shown that the
characteristics of the regional geology make it possible to reinject produced water onshore. EPA also
believes that it is generally possible to reinject produced water in areas that EPA recognizes as offshore.
The only EPA-defined offshore facility hi Alaska, which is located on a gravel island in the
Beaufort Sea, reinjects all of its produced water. In other coastal areas of Alaska, this technical issue
has not yet been specifically evaluated. At an onshore facility at Trading Bay, a technical evaluation of
the formation's geological suitability for reinjection indicated that the formation was highly faulted and
that compartinentalization is likely, thus reducing the capacity of the formation for use hi receiving
injected fluids to approximately two years. Other evaluations on the feasibility of reinjecting produced
water have been limited to economic issues.23
5.2.2.2 Well Selection and Availability
Many of the requirements in the planning, design, and operation of the produced water reinjection
system are the same whether the location is onshore or offshore. These include important design
considerations such as selection of a receiving formation, preparation of an injection well, and choice of
equipment and materials. Significant operational parameters include scaling, corrosion, incompatibility
with the receiving stratum, and bacterial fouling.
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Selection of the receiving formation should be based on geologic as well as hydrologic factors.
These factors determine the injection capacity of the formation and the chemical compatibility of the
injected produced water with the water within the formation. The most important regional geologic
characteristics of a disposal formation are areal extent and thickness, continuity, and lithological
character. This information can be obtained or estimated from core analysis, examination of bit cuttings,
drill stem test data, well logs, driller's logs, and injection tests.
The desirable characteristics for a produced water 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 (2) solution vugs and fracture channels. Formations with intergranular openings
are usually made up of sandstone, limestone, and dolomite formations and often have vugulur or cavity-
type porosity. Limestone, dolomite, and shale formations may be naturally fractured. Formations with
fracture channels are often preferable for produced water disposal because fracture channels are relatively
large in comparison to intergranular openings. These larger channels may allow for fluids with high
concentrations of suspended solids to be injected into the receiving formation under minimum pumping
pressure and minimal pretreatment.
A formation with a large areal extent is desirable for disposal purposes because the fluids within
the disposal formation must be displaced to make room for the incoming fluids. An estimate of the aireal
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 im 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.1 Abandoned producing
formations are ideal for disposal because the original fluids were trapped in the formation. Fluids
reinjected into those formations also will be trapped and will not migrate into other areas.
IX-29
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5.2.2.2.1 Possible Concerns
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.22 Depending
upon local stratigraphy and the type and amount of fault displacement, one of three possible conditions
can occur. Displacement along the fault may either: (1) limit the area available for disposal; (2) place
a different permeable formation opposite the disposal formation which could allow fluids to migrate to
unintended locations; or (3) the fault itself may act as a conduit, allowing injected fluids to flow along
the fault plane either back to the surface or to permeable formations at a shallower depth than the disposal
formation. Either the second or third possibility has the potential to create a pollution problem by
contaminating underground sources of drinking water.
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.22 Such movement can create seismic activity in the area. The city of Denver, Colorado placed
a disposal well near the Rocky Mountain Arsenal and pumped city waste water down the well. The well
bottom was in the vicinity of a fault. Subsequent analysis showed a direct correlation between the
number of microseisms hi the Denver area and well pumping tunes and rates. Increased pumping caused
a corresponding increase hi the number of microseisms.
5.2.2.2.2 Well Design
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 be 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, adequate equipment and storage
space must be provided at the facilities.
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5.2.2.2.3 Regional Geological Considerations
California
There is little question about the technical feasibility of reinjecting produced water at the existing
facilities offshore California because the current practice of this technology is common. In the offshore
subcategory for California, all of the produced water are reinjected for the sole purpose of enhanced
recovery by waterflooding. Reinjection of produced water is not practiced in areas where there is
potential for seismic activity. The offshore geological conditions and engineering requirements for the
reinjection of brines from new sources in areas expected to be open for oil and gas development and
production, i.e., free of seismic activity, are expected to be essentially the same as for existing sources.
Consistent with the past and present industry practices, suitable disposal formations with adequate
permeability, porosity, thickness, and areal extent are expected to be available. Similarly, constructability
and trouble-free operation of reinjection wells, availability of offshore pretreatment technologies, and the
transport and onshore disposal of solids and sludges from new sources pose no additional technical
problems beyond those currently encountered due to the reinjection of brines from existing sources.
Gulf of Mexico
In the Gulf of Mexico, reinjection of brines from existing offshore sources is not practiced to any
appreciable extent. The current practice is to treat the brines to the BPT effluent limitations and
discharge overboard. Waterflood projects are not common in the Gulf of Mexico; it is estimated that
less than ten facilities in the Gulf of Mexico reinject produced water for pressure maintenance.2'1 The
primary reason that waterflooding is not common offshore is because, unlike California, extraction of the
formation fluids from the reservoirs in the Gulf of Mexico does not require the additional water drive
provided by waterflooding. Secondly, economics prevent secondary recovery operations hi the Gulf of
Mexico. The additional oil recovered due to waterflood is not worth the cost of the reinjection operation.
An effective waterflood program requires several wells, since waterflooding operations often push the
oil zone up and horizontally direct the movement of the zone to the production well. "Textbook"
waterflooding operations utilize a five spot pattern to properly manage the flow of the oil zone. A five
spot pattern consists of four injection wells surrounding the production well, typically hi a square pattern.
Through the control of injection water from the four wells, the oil zone can be directed to the area where
the production well is located. This type of waterflooding program is very expensive in offshore
operations since several directionally drilled wells are required.25
IX-31
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Reinjection of brines from existing and new sources in the Gulf of Mexico also depends OB the
availability of an adequate number of suitable disposal formations. In the early stages of production,
there will be little need for reinjection fluids to enhance recovery and, therefore, the produced water
would be reinjected only for disposal purposes. The onshore reinjection experience in Texas and
Louisiana has shown that reinjection of produced water is possible where there are suitable disposable
formations available. Consistent with the onshore experience, there may be instances where a suitable
disposal formation may not be available.
5.2.2.2.4 Technical Exceptions ...'..,..
Reinjection into producing formations is not extensively practiced offshore along the Gulf Coast
because of potential problems that waterflooding can cause by adversely changing the field pressure.22
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 the wellbore.
Increased pressure can also cause movement of the formation fluid containing the oil and gas away from
the wellbore. These movements may result in reduced production. Because each production area has
its own unique set of conditions, each site must be individually evaluated for potential problems that may
arise from reinjection into a producing formation.
Other sources indicate that although it is theoretically possible to reinject produced water into
subsurface formations, the consequences of injecting large quantities of produced water are impossible
to determine, and the potential impacts are significant. Approximately 1 billion barrels of produced water
are generated annually hi the offshore subcategory. Since many formations in the Gulf are small, tightly
packed, and have relatively low permeability and porosity, one resulting problem could be fracturing and
eventual flow of the produced water back to the surface, through the ocean floor, and/or flow to a fresh
water aquifer. Another consideration is that because of the formation characteristics in the Gulf, the
produced water will require very intensive pretreatment to remove the solids.
5.2.2.3 Pretreatment of Produced Water Prior to Reinjection
Pretreatment of produced water may be necessary to prevent scaling, corrosion, precipitation, and
fouling from solids and bacterial slimes. Corrosion and scale deposits lead to decreased equipment
performance and to plugging hi the underground formation. One method to overcome this problem is
to increase reinjection pressures. However, excessive injection pressure may fracture the receiving
formation causing the escape of produced water into freshwater or other mineral bearing formations.
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Also, additional energy (fuel) is necessary to obtain the higher discharge pressures and consequently
results in increased air emissions.
* Offshore treatment systems are classified as closed systems which operate in the absence of air.
This alleviates the problems arising from oxygen induced corrosion, scaling, and chemical precipitation.
In a closed system, a blanket of natural gas is maintained over the produced water in pipelines and tanks.
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Pretreatment for injection includes gravity separation, gas flotation, and/or filtration. This level
of pretreatment is generally more elaborate than the current pretreatment practices hi the Gulf of Mexico
where produced water is treated and discharged to the surface waters. Space requirements or the
reliability of the pretreatment technology pose no additional problems beyond those encountered offshore
of California where the same level of pretreatment is currently practiced prior to reinjection. However,
the facilities in California were originally designed to include the additional equipment required for
pretreatment and reinjection. .
5.2.3 Granular Filtration
Granular media filtration involves the passage of water through a bed of filter media to remove
solids. The filter media can be single, dual, or multi-media beds. When the ability of the bed to remove
suspended solids becomes impaired, cleaning through backwashing is necessary to restore operating head
and effluent quality. There are a number of variations in filter design systems. These include: (1) the
direction of flow: downflow, upflow, or biflow; (2) types of filter beds: single, dual, or multi-media;
(3) the driving force: gravity or pressure; and (4) the method of flow rate control: constant-rate or
variable-declining-rate.26 Figure IX-3 shows the schematic of a multi-media granular filter.
Filtration is widely used for produced water treatment at onshore facilities throughout the United
States, as well as at some offshore facilities located in California state waters. The filters are used as a
polishing step for the removal of suspended solids following the oil separation processes. High levels
of treatment which include filtration are generally utilized to improve the injection characteristics of
produced water,26
The three-facility study evaluated granular filtration systems designed to pretreat produced water
following oil separation and prior to reinjection. These particular operations inject produced water either
because of a zero discharge permit requirement or for enhanced oil recovery. The three facilities
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2' 6" Anthracite
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Figure IX-3
Multi-Media Granular Filter
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evaluated were: Conoco's Maljamar Oil Field near Hobbs, New Mexico; Shell Western E&P, Inc. - Beta
Complex off Long Beach, California; and the Long Beach Unit - Island Grissom which is owned by the
City of Long Beach, California, and operated by THUMS Long Beach Company.
At the THUMS facility, approximately 90,000 barrels per day (bbl/day) of produced water are
treated. To provide sufficient water for reinjection purposes, approximately 28,000 bbl/day of make-up
water is added to produced water prior to reinjection. Produced water is first treated to remove oil in
a series of free water knockouts (FWKOs) and clarifiers. Water from the clarifiers is passed through a
series of dispersed gas flotation units and ultra-high-rate multi-media granular filters. There are three
filters operating in parallel and a fourth is used as a spare during the backwash cycles. The filters operate
in a downflow configuration and the filtering media consists of (from top to bottom): a layer of crushed
anthracite (effective size 6-4 mm), a layer of Number 3 sand, and a layer of stratified rock. Oil removed
in the treatment system is further treated in the API skim tank. Prior to filtration, coagulant and
demulsifier chemicals are added to the water.
At the New Mexico facility, approximately 21,000 bbl/day of produced water are treated. To
provide sufficient water for reinjection purposes, approximately 4,000 bbl/day of fresh water is added
to the produced water before filtration, requiring the filters to handle approximately 25,000 bbl/day of
water. There are three upflow sand filters operating in parallel. Prior to filtration, corrosion inhibitor,
coagulant, and flocculent aid chemicals are added to the water to enhance separation.
At Shell Western-Beta Complex, approximately 10,000 bbl/day of produced water are treated.
To provide sufficient water for reinjection purposes, approximately 28,000 bbl/day of de-gasified make-up
water is added to the produced water. Produced water is fed to a skim tank for oil-water separation.
Water flows from the skim tank by gravity to a flotation unit. Prior to the flotation unit, a chemical
coagulant is injected into the produced water stream. Following flotation, water is pumped to two multi-
media filters operating in parallel, one additional filter is on stand-by mode and used during backwash
cycles. The filters are the same as those described for the THUMS facility, however, there is no
chemical addition at the filtration unit to aid in the separation process. Filtered water is gravity fed to
an injection surge tank where it is mixed with make-up water. Water from this tank is partially pumped
through cartridge filters and reinjected, and partially pumped to the backwash water storage tank.
EPA statistically analyzed the data from these facilities to determine effluent levels achievable
from add-on granular media filtration technology. Table IX-16 presents the performance of granular
IX-35
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TABLE IX-16
GRANULAR MEDIA FILTRATION PERFORMANCE27
-
Thums Long Beach
(With Chemical Addition)
Filter Influent
Filter Effluent
% Removal
Conoco, Hobbs
(With Chemical Addition)
Filter Influent
Filter Effluent
% Removal
TSS (mg/If
43.27
25.65
40.7%
102.84
48.77
53%
O&G (mg/ir
:
20.75 \
11.22
46%
34.54
10.90
68%
*TSS concentrations represent flow weighted averages of paired samples for each day of
sampling.
**Composite sample concentrations estimated by the arithmetic average of sample
concentrations within a day.
media filtration for oil and grease (O&G) and TSS, based on calculated daily composites. Granular
filtration has demonstrated good removals of TSS and oil and grease at the two facilities using chemical
coagulants and flocculatants to enhance separation, thus improving filtration performance.
5.2.4 Crossflow Membrane Filtration ;
Crossflow membrane filtration is an ultrafiltration process. The process operates at low
pressures, less than 100 pounds per square inch (psi). The membrane pore sizes range from 0.03 to 0.8
micrometers. Crossflow filtration minimizes the accumulation of particulates on the surface of the
membrane by flowing the feed stream over the surface of the membrane to sweep away part of the
accumulated layer on the membrane. Figure IX-4 presents the flow dynamics of a crossflow filter.
Crossflow filtration requires recirculation of the process stream that may be several orders of magnitude
greater than the rate of filtration. The advantage of crossflow filtration is that the membrane's life and
periods between cleaning cycles are extended through constant membrane scouring by the particulates hi
the produced water stream.28 In addition to the high velocities of produced water across the membrane
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surface to prevent membrane fouling, some systems utilize a backflow of permeate (i.e., filter effluent)
through the membrane to dislodge any oil or solid particles embedded within the pores of the membrane.
Several types of crossflow membrane filters have been pilot or field tested for the treatment of
produced water. The two common types of membrane materials are an inorganic ceramic material and
an organic polymeric material. Membrane module designs include hollow fiber, spiral wound, and
tubular. Many systems require either pre-filtration or chemical treatment to prevent rapid membrane
fouling and flux degradation. For flux restoration, some systems utilize on-line membrane cleaning, such
as backpulsing, while others require system shutdown and physical cleaning of the membrane.
One type of crossflow membrane filtration system is currently being operated on two different
platforms located in the Gulf of Mexico. One is a 150 barrel per day pilot scale unit and the other is a
5,000 barrel per day full scale unit processing a partial stream (slip stream) of the produced water for
waterflood injection purposes.29 The ceramic membranes used in these filtration modules are made of
porous alumina. Each module contains up to 36 ceramic elements. The bulk of the ceramic element is
a ceramic monolithic support containing 12 micrometer pores. Each element contains 19 channels
arranged in a honeycomb configuration, which are stratified with alumina ceramic layers that are bonded
to the monolithic support. These alumina layers have a pore size of 0.8 microns. Figure IX-5 presents
a cross section of a ceramic element. The produced water flows axially through each channel and radially
permeates through the membrane layer and supporting structure.
The produced water stream is chemically pretreated with ferric chloride. Through a hydrolysis
reaction between the produced water and ferric chloride, a ferric hydroxide floe is formed. The ferric
hydroxide floe develops a precoat layer on the surface of the membrane and serves as a "dynamic
membrane." This "dynamic membrane" is unique to this system and allows water to permeate through
the ceramic membrane while reducing the rate of accumulation of oil and oil wet solids on the membrane
surface. The backpulse cycle serves to constantly replace the "dynamic membrane" with a fresh ferric
hydroxide floe precoat. However, the "dynamic membrane" does not completely prevent the membrane
from fouling. When backpulsing does not restore the permeate flux rates, shutdown of the system is
necessary for chemical cleaning.30
In 1991, EPA conducted a week long sampling episode of the full scale unit described in the
preceding paragraphs. Data obtained from this sampling effort indicate that the total oil and grease of
the effluent can be as low as 3.5 mg/1 with an influent oil and grease concentration of 22 mg/1. The
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sampling program also analyzed the filtration process for removal efficiencies and potential concentration
of TSS, organic compounds, metals, and radionuclides. Table IX-17 presents data obtained from the
sampling program.
Despite the potential of high pollutant removal efficiencies, widespread use of crossflow
membrane filtration for the treatment of produced water has been hampered by operational problems, due
to membrane fouling, experienced by several of the pilot and full scale units, including the unit studied
in the 1991 EPA sampling program. The unit evaluated was being operated at 20 percent of the design
capacity due to a barium sulfate scale build-up on the membrane surface.
The filtration unit was also bypassed several times during the sampling program due to upsets in
the produced water treatment system. The unit was bypassed as a preventative measure to avoid sending
water with a relatively high oil and solids content to the filter. The membrane pores can be easily
plugged during high loadings of oil and solids. If the membrane pores become oil wet or plugged with
solids, significant flux reduction results and shutdown of the filter is necessary for chemical cleaning.
The operator was also experiencing problems with the waste streams generated from the filtration process.
The major waste streams generated by the unit include: the only float skimmed at the feed tank surface,
the solids concentrate blowdown stream, and the spent acid and caustic used for filter cleaning. The
wastes are currently recycled into the produced water treatment system or neutralized and discharged
overboard. The wastes being recycled into the produced water treatment system are creating upsets in
the chemical equilibrium of the system. The operator indicated that a larger filtration unit would generate
greater volumes of waste which would be difficult to recycle into the produced water treatment system
without causing significant upsets and be costly to dispose of onshore.32
Also in response to the 1991 proposal, EPA received bench, pilot, and full scale analytical and
operating data from several vendors of crossflow membrane filters. The commenters submitted data and
information on several field tests processing produced water at locations in the Gulf of Mexico, Kansas,
Alaska, California, Canada, and the North Sea. All of the analytical data indicated high removal
efficiencies for oil and grease and total suspended solids. This information is presented in a literature
study titled "Crossflow Membrane Separation System Study."30
The only other full scale crossflow membrane filtration unit that EPA is aware of is a ceramic
membrane operating in the Valhalla field located in northeastern Alberta, Canada.33 The unit has a rated
design capacity of 6,000 barrels per day and is processing a combined produced water and ground water
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TABLE IX-17
MEMBRANE FILTRATION PERFORMANCE DATA FROM THE MEMBRANE
FILTRATION STUDY31
Pollutant Parameter
Oil & Grease
Freon
Hexane
Total Petroleum Hydrocarbon
TSS
Priority and Non-conventional
Organic Pollutants:
Benzene
Benzole acid
Biphenyl
Chlorobentene
Ethylbenzene
Hexanoic Acid
Methylene Chloride
Naphabene
o,p-Xylene
Phenol
Toluene
2-Butanone
2-Propanone
Priority and Non-conventional
Metal Pollutants:
Aluminum
Antimony
Arsenic
Barium
Boron
Copper
Iron
Lead
Magnesium (mg/1)
Manganese
Strontium (mg/1)
Titanium
Yttrium
Zinc
Radkmuciides:
Gross Beta (pCi/1)
Radium 226 (pCi/1)
Radium 228 (pCi/1)
Influent 0*g/l)
MIN*
16.33
8.0
16.33
, 67.0
738.38
51
10
10
62.6
10
10
10
34.15
10
438.4
180.4
50
875
3
165
92,150
6,950
30
24,300
150
2,280
1,440
181
9
9
24
296.0
381.0
511.8
MAX*
42.67
21.67
42.67
86.0
1,050.32
84.83
557.41
16.5
114.3
14.4
148.3
29.6
83.4
53.4
650.5
1,206.0
1,901.1
.2,270
617
211
135,220
8,050
31
28,800
530
2,495
1,965
224
12
14
38
442.5
643.0
863.6
MED*
19.67
11.0
19.67
82.0
925.35
67.82
10
11.78
90.1
10
83.2
17.8
53.7
10
556.7
282.0
1,004.3
1,660
30
187
130,000
7,620
30
27,500
150
2,450
1,960
218
9
9
25
328.0
484.0
604.3
Effluent 0*g/l)
MIN*
3
3.0
3.0
86.0
441.5
50.0
10
10
10
10
10
10
31.0
10
445.9 "
182.1
50
343
30
127
90,250
6,790
30
26,100
150
2,280
1,910
202
9
9
24
296.0
521.0
130.4
MAX*
7.67
6.33
7.67
97
958.9
50.4
10
15
77.2
47.2
138.7
21.5
47.3
66.1
607.1
2,610.2
2,686.1
1,351
4,200
256
142,000
7,830
30
28,450
314
2,495
2,325
226
17
17
45
390.5
616
868.3
MED*
4.67
3.33
4.67
97
860.0
50.0
10
10
61.8
10
10
13.1
35.4
10
517.5
305.8
1,215.2
1,100
264
160
128,000
7,570
30
26,900
212
2,460
2,265
216.5
9
9
28
304
583.0
579.7
*Pollutant Concentration "Minimum Level" Values were Substituted for Non-detect Samples
NR=Not Reported
IX-41
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stream for pretreatment prior to reinfection. The system was installed the fourth quarter of 1990 and until
1992 had not been in continuous operation. The system was frequently shut down due to membrane
fouling problems. However, recent design changes have improved its ability to operate continuously
without membrane fouling. \
5.2.5 Activated Carbon Adsorption
Activated carbon is a material which selectively removes organic contaminants from wastewater
by adsorption. Activated carbon can be used both as an in-plant process for the recovery of organics and
as an end-of-pipe treatment for the removal of dilute concentrations of organics from wastewater prior
to discharge or recycle. Key design parameters for an activated carbon unit include the quantity and
quality of wastewater to be treated, the required effluent quality, type and quantity of activated carbon,
the empty bed contact time, and the breakthrough capacity before regeneration is necessary.
Generally, activated carbon systems are preceded by treatment systems such as chemical treatment
or filtration to remove the suspended solids and any other materials which might be present in the
wastewater and which interfere with the adsorption phenomenon. Presently^ activated carbon is not
generally used hi the treatment of produced water from oil and gas wells.
EPA determined that carbon adsorption is not technologically available to implement as a basis
for BAT or NSPS limitations for the treatment of produced water from offshore oil and gas production.
This is because of the lack of treatability information related to the effects of the brine-like nature of
produced water on the adsorption process, either from literature or from pilot or full-scale studies.
I*1
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6.0 REFERENCES
I
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1.
2.
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6.
7.
8.
9.
10.
11.
12.
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.
"Oil and Gas Extraction Industry, Evaluation of Analytical Data Obtained from the Gulf of
Mexico Sampling Program," Vol. 1, Discussion, prepared by Burns and Roe Industrial Services
Corp., prepared for USEPA, Effluent Guidelines Division, January 1983, Revised February
1983. J
Lysyj, I., and M.A. Curran, "Priority Pollutants in Offshore Produced Oil Brines," Rockwell
International, Environmental Monitoring and Services Center and USEPA, Industrial
Environmental Research Laboratory, November 1982.
Memorandum from D. Ruddy, Industrial Technology Division, to A. Tarnay, Assessment and
Watershed Protection Division, "Offshore Oil and Gas Extraction Revised Produced Water BPT
Baseline Pollutant Levels," October 24, 1989. (Offshore Rulemaking Record Volume 120)
SAIC, "Produced Water Pollutant Variability Factors and Filtration Efficacy Assessments From
title Three Facility Oil and Gas Study," prepared for Industrial Technology Division U S
Environmental Protection Agency, March 1991. (Offshore Rulemaking Record Volume 12O)
Envirosphere Company, Summary Report: Cook Inlet Discharge Monitoring Studv: Produced
Witer, Discharges Number 016, prepared for the Anchorage Alaska Offices of Amoco
Production Company, ARCO Alaska, Inc., Marathon Oil Company, Phillips Petroleum
Company, Shell Western E&P, Inc., Unocal Corporation, and U.S. Environmental Protection
Agency, Region 10, September 1988 through August 1989. (Offshore Rulemaking Record
Volume 120)
SAIC, "Analysis of Oil and Grease Data Associated with Treatment of Produced Water by Gas
Flotation Technology," prepared for Engineering and Analysis Division, Office of Science and
Technology, U.S. Environmental Protection Agency, January 13, 1993.
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. J
Churchill, R.L., "A Critical Analysis of Flotation Performance," American Institute of Chemical
Engineers, 290-299, (1978).
Sport, M.C., "Design and Operation of Dissolved-Gas Flotation Equipment for the Treatment
of Oilfield Produced Brines," Journal of Petroleum Technology, 918-921, (1970).
Leech, C.A., "Oil Flotation Processes for Cleaning Oil Field Produced Water," Shell Offshore
Inc., Bakersfield, Ca., (1987).
Pearson, S.C., "Factors Influencing Oil Removal Efficiency in Dissolved Air Flotation Units "
4th Annual Industrial Pollution Conference, Houston, Texas, (1976).
IX-43
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13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
:
23.
24.
25.
26.
27.
!
Kumar, I.J., "Flotation Processes," Lenox Institute for Research Inc., Lenox, Mass., (1988).
Paragon Engineering Services, Houston Texas.
Arnold, K.E., "Equipment and Systems Used to Separate Oil From Produced Water on Offshore
Platforms," Paragon Engineering Services, Inc., Houston, Texas, (1987).
Krofta, M., et al., "Development of Low-Cost Flotation technology and systems for Wastewater
Treatment," Proceedings 42nd Industrial Waste Conference, 1987, Purdue University, Lewis
publishers, Chelsea, MI, (1988).
Brown and Root, Inc., "Determination of Best Practicable Control Technology Currently
Available to Remove Oil and Gas," prepared for Sheen Technical Subcommittee, Offshore
Operators Committee, New Orleans, (March 1974).
Lysyj, I., et al., "Effectiveness of Offshore Produced Water Treatment," API et al;, Oil Spill
prevention, Behavior Control and Clean-up Conference (Atlanta, GA) Proceedings, (March
1981).
Wyer, R.H., et al., "Evaluation of Wastewater Treatment Technology for Offshore Oil
Production Facilities," Offshore Technology Conference, Dallas, Texas, (1975).
Luthy, R.C., "Removal of Emulsified Oil with Organic Coagulants and Dissolved Air Flotation,"
Journal Water Pollution Control Federation. (1978), 331-346.
Rochford, D.B., "Oily Water Using Gas Flotation," Offshore Technology Conference, OTC
5247, (1986).
ERCE, "An Evaluation of Technical Exceptions for Brine Reinjection for the Offshore Oil and
Gas Industry," prepared for Industrial Technology Division, U.S. Environmental Protection
Agency, January 1990. (Offshore Rulemaking Record Volume 119)
Alaska Oil and Gas Association (AOGA), "Comments on USEPA 40 CFR Part 435 Oil and Gas
Extraction Point Source Category, Offshore Subcategory, Effluent Limitations Guidelines and
New Source Performance Standards, Proposed Rule," May 19, 1991. (Offshore RulemaMng
Record Volume 138)
Maurice Stewart, Minerals Management Service, New Orleans Office, personal communication
with Joe Dawley, SAIC, regarding reinjection of produced water in the Gulf of Mexico. May 8,
1992.
Ed Peterson, AMOCO Oil Company, Houston Texas, personal communication with Joe Dawley,
SAIC, regarding reinjection of produced water in the Gulf of Mexico. March 20, 1992.
Burns & Roe Industrial Services Corporation, "The Use of Filtration for Produced Water
Treatment," prepared for Effluent Guidelines Division, U.S. Environmental Protection Agency,
December 2, 1982.
SAIC, "Engineering Report on Granular Filtration Based on the Three Facility Study," prepared
for the Engineering and Analysis Division, U.S. Environmental Protection Agency, June 1992.
"I
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IX-44
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28.
29.
30.
31.
32.
33.
34.
Schweitzer, Philip,A., "Handbook of Separation Techniques for Chemical Engineers," Second
Edition, McGraw-Hill Book Co., New York. Chapter 2. (1988)
Yang, J.C., Meyer, J.P., "Industry's Field Experience With Membrane Filtration Technology,"
June, 1991. Submitted as comments to 56 FR 10664 by Craig W. Gordy, Marathon Oil
Company, June 10, 1991. Commenter number 50, Volume 147 ofRulemaking Record.
Offshore Operators Committee, "Crossflow Membrane Separation Systems Study," prepared by
Parag6n Engineering Services, project No. 90421, December, 1990. Submitted as comments to
56FR 10664 by C.T. Sawyer, American Petroleum Institute, Volume 2, Tab 1, May 13, 1991.
Commenter number 42, Volume 142 ofRulemaking Record.
SAIC, "Produced Water Pollutant Variability Factors and Filtration Efficacy Assessments from
the Membrane Filtration Oil and Gas Study," prepared for Engineering and Analysis Division,
Office of Science and Technology, U.S. Environmental Protection Agency, January 13, 1993.
SAIC, "Trip Report for the Sampling of the Membrane Filtration Unit at the Marathon Oil Co. -
Eugene Island 349-B Platform," prepared for Engineering and Analysis Division, U.S.
Environmental Protection Agency, January 13, 1993.
Terry Bullen, Petro Canada, Alberta, Canada, personal communication with Joe Dawley, SAIC,
regarding the ceramic membrane filtration unit operating at the Valhalla Field. September 9
1992.
Memorandum from C. White, Engineering and Analysis Division, to M". Rubin, Engineering and
Analysis Division, U.S. Environmental Protection Agency, "Long-Term Averages for Analyte
Concentrations hi the Proposed Offshore Oil and Gas Regulations," September 20, 1989.
JX-45
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unconsolidated sand fonnations.1 Produced sand is considered a solid and consists primarily of sand and
clay with varying amounts of mineral scale (epsom salts, magnesite, gypsum, calcite, barite, and celestite)
and corrosion products (ferrous carbonate and ferrous sulfide).2
Produced sand is carried from the reservoir to the surface by the fluids produced from the well.
The well fluids stream consists of hydrocarbons (oil or gas), water, and sand. At the surface, the
production fluids are processed to segregate the specific components. The produced sand drops out of
the well fluids stream during the separation process due to the force of gravity as the velocity of the
stream is decreased during passage through the treatment vessels. The sand accumulates at low points
in the equipment and is removed periodically through sand drains, manually during equipment shut-downs
for cleaning, or by periodic blowdowns as a wet sludge containing both water and oil.3 One source
indicates that desanders or desilters (hydrocyclones) are used to remove sand if the volume produced is
high.2 However, the Offshore Operators Committee (OOC) indicates that sand removal is primarily by
tank cleanouts and that desanders are seldom used. Equipment is typically cleaned on a three to five year
cycle. At some locations, sand is collected on a yearly basis because large volumes of sand are being
generated due to failure of downhole sand control measures.4 Sand removal by blowdown through valves
installed on tank and equipment accounts for approximately 10 percent of all sand generated at offshore
facilities.4
2.2 PRODUCED SAND VOLUMES
The generation rate of produced sand will vary between wells and is a function of the: amount
of total fluid produced, location of the well, type of formation, production rate and completion methods.2'3
Oil producing reservoirs will typically generate more produced sand than gas producing reservoirs. This
is because oil is more viscous than gas and the oil will carry the sand more easily than gas. Another
reason is because gas producing wells have sensors that detect sand flowing with the gas stream to
prevent erosion on the production equipment due to sand flowing with the gas at high velocities.5
In 1989, a survey of operators hi the Gulf of Mexico was conducted by the OOC that compiled
data on produced sand discharges from 330 sites operated by thirteen different companies.4 Table X-l
presents a summary of the data collected in the survey. The information collected for each site includes:
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1 1
1 1
TABLE X-l
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SUMMARY OF RESULTS OF OOC PRODUCED SAND SURVEY4 1
Total Number of Sites Included in the Survey
Number of Sites Collecting Produced Sand for the Survey Year
Number of Sites Discharging Only to Sea
Number of Sites Hauling Only to Shore
Number of Sites Hauling to Shore and Discharging to Sea
Number of Sites reporting No Produced Sand Generation
Maximum Discharge of Produced Sand Per Site
Maximum Haul of Produced Sand Per Site
Average Discharge of Produced Sand
Average Haul of Produced Sand
330
143
21
115
7
63
12,565 fobl
1,508 blbl
1,136 bbl
HObbl
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The amount of produced sand discharged (barrels)
The amount of produced sand hauled to shore (barrels)
The amount of produced water generated (barrels).
Since produced sand is not collected from process equipment every year, the survey only
represents a snapshot of produced sand collection for a given year. Forty-three percent (43%) of the
facilities surveyed indicated no discharging or hauling of produced sand .in 1989. This does not indicate
that these facilities did not generate any produced sand that year. It indicates that either these facilities
did not generate any produced sand or no produced sand was collected from the process equipment for
that year. Several years of data in this format would be necessary to draw any conclusions about yearly
produced sand generation rates.
The OOC survey indicates that less than half of the sites surveyed discharged produced sand in
1989. Of the sites discharging produced sand, 15 percent discharged to the surface waters, 80 percent
hauled to shore and 5 percent hauled to shore and discharged to the surface waters. The total sand
production from the 143 sites discharging sand was 41,627 barrels, which equals approximately 291
barrels discharged per site. Of this volume, 28,403 barrels (68%) were discharged to the surface waters
and 13,229 barrels (32%) were hauled to shore.
X-3
-------
Several facilities in the survey reported over one-thousand barrels of produced sand discharged
to the surface waters and one facility accounted for forty-four percent (12,565 barrels) of all produced
sand reported to be discharged to the receiving waters (28,403 barrels). EPA considers these volumes
extremely high when compared with the other reported collection volumes in the survey. A follow-up
telephone conversation with one operator indicated that one of the facilities reporting over 4,000 barrels
of produced sand discharged hi 1989 produces about 100 barrels of sand a year (at this annual generation
rate, it would take 40 years to generate this volume). The operator indicated that another facility
generates sand continuously at a rate of approximately 5 barrels per day.6 However, no specific reasons
were provided that explained the large volumes of sand.
2.3 PRODUCED. SAND CHARACTERIZATION
Produced sand is generally contaminated with crude oil from oil production or condensate from
gas production. The primary contaminant associated with produced sand is oil.7 The oil content of
unwashed produced sand can range from a trace (expected in sand from blowdown) to as much as 15
percent by volume.8
In 1991, Shell Offshore, Inc. conducted a produced sand washing study. The study evaluated
produced sand that was generated at a facility located in the Mississippi Canyon Area (Gulf of Mexico
OCS) and washed and discharged at a platform located in West Delta Area. The oil and grease content
of unwashed produced sand ranged from 0.5 to 6.1 percent by weight or 6 to 14 percent by volume.9
This material had already undergone bulk solids separation in conjunction with tank cleaning operations
prior to being analyzed for oil and grease.10 Thus, some of the free oil could have been removed during
this process. Table X-2 presents the oil and grease data of the unwashed and washed produced samd.
Elevated levels of ^Ra and ^Ra have been detected in some produced sand samples. The 1989
OOC produced sand survey and the 1991 sand washing study contained data on the level of radioactivity
in produced sand.
Of the 330 facilities surveyed by OOC in 1989, 67 facilities reported radionuclide data for
produced sand. Of these 67 facilities reporting radioactivity data, 19 reported radionuclide concentration
data in picocuries per gram (pCi/g) based on laboratory analysis, and 48 reported radiation exposure data
in microroentgens per hour (microR/hr) from gamma readings. Naturally occurring radioactive materials
(NORM) levels of the produced sand were found to be above either 30 pCi/g or 50 microR/hr for 17 of
the 67 locations.4 Table X-3 summarizes the radioactivity data collected during the OOC Survey.
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TABLE X-2
AVERAGE OIL CONTENT IN PRODUCED SAND11
Cutting
Box
A-222
11441
17631
11331
17071
A-194
A-113
11041
17451
A-148
501
Oil Content in Feed Sand"
Oil & Grease (% Weight)*
3.95
2.4
1.55
3.3
2.2
4.3
5.95
2.25
3.45
3.15
No data
Oil Content in Washed Sand1"
Oil & Grease (% Weight)*
0.99
1.75
1.47
1.02
1.10
1.45
2.2
1.22
1.18
3.33
4.60
"Each sample is the composite of 5 samples taken from the cuttings hox.
"Samples were collected as the material (feed from a specific cuttings box that had undergone processing) was
discharged from the sand washer.
cOil and grease analysis by APHA Method 503D.
TABLE X-3
SUMMARY OF RADIONUCLIDE DATA FOR PRODUCED SAND FROM OOC SURVEY4
Facility Location
., (Lease Number)
MC-311
MP-310
OCS-0742
OCS-0985
OCS-1181
OCS-1220
OCS-2116
OCS-2280
OCS-2428
OCS-3236
OCS-4232
OCS-4240
OCS-4734
OCS-9575
OCS-G-1294
OCS-G-1870
OCS-G-2638
OCS-G-3936
SL-1355
Ka-226 Concentration
(pCปVg>
39
21
56
32
144
37
9
0
1
0
12
19
1
0
85
93
41
28
13
Ha-228 Concentration
(pCi/g)
64
23
51
29
180
10
9
0
1
0
12
19
1
0
84
91
39
15
21
X-5
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The Shell Offshore, Inc. produced sand washing study analyzed samples of unwashed and washed
sand for radionuclides. The average concentrations of radionuclides in the produced sand before washing
(this material had already undergone bulk solids separation in conjunction with tank cleaning operations)
were 44.5 pCi/g and 42.1 pCi/g for ^Ra and ^Ra, respectively. The average concentrations of
radionuclides in the washed produced sand were 39.9 pCi/g for ^Ra and 38.7 pCi/g for ^Ra.11 Table
X-4 presents the radionuclide data obtained in this study. '
TABLE X-4
AVERAGE RADIOACTIVITY LEVELS IN PRODUCED SATO)11
Cutting
Box
A-222
11441
17631
11331
17071
A-194
A-113
11041
17451
A-148
501
Unwashed Sand*
Ra-226
(pCi/g>
21.5
25
44
18.5
33.5
26.5
57.5
58
15
145
No data
Ra-228
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2.4 CONTROL AND TREATMENT TECHNOLOGIES
The primary control and treatment technology for produced sand is preventing the sand from
exiting the formation. Sand control is determined by the type of well completion. A specialized
completion can prevent sand from being brought into the production line with the fluids.5 The most up-
to-date completion technology will prevent production solids from entering the production tubing, even
in the most loose and unconsolidated formations.
The most common type of completion that prevents solids from entering the production tubing
is a gravel pack completion. A gravel pack completion is a perforated cased hole completion that
includes the placement of gravel, glass beads, or some other packing material between the production
tubing and the casing. A screen or mesh is also placed between the production tubing and the casing.
The gravel pack and screen serve as a filter to prevent solids from entering the production tubing. Older
wells are typically open holed perforated completions in which nothing prevents solids from entering the
production tubing with the fluid. Figure X-l presents a schematic diagram of a closed hole perforated
completion with gravel packing.
Gas producing wells are typically equipped with sand sensors which indicate the presence of sand
in the gas stream. Sand sensors are commonly used in gas producing wells because sand flowing at high
velocities with the produced gas will erode tubing, valves, and other process equipment. A sand sensor
is a simple device that detects the sand particles hitting its surface. If sand is detected, an electrical signal
will trigger an alarm to notify the operator. The operator can either alleviate the sand generation problem
at the source or reduce the gas velocities to prevent the sensor from detecting the sand flow. The sand
probes do not work in liquid streams and thus are not used on oil producing wells.5
2.4.1 BPT Technology
The management of produced sand wastes involves either treating the sand to meet the no free
oil limitations and discharge to the surface waters or hauling the sand to shore for final disposal. Data
from the 1989 OOC produced sand survey indicate that 32 percent of the sand collected is transported
to shore for disposal and that 68 percent of the sand is discharged to the ocean. The Minerals
Management Service (MMS) published an Environmental Impact Statement in 1989 that estimated 25
percent of the produced sand generated is transported to shore for disposal and 75 percent of the sand
is discharged into the ocean. Since that time, MMS has issued interim guidelines placing additional
restrictions on discharges of NORM contaminated produced sand.13
X-7
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Production
Tubing
Cement
Casing
Hanger
Liner Cemented
and
Perforated
Sands
Gravel Pack
Screen
Figure X-l
Closed Hole Perforated Completion (With Gravel Pack)
X-8
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In November 1990, the MMS Gulf of Mexico regional office responded to concerns of ihe
presence of NORM in produced sand by issuing a Letter to Lessees (LTL) requiring all disposal to be
approved by the MMS Gulf of Mexico office. Since the MMS Gulf of Mexico office was not approving
offshore disposal, in essence this LTL placed a prohibition on the discharge of produced sand. A second
LTL was issued in December 1991 which established interim guidelines for the disposal of produced
sands. This LTL allows limited discharges of produced sand based on the following criteria14:
The discharge is not in close proximity to a biologically sensitive area.
The discharge complies with NPDES requirements.
Samples of the material must be analyzed and demonstrate a radiation dose equivalent
rate of less than 25 microR/hr above background.
The volume to be discharged is less than 100 barrels per day.
Samples must be analyzed by a laboratory capable of providing accurate results for
concentrations of ^Ra and 22%a and records concerning these data must be maintained
and made available for review.
ป Should the total radium discharged surpass 50,000 micro curies per quarter, the MMS
regional office must be notified and all future discharges stopped until an assessment of
the area is completed.
The MMS guidelines require the operator to submit an application for each facility where
discharge is proposed. The application must include:
Identity of the platform (well depth and oceanographic conditions)
List of other facilities that will be discharging at the site
Frequency and volume of discharge
Preliminary measurements of radionuclide activity
Program for monitoring, sampling, and record keeping
Description and characterization of the material to be discharged
Method of discharge.
o
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Specific instructions have been provided regarding the above requirements. Even before
enactment of the restrictions, some operators would opt for onshore disposal as opposed to treatment and
discharge at the platform due to: costs, lack of space, lack of time, lack of proper equipment or type of
hydrocarbons associated with the sand.4
X-9
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2.4.2 Additional Technologies
Several methods were identified in the literature for treatment of produced sand and are included
in this section. The treatment methods include: washing the material with water and detergents,
mechanical separation, separation with solvents, and air flotation. Most of the sources consulted did not
provide data or cleaning efficiencies for the treatment of produced sand.
The sand washing unit evaluated by Shell Offshore, Inc. consisted of mixing and settling tanks.
The system was designed for operation at onshore locations and is larger than can be accommodated at
some offshore platforms. This system achieved removals of approximately 60 percent of the oil
associated with the produced sand. The system also generated centrifuge solids and washwater from the
detergent cleaning operation that were transported to shore for disposal.8 The unit processed 600 barrels
of produced sand. The cost of the operation was $75,000 which included $6,000 for set-up and rig
down, one and a half days of experimental operation, processing at a conservative flow rate and
approximately $30,000 for soap. Treatment cost was $125 per barrel but the operator indicated that
future operation of the treatment system will be approximately $60 per barrel.12
Several other treatment systems have been identified in the literature:
A sand washer system that mechanically removes oil from produced sand consisting of
a bank of cyclone separators, a classifier vessel, and another cyclone. Following
treatment the sand is reported to have no trace of oil.15 Actual data were nqt presented.
A sand cleaning system consisting of two vertical two-phase separators. The initial
separator is baffled and sand falls through to the second separator. The second separator
contains a solvent layer to absorb oil from the sand grains.15 Data were not presented.
A produced sand disposal system consisting of a conventional cyclone and a cyclone with
chemical and air injection that removes the oil by air flotation.16
Treatment of produced sand via mechanical washing has several drawbacks. The capital costs
necessary to install a complete sand washing unit on a platform preclude the widespread installation of
systems on platforms which only need to wash sand every 3 to 5 years. In addition to the equipment
costs, current/ existing platform space is limited or not available for such equipment. The economics of
platform additions for these systems would also limit widespread usage of sand washing technology. Sand
washing does not always guarantee one-hundred percent discharge of the sand. Sands containing heavy
oils cannot always be washed thoroughly enough to meet the permit discharge prohibition on free oil.
X-10
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In these cases, the sand cannot be discharged and must be transported to shore for disposal. Since sand
washing only reduces the oil content, produced sand that contains certain levels of Naturally Occurring
Radioactive Material (NORM) must be transported to shore for disposal under the current MMS
guidelines. In addition, sand washing can generate additional wastes, such as oily solids and oily water,
which require further treatment and disposal.
If the produced sand can not be treated and discharged at the platform, then it is transported to
shore for disposal. Cuttings boxes (15 and 25 barrel capacity), 55 gallon steel drums, and cone bottom
portable tanks are used to transport the sand to shore via offshore service vessels.4 According to the
OOC, produced sand is disposed as a non-hazardous oilfield waste (NOW) according to State regulations.
See Section VII.5.2.4 for a discussion of land disposal of NOW.
3.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
The definitions for well treatment, workover, and completion fluids (TWC fluids) are as follows:
Well Treatment Fluids are "any fluid used to restore or improve productivity by
chemically or physically altering hydrocarbon-bearing strata after a well has been
drilled."
Workoyer Fluids are "salt solutions, weighted brines, polymers, or other specialty
additives used in a producing well to allow safe repair and maintenance or abandonment
procedures."
ซ Completion Fluids are "salt solutions, weighted brines, polymers and various additives
used to prevent damage to the wellbore during operations which prepare the drilled well
for hydrocarbon production."
3.1 WELL TREATMENT, WORKOVER, AND COMPLETION FLUID VOLUMES
The volume of workover, well treatment, and completion fluids generated will vary depending
on the type of well and the specific operation to be performed. Normally, workover and completion
operations require at least one well volume of fluid since the fluids are contained within the well bore.
For example, a 10,000 foot well with 3.5 inch diameter tubing contains a volume of less than 100
barrels.17 The volume of workover and completion fluids will generally be the same before and after
usage. More than one well volume (usually no more than three) are necessary for well treatment because
the fluids may be tost to the formation. Treatment fluids can react with the formation and the volumes
before and after use are not the same.
x-ii
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Typically, small volume discharges of fluids occur during the course of workover and completion
operations hi the same manner as drilling fluids discharges. In response to the 1991 proposal, several
industry commenters indicate that workover and completion fluids that return to the surface as a discrete
slug represent only a small portion of the fluids discharged during workover and completion operations.18
Discharge volumes for specific workover, completion and well treatment activities are presented in Table
X-5. This information indicates that discharges can range from 100 to 1,000 barrels. A report prepared
for the American Petroleum Institute includes a summary of a survey of well servicing activity for 1988.
This survey, presented in Table X-6, indicated that well treatment is performed on approximately 2
percent of the wells each year and approximately 4 percent of the wells are completed or recompleted
each year. Other sources indicate that workover operations are performed on a well every three to five
years.18 Acidizing chemical data was obtained from four companies during the 1988 survey and is
presented in Table X-7.
TABLE X-5
TYPICAL VOLUMES FROM WELL TREATMENT, WORKOVER,
AND COMPLETION OPERATIONS19
Operation x -
Completion and Workover
Well Treatment
Type of Material
Packer Fluids
Formation Sand
Metal Cuttings
Completion/Workover Fluids
Filtration Solids
Excess Cement
Neutralized spent Acids
Completion/Workover Fluids
Volume Discharges (barrets)
100 to 1000
ItoSO
<1
100 to 1000
10 to 50
<10
10 to 500
10 to 200
Volumes of fluids used for workover, completion, and well treatment operations were collected
for the Cook Inlet Discharge Monitoring Study. Table X-8 presents the volumes discharged during
specific operations. Volume information was collected for a one year period. Ten discharge events were
sampled during the course of the year. Each of the discharge events was from a single operation (either
well treatment, workover, or completion) but discharges of the fluids may have occurred at several times
during the course of the operations.21
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TABLE X-6
SURVEY OF WELL SERVICING ACTIVITY20
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Total! Number of Wells
Well Treatment (Stimulation)
Completions
Artificial Lift Installation/Repair
Tubular Repair
Recompletions
Total Number of Jobs
Gulf of Mexico
ซ
10,614
259
162
1,401
91
320
2,233
Offshore California
2,090
28
36
180
44
24
312
Alaska9
MHMHMM
355
3
30
53
5
3
180
Krt.,1. u s **, '25% of wells and service offshore. The data includes
both the onshore and offshore subcategories.
TABLE X-7
DATA ON ACIDIZING IN THE GULF OF MEXICO20
Number of Wells
Number of Acid Jobs
Hydrochloric
Hydrofluoric
Acetic
Total Acid
Average Job
1
mmmmmmmmmum
358
19
Company/Area
2
MBMBMBCMM
386
19
3
mmmmmmmmmmm
600
80
Acids Used (gallons)3
10,741
0
0
10,741
565
46,300
8,363
3,660
58,323
3,070
168,000
61,320
0
229,320
2,867
4
322
27
4,509
0
0
4,509
167
Total
i
1,666
145
229,550
69,683
3,660
302,893
2,089
me various concentrations and types of acids have been converted to the equivalent volume of 15
percent hydrochloric acid (in gallons) based on the available hydrogen ion
X-13
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TABLE X-8
VOLUMES DISCHARGED DURING WORKOVER, COMPLETION, AND WELL
TREATMENT OPERATIONS FROM THE COOK INLET DMR STUDY21
Type of Joi>
Volumes
. Discharged
(barrels)
Minimum
Maximum
Average
Workover
600
600
400
100
1,111
492
1,200
670
100
1,200
647
Completion
390
75
310
303
50
50
25
75
25
1,295
740
50
25
1,295
282
Well
Treatment
178.6
238.1
35.7
71.4
20
93
20
238.1
106
Acid
10.8
320.8
25
173
10.8
25
132
Clean Out
Tubing
12
148
12
148
; so
3.2 WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS CHARACTERISTICS
3.2.1 Well Treatment Fluids
In general, well treatment fluids are acid solutions. Acids used include: hydrochloric acid (HC1),
hydrofluoric acid (HF) and acetic acid (QHA). Concentrations of HCl in water range from 15 to 28
percent. A mixture of hydrochloric and hydrofluoric acid is also used and is referred to as "mud acid."17
Mud acid mixtures are 12 percent HCl and 3 percent HF in water. Acids are selected based on formation
solubility, reaction time, and reaction products. The acid reactions are temperature dependent and
temperature increases can decrease the depth of acid penetration.22 ;
A well treatment job involves a series of several solutions to be pumped down hole: a pre-flush
solution, the;acid solution, and a post-flush or "chaser" solution. The pre-flush solution is generally 3-5
percent ammonium chloride (NH4C1) and forces the hydrocarbons back into the formation to prepare for
stimulation. The acid solution is then pumped downhole. Following the acid solution is a post-flush of
ammonium chloride that forces the acid further into the formation.20 The solutions remain in the
formation for 12 to 24 hours and are then pumped back to the surface.17
X-14
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Common well treatment fluids include: hydrofluoric acid, hydrochloric acid, ethylene
diaminetetraacetic acid (EDTA), ammonium chloride, nitrogen, methanol, xylene, toluene. Well
treatment fluids may include additives such as corrosion inhibitors, mutual solvents, acid neutralizers,
diverters, sequestering agents, and antisludging agents.19 Additives include: iron sequestering agents,
corrosion inhibitors, surfactants, viscosifiers, and fluid diverters.23 The purpose of the additives can be
for: reducing the leak-off rate, increasing the propping agents carried by the fluid, reducing friction,
and preventing the aggregation and deposition of solid particles.20 A corrosion inhibitor is always used
during an acid stimulation job because the acids used are extremely corrosive to the steel piping and
equipment.17-24 Table X-9 lists some of the typical chemicals used during well treatment.
TABLE X-9
WELL TREATMENT CHEMICALS25
Type ot Ftohi or Purpose
Fracture or matrix
acidizing agent
Acid stimulation agent
Acid fracturing agent
emulsion
Acid precursor
strata
Sequestering additive for
iron and aluminum in acid
stimulation
Fracturing agent
racturing agent
Acid fracturing
Constituents
BMH^HBMMHHMBmOH
Acrylamide polymer
Gelling agent
Reducing agent
Acid
Vinyl pyrolidine eopolymer
HC1
Water
Oxyalkylated acrylamidoalkane-
sulfonicacid polymer
Dialkyldimethyl-ammonium chloride
polymers in acid solution
C
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3.2.2 Workover and Completion Fluids
Workover and completion fluids are similar in nature and are typically a variety of clear brine.
Packer fluids are workover or completion fluids which are left in the annulus between the well casing and
tubing at the conclusion of the operation.18 Specific fluids are used during completion and workover
operations to seal off the producing formation to prevent fluids and solids loss to the formation. 'The
formation is sealed by the disposition of a thin film of solids over the surface of the formation. These
solids are called bridging agents.25 The bridging agents are oil or acid soluble and dissolve at the
cessation of workover or completion operations to enable oil or gas to be produced from the well.26
Commonly used bridging agents are: ground calcium carbonate, sodium chloride, oil soluble resins, and
calcium lignosulfonates.27 The fluids are selected to be compatible with the formation to minimize
damage to the formation and should perform the following functions:19'27-28
Control subsurface pressures
Maintain hole stability
" Transport solids to the surface
Installation of packer fluids
Keep solids in suspension ',
Minimize corrosion
Remain stable at elevated temperatures.
Workover and completion fluids can be divided into two broad classifications: water-based and
oil-based fluids. There are three types of water-based fluids: brine water solutions, modified drill ing
fluids, and specially designed drilling fluids. .
Brine fluids are comprised of inorganic salts dissolved in water. This combination yields a solids-
free fluid with sufficient density to control sub-surface pressures.27 Brine solutions have a density ranging
from 8.5 pounds per gallon (ppg) for seawater to 19.2 ppg for zinc bromide/calcium bromide fluids.28
Table X-10 lists some of the more common brine solutions and their densities. Disadvantages of brine
fluids are: expense (which can reach $800/barrel), the generation of precipitates in the formation at high
pH or when contaminants are present, loss of large volumes of fluid to the formation, limited lifting
capacities, poor suspension properties, and temperature sensitivity.27
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TABLE X-10
COMMON BRINE SOLUTIONS USED IN WORKOVER AND COMPLETION
OPERATIONS27
Brine Solution
iaMMl*lltoBtniltaMl^H^Hl^I^M^*MMMIM^Hi^BIM
Potassium Chloride
Sodium Chloride
Sodium Bromide
Calcium Chloride
Calcium Bromide
Calcium Chloride-Calcium Bromide
Zinc Bromide-Calcium Bromide-Calcium Chloride
Density (Ib/gailon)"
^^^^^I^Bi^BHABMttMHIMHA
9.7
10.0
12.5
11.6
11.6 to 14.2
11.6 to 15.1
15.1 to 19.2
"Densities given are the maximum density except where a range is provided.
Modified drilling fluids contain the necessary additives to achieve the basic functions of a
completion or workover fluid. These fluids are economical to use since they are usually readily available.
The disadvantages of modified drilling fluids is their high solids content (botlTcompressible and incom-
pressible solids). The high solids content can result in: hydration and/or migration of formation clays
and silts, emulsion or water blocking, and permanent formation damage.
Specially designed fluids consist of inorganic brines with the addition of: polymers, acids, water,
or oil-soluble materials heeded to formulate a fluid with the proper viscosity, weight support, and fluid
loss control. These fluids are used where additional clay inhibition is required. Two of the available
polymers used are hydroxyethyl cellulose (HEC) and xanthan gum. Problems associated with specially
designed systems include poor temperature stability, foaming, and corrosivity.27
There are two types of oil-based fluids: true oil fluids and invert emulsion fluids. The
advantages of oil-based fluids include: temperature stability, density range, maximum inhibition,
minimum filtrate invasion, and non-corrosive. Disadvantages include toxicity and the potential to:
damage environmentally sensitive areas, change the wettability of the formation, cause emulsion blocks,
or damage dry gas sands.27
The drilling mud tanks are used to mix and circulate workover and completion fluids. The fluids
are circulated to remove unwanted materials and to maintain pressure.17 Solids control must be
X-17
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maintained in workover and completion fluids so that the formation is not irreversibly plugged in the
vicinity of the wellbore.
World Oil publishes a yearly guide of drilling completion and workover fluids. The guide lists
specific additives to the basic fluid and includes the product name, tradename, description of material,
recommended uses, product function and the company from which they may be obtained. In all, 1,226
additives were recommended for use in workover operations and 1,157 of these additives were also
recommended for other uses. The primary functions of additives hi workover fluids were as corrosion
inhibitors, viscosifiers, and filtration reducers. The corrosion inhibitors such as hydrated lime and amine
salts are added to the fluid to control corrosion. The viscosifiers are added to increase the viscosity. The
filtrate reducers are added to reduce fluid loss to the formation and can include bentonite clays, sodium
carboxymethylcellulose, and pregelatinized starch.29 Table X-l 1 identifies specific additives to completion
and workover fluids.
TABLE X-ll
ADDITIVES TO COMPLETION AND WORKOVER FLUIDS19
Type of Additive ,
Viscosifiers
Fluid Loss Control
Corrosion Inhibitors
Specific Additives
Guar Gum
Starch
Xanthan Gum
Hydroxyethyl Cellulose
Carboxymethyl Cellulose
Calcium Carbonate
Graded Salt
Oil Soluble Resins
Amines
Quaternary Ammonia Compounds
Several sources indicate that well completion and workover fluids may include hydroxyethyl
cellulose, xanthan gum, hydroxypropyl guar, sodium polyacrylate, filtered seawater, calcium carbonate,
calcium chloride, potassium chloride, and various corrosion inhibitors and biocides, zinc bromide,
calcium bromide, calcium chloride, hydrochloric acid, and hydrofluoric acids.23
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3.2.3 Chemical Characterization of Well Treatment, Workover, and Completion Fluids
Samples of workover, completion and well treatment fluids were collected and analyzed for the
Cook Inlet Discharge Monitoring Study conducted in 1987. The study was a cooperative effort between
the U.S. EPA Region X and seven oil and gas companies. The specific objective of the study was to
determine the type, composition and volume of discharges from workover, completion, and well treatment
operations. Samples were collected of fluids during five workover operations (one using weak acid,
EDTA), two completion operations, and three well treatments using acid.21
The samples collected during the Cook Inlet Discharge Monitoring Study were analyzed for pH,
oil and grease, dissolved oxygen, BOD, COD, TOC, salinity, zinc, cadmium, chromium, copper,
mercury, and lead. Table X-12 summarizes the analytical results from the Cook Inlet Discharge
Monitoring Study.
The Three Facility Study collected well treatment fluids from two wells being acidized at the
THUMS facility.17 Table X-13 presents the analytical results of the well treatment fluids sampled at the
THUMS facility.
The American Petroleum Institute's report entitled Exploration and Production Industry
Associated Wastes Report presents metals analysis for a fracturing fluid sampled in 1982. The firac fluid
analyzed was a water based mixture of polymers, salts, gels and miscellaneous chemicals from a
production facility in California. The fluid contained 25 to 30% fine sands used as a propping agent.
A propping agent is a granular substance carried in suspension by the fracturing fluid that serves to keep
the cracks open when the fracturing fluid is withdrawn after a fracture treatment. The total volume of
fluids used including a separate displacement was 840 barrels. Table X-14 contains analytical data for
metals analyses of this fluid.17
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TABLE X-13
ANALYSIS OF FLUIDS FROM AN ACIDIZING WELL TREATMENT17
1
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1
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1
1
Analyte
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Molybdenum
Nickel
Selenium
Silver
Sodium
Thallium
Tin
Titanium
Vanadium
Yttrium
Zinc
Concentration
53.1
<3.9
<1.9
12.6
<0.1
31.9
0.4
35.3
19
<1.9
3.0
572
<9.82
162
<0.96
52.9
<2.9
<0.7
1,640
5.0
6.66
0.68
36.1
0.19
28.5
Anatyte
Aniline
Naphthalene
o-Toluidine
2-Methylnaphthalene
2,4,5-Trimethylaninine
Oil and Grease
pH
-
Concentration
434
ND
1,852
ND
2,048
619
2.48
X-21
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TABLE X-14
METALS ANALYSIS OF A FRACTURING FLUID17
Analyte
Antimony
Arsenic
Barium
Beryllium
Cadmium
Chromium
Cobalt
Copper
Lead
Mercury
Molybdenum
Nickel
Selenium
Silver
Thallium
Vanadium
Zinc
PH
Specific gravity
% Solids
Concentration (mg/kg)*
44.83
< 0.002
7.245
0.06
0.13
0.065
0.18
0.395
2.27
0.0045
0.10
0.23
0.106
0.03
0.30
0.10
2.1
5.0
1.60
10.91%
*Mean concentration of duplicate samples except for pH, specific gravity
and % solids.
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3.3 WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS CONTROL AND TREATMENT
TECHNOLOGIES
3.3.1 BPT Technology
The current BPT requirement for TWC fluids is "no discharge of free oil" to receiving waters,
as determined by the static sheen test. Methods for treatment and disposal include:
Treatment and disposal along with the produced water
Neutralization for pH control and discharge to surface waters
Reuse
Onshore disposal and/or treatment.
Conflicting information is available regarding the treatment and disposal of well treatment,
workover, and completion fluids with the produced water. Some sources indicate the infeasibility of
commingling due to technical limitations while other sources indicate routine commingling without any
negative effects on the performance of the produced water treatment system. A key factor of whether
the TWC fluids are or are not commingled is how they resurface from the formation. If the TWC fluid
surfaces as a discrete slug, it can be easily separated from the production fluid stream. Once separated,
the TWC fluid must meet the no free oil requirements upon discharge. If the TWC fluid cannot meet
the no free oil requirement, it must either be treated or brought to shore for treatment and/or disposal.
However, if the TWC fluid is not present as a discrete slug, separation may be difficult. Several
commenters reported that most completion and workover fluid discharges occur as small volume
discharges several times during the completion or workover operations (normally lasting seven to thirty
days).18 The following paragraphs present information on facilities that do and do not commingle.
One source indicates that these fluids are not typically processed with the produced water in
offshore operations and that operating practices in Cook Inlet are not representative of offshore operations
(facilities in Cook Met commingle TWC fluids with produced water). Other sources have indicated that
the processing of these fluids along with the produced water is infeasible. Due to short residence times,
offshore produced water treatment systems are sensitive to changes in the influent which would occur if
large, concentrated slugs of TWC fluids are introduced to the system. EPA believes however, that
corrosion problems can also result if oxygen is introduced into the produced water treatment system along
with the TWC fluids.18
X-23
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According to one industry report, TWC fluids can be effectively treated in the produced water
treatment system if commingling is performed in such a manner that the treatment system is not subjected
to concentrated slugs of TWC fluids.20 Operators in Alaska also treat and dispose of these fluids with (heir
produced water. In California, facilities commingle the workover, completion and well treatment fluids
with the produced water.17
Generally, economics dictates recycling and reusing weighted workover and completion fluids.
Workover and completion fluids can be reused 2 to 3 times depending on the amount of oil and grease
build-up. Inexpensive workover and completion fluids consisting primarily of filtered seawater are
typically not reused. Treatment fluids are not reused because they react with the formation and lose their
treatment ability.17
3.3.2 Additional Technologies Considered
Additional controls considered for BAT and NSPS levels of control for this rulemaking are
limitations on oil and grease content. The technology basis for oil and grease limitations on TWC fluids
is commingling and treating with the produced water. A detailed discussion of produced water BAT and
NSPS treatment technology is presented in Section IX.
Information contained in a 1989 industry report indicate that for operations involving 10 or more
wells per platform, the produced water flow rates and the treatment systems are large enough to
sufficiently buffer the introduction of the TWC fluids into the produced water treatment system such that
upsets will not occur.30 Typically, only one well is treated at a time due to the manpower and equipment
requirements. Therefore, the volumes of TWC fluids from this one well are small relative to the volume
of the produced water from the remaining wells. Those TWC fluids unable to be processed with the
production stream, can be processed through a test separator (standard equipment on platforms).
Production facilities piping the bulk production fluids to shore for separation would be unlikely to suffer
treatment system upset because the volumes of produced water from other platforms being treated at the
same onshore facility would be much greater in relation to the TWC fluid volume. Even, facilities with
less than 10 wells per platform should be able to commingle TWC fluids in the produced water treatment
system if the fluids are captured and commingled at such a rate to prevent system upset.
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4.0 DECK DRAINAGE
4.1 DECK DRAINAGE SOURCES
Deck drainage includes all water resulting from spills, platform washings, deck washings, tank
cleaning operations and run-off from curbs, gutters, and drains including drip pans and work areas.
4.2 DECK DRAINAGE VOLUMES
EPA evaluated Discharge Monitoring Reports (DMRs) for deck drainage discharges from 32 oil
companies located in the Gulf of Mexico.31 The DMR data spans two years from May 1, 1981 through
April 30, 1983 and consists of deck drainage monitoring data from oil and gas production facilities. The
DMR data reports monthly samples taken by the operators. The data do not indicate the location of
where the samples were taken, the treatment of the waste stream prior to sampling, or the analytical
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method of determining
the DMR data.
oil & grease. Table X-15 presents the volumes of deck drainage compiled from
TABLE X-15
VOLUMES OF DECK DRAINAGE FROM OFFSHORE RIGS IN THE GULF OF MEXICO31
Year
nMHM^HHWMM
1981 - 1982
1982 - 1983
Number of
Platforms
mMMHMBi
425
950
Average Monthly Volume
Range
-------
The DMR from the Gulf of Mexico contained oil and grease concentrations of deck drainage
discharges. Table X-16 presents the monthly averages of deck drainage oil and grease concentrations for
the two years evaluated.
TABLE X-16
CHARACTERISTICS OF DECK DRAINAGE FROM OFFSHORE PLATFORMS31
Oil and Grease in Deck Drainage f
_ r (mgfi)r , , ':: - -
-
1981-82 (19 Sites)
1982-83 (117 Sites)
Monthly Average
Range
5-47
2-183
Average
22
28
Daily Maximum
Range
19-72
5-1363
Average
51
75
The Tliree Facility Study collected samples of untreated and treated deck drainage from the
THUMS facility and the Shell Beta Complex. The range of pollutant concentrations hi untreated deck
drainage are presented in Table X-17. '
Table X-18 presents TSS and oil and grease data from the deck drainage collection system of the
THUMS facility before treatment in a skim basin. See Section X.5.4 for a description of the deck
drainage system at the THUMS facility.
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TABLE X-17
POLLUTANT CONCENTRATIONS IN UNTREATED DECK DRAINAGE33 M
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Pollutant
Temperature (ฐC)
Conventionals (mg/1)
pH
BOD
TSS
Oil & Grease
Nonconventionals
TOC (mg/1)
Aluminum (/zg/1)
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Sodium
Tin
Titanium
Vanadium
Yttrium
Priority Metals (/ig/1)
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Silver
Thallium
Zinc
Range of
Concentration
20-32
6.6-6.8
< 18-550
37.2-220.4
12-1,310
21-137
176-23,100
2,420-20,500
3,110-19,300
98,200-341,000
<20
830-81,300
50,400-219,000
133-919
< 10-20
ISlxlOMeSxlO4
<30
4-2,030
< 15-92
<2-17
<4-<40
<2-<20
<1-1
<4-25
< 10-83
14-219
< 50-352
<4
< 30-75
< 3-47.5
<7
<20
2,970-6,980
Pollutant
Priority Organics Otg/1)
Acetone
Benzene
m-Xylene
Methylene chloride
N-octadecane
Naphthalene
o,p-Xylene
Toluene
1,1-Dichloroethene
Range of
Concentration
'**
ND-852
ND-205
ND-47
ND-874
ND-106
392-3,144
105-195
ND-260
ND-26
*Ranges of four samples, two each, at two of the three facilities in the three-facility study.
X-27
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TABLE X-18
DATA FROM SUMP EFFLUENT TAKEN AT THUMS ISLAND GRISSOM FACILITY33
Sample Date
June 26, 1989
June 28, 1989
Temp, CO
32
30
pH
6.8
6.6
TSS (mg/l)
37.2
208.4
Oil and Grease
(mg/1)
199
1310
Table X-19 presents data of untreated and treated deck drainage collected at the Shell Beta
Complex. The data of the treated deck drainage represents samples collected from the skim pile. See
Section X.S.4 for a description of the deck drainage system at the Shell Beta Complex.
TABLE X-19
DATA FROM DECK DRAINAGE TAKEN AT SHELL BETA COMPLEX33-34
Sample Date
June 20-21, 1989
June 21-22, 1989
Untreated Deck Drainage
Temp.
CQ
24
20
PH
6.7
6.6
TSS
(mg/1)
65.6
220.4
Oil & Grease
(mg/1)
12
286
Treated Deck Drainage
Temp.
CO
19
17
pH
6.7
6.6
TSS
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X-29
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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 baffled plates where it coalesces. See Section IX.5.1.6 for a description of a typical skim pile.
Due to the differences hi specific gravity, oil floats upward through oil risers from baffle to baffle. The
oil is collected at the surface and removed by a submerged pump. These pumps operate intermittently
and will move the separated oil to a sump tank. Oil recovered in the sump is combined with production
oil.
The following chemical and physical characteristics are major factors in the performance of
treatment technologies:35
Salt content: usually a high salt content facilitates the separation, some processes do not
work well with a low salt content
Solid content: the presence of solid particles in the water usually precludes the use of
fibrous bed separation techniques; tank cleaning leads to high solids.
Chemical content: chemicals used in oil production (e.g. biocides, corrosion inhibitors)
will lower the size of oil droplets, creating separation problems.
Oil content: depending on the oil content a one-step or two-step process is necessary.
Temperature: a high temperature increases the separation but also increases the
solubility of oil compounds in water.
* Oil density: the lighter the oil, the easier the separation.
Oil viscosity and Wax Content: interfere with filtering or coalescing bed plates.
* Oil droplet size: the larger the droplet size, the easier the separation.
In the Gulf of Mexico, treatment practices for deck drainage vary. Some deck drainage discharge
systems collect the flow from all drains and route it to a skim pile which is designed to meet the BPT
prohibition of free oil discharges. Optimum performance of a skim pile is based on a 20 minute
residence time. Other deck drainage discharge systems take all drains to a sump tank located below the
main deck. Oil is separated by gravity and pumped to the oil treating system while water is then routed
to a skim pile for discharge to the sea.35
X-30
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Some platforms in Cook Inlet, Alaska collect crank-case oil separately and oil-based muds are
diverted from the platform drain systems for onshore separation and treatment. Deck drainage is either
piped to shore with the produced water waste stream and treated by gas flotation or gravity separated on
the platform and treated by gas flotation to an average of 25 mg/1 oil and grease.36
In California, some platforms mix deck drainage water with produced water and pipe it to shore
for treatment and disposal. On other platforms the deck drainage is mixed with produced water, filtered
and reinjected.35 At the Beta Complex, evaluated in the Three facility Study, all waters from the deck
drains, which may originate from washdowns, spills, rain, or equipment drains, are treated by the
emergency sump system and discharged to the skim pile. Figure X-3 presents a detailed schematic of
the emergency sump system. Water discharged from the emergency sump system and emergency
discharges from the produced water system are directed to the skim pile.
A sampling trip was performed by EPA in April 1991 to collect data to evaluate the produced
water treatment system located on Marathon Oil's Eugene Island 349-B platform in the Gulf of Mexico.37
Deck drainage was not sampled on this sampling trip; however, observations of the deck drainage
treatment system are presented here to provide additional information regarding site-specific treatment
practices. The deck drainage at this site is collected by deck drains in several places on the drilling deck
and by gutters that line the perimeter of the drilling deck. The drainage lines are all connected together
and piped to the pre-sump. The pre-sump is a small gravity separator with an oil collection system. The
capacity of the pre-sump is approximately 40 barrels. The oil collected in the pre-sump is pumped to the
chem-electric oil treatment unit. The water is piped to a skim pile for discharge to the sea.
One of the platforms examined in the Cook Inlet Discharge Monitoring Study was the Phillips
Petroleum Company's Platform Tyonek. On this platform all produced water and deck drainage water
are commingled in a slop tank. Waters from the slop tank are pumped to the balance tank in batches.
Chemicals are added and circulated to extract the hydrocarbon from the water. The mixture is retained
in the tank for a period of time to allow the oil and water to separate by gravity. The water is discharged
to the sea. The remaining liquid is transferred to another slop tank for holding and reprocessing.
Sampling results indicated a mean average oil and grease content of 3.8 milligrams per liter.
X-31
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A study in Region II found that for deck drainage treatment systems to operate properly, three
basic components were necessary:
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1. Settling tanks of sufficient capacity
2. Desander (hydrocyclone)
3. Oil-water separation unit (type not specified).
If these conditions were met, the effluent oil and grease concentrations were below a monthly
average of 30 mg/1 and a daily maximum of 52 mg/1.
4.4.2 Additional Deck Drainage Technologies
As part of this rulemaking, EPA has considered BAT and NSPS limitations based on commingling
deck drainage with the produced water. An example of this practice can be found on Texaco/Superior's
platform "A" in Cook Inlet, Alaska. All deck drainage is collected and drained to the production surge
tank where it combines with produced fluids and is also shipped to shore. Various studies indicate that
commingling, as it is defined above, does not usually occur. There is relatively little data supporting the
use of this practice. More often, the deck drainage is diverted to a sump tank. The water is gravity
separated and transferred to a skim pile where further separation occurs prior to discharge overboard.
The oil removed in the sump tank is pumped to an oil separator in the produced water treatment system.
It was found, through a telephone conversation with a senior process engineer in Cook Inlet, that mixing
of the deck drainage and produced water is only conducted when the deck drainage stream fails the visual
sheen test.38 Rather than co-mingling the deck drainage with the produced water treatment system at the
facility, the deck drainage wastewater is diverted and pumped to shore along with produced water for
treatment. A corrosion inhibitor is usually added to compensate for the introduction of the oxygen-
enriched deck drainage water.
The whole deck drainage waste stream is not usually commingled with the produced waste water
stream because:35
The resulting flow variations would seriously upset the produced water treatment facility.
Deck drainage water, saturated with oxygen, when combined with the salt content
of the produced water could result in higher corrosion rates in the equipment.
Also, the oxygen may combine with iron and sulfide in the produced water can
causing the formation of solids which foul treatment equipment;
X-33
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Detergents, used for washing oil off the decks, cause emulsification of oil and
seriously upset the produced water treatment processes.
While the total volume of deck drainage is less than the total volume of produced water generated
annually, the deck drainage to the produced water treatment system would create hydraulic overloading
of the equipment. An add-on treatment specifically designed to capture and treat deck drainage, other
than the type of sump/skim pile systems typically used, on offshore platforms is not technologically
feasible. Deck drainage discharges are not continuous discharges and they vary significantly in volume.
At times of platform washdowns, the discharges are of relatively low volume and are anticipated. During
rainfall events, very large volumes of deck drainage may be discharged in a very short period of time.
A wastewater treatment system installed to treat only deck drainage would have to have a large treatment
capacity, be idle at most times, and have rapid startup capability. Since startup periods are typically the
least efficient for treatment systems and offshore platforms have limited available space for storage of the
volumes of deck drainage which occur, EPA determined that an add-on treatment system appropriate for
the treatment of deck drainage was not available.
5.0 DOMESTIC WASTES
5.1 DOMESTIC WASTES SOURCES
Domestic wastes (gray water) originate from sinks, showers, laundry, food preparation areas., and
galleys on the larger facilities. Domestic wastes also include solid materials such as paper, boxes, etc.
EPA compiled U.S. and international regulations governing the discharge of domestic wastes, into
ocean waters from ships and fixed or floating platforms. International waters are governed by MARPOL
73/78 (the International Convention for the Prevention of Pollution from Ships, 1973, as modified by the
Protocol of 1978 relating thereto.) The Coast Guard implemented MARPOL 73/78 as part of its pollution
regulations (33 CFR-Part 151) governing U.S. waters.
Disposal from drilling rigs are dealt with in Regulation 4 of Annex V of MARPOL. It states that:
(1) Fixed or floating platforms, engaged in the exploration, exploitation, and
associated offshore processing of sea-bed mineral resources, and all other ships
alongside such platforms or within 500 meters of such platforms, are forbidden
to dispose of any materials regulated by this Annex, except as permitted by
paragraph (2) of this Regulation.
X-34
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(2) The disposal into the sea of food wastes when passed through a comminutor or
grinder from such fixed or floating drilling rigs located more than 12 nautical
miles from land and all other ships when positioned as above. Such comminuted
or ground food wastes shall be capable of passing through a screen with openings
no greater than 25 mm.
Table X-20 summarizes the garbage discharge restrictions from fixed or floating platforms.
TABLE X-20
GARBAGE DISCHARGE RESTRICTIONS
Garbage Type
Plastics - includes synthetic ropes and fishing
nets and plastics bags.
Dunnage, lining and packing materials that
float.
Paper, rags, glass, metal bottles, crockery and
similar refuse.
Paper, rags, glass, etc. comminuted or ground.1
Victual waste not comminuted or ground.
Victual waste comminuted or ground.1
Mixed garbage types.3
Fixed or Floating Platforms &
Associated Vessels4 (33 CFR I5L73)
^^^^^^I^M^Hl^H^HMlMMi^MMIMMIHMMIMIUM
Disposal prohibited (33 CFR 151.67)
Disposal prohibited
Disposal prohibited
Disposal prohibited
Disposal prohibited
Disposal prohibited less than 12 miles from
nearest land and in navigable waters of the U S
See note 3.
(1) Comminuted or ground garbage must be able to pass through a screen with a mesh size no
larger than 25 mm (1 inch) (33 CFR 151.75).
(2) Fixed or floating platforms and associated vessels include all fixed or floating platforms
engaged in exploration, exploitation, or associated offshore processing of seabed mineral resources
and all ships within 500m of such platforms. '
(3) When garbage is mixed with other harmful substances having different disposal requirements
the more stringent disposal restrictions shall apply.
5.2 DOMESTIC WASTES VOLUME AND CHARACTERISTICS
The volume of domestic waste discharged has been estimated to range from 50 to 100 gallons per
person per day, with a BOD of 0.2 pound per day per person.39-40 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 X-21 and X-22 summarize the volume and
characteristics of domestic wastes.
X-35
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I
TABLE X-21
TYPICAL UNTREATED COMBINED SANITARY AND DOMESTIC WASTES FROM
OFFSHORE FACILITIES41
Number of
Persons
76
66
67
42
10-40
Flow
(gal/day)
5,500
1,060
1,875
2,155
2,900
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Under the Coast Guard Regulations, discharges of garbage, including plastics, from fixed and
floating platforms engaged in the exploration, exploitation and associated offshore processing of seabed
mmeral resources are prohibited with one exception. Victual waste (not including plastics) may be
dKcharged from fixed or floating platforms located beyond 12 nautical miles from the nearest land if
such waste is passed through a comminuter or grinder meeting the requirements of 33 CFR 151 75
Section 151.75 requires that the grinders or comminuters must be capable of processing garbage SO that
it passes through a screen with openings no greater than 25 millimeters (approximately one inch) in
diameter.
6.0 SANITARY WASTES
S.I SANITARY WASTES SOURCES. VOLUMES AND CHARACTERISTICS
The sanitary wastes from offshore oil and gas facilities are comprised of human body wastes from
toilet, and urinals. The volume and concentration of these wastes vary widely with time, occupancy,
platform characteristics, and operational situation.
EPA compiled U.S. and international regulations governing the discharge of sanitary waste into
ocean waters from manned ships and manned fixed or floating platforms. International waters are
governed by MARPOL 73/78. Annex IV which deals specifically with the disposal of sewage from ships
The Federal Water Pollution Control Act (FWPCA) ง312 (33 U.S.C. 1322) administered/implemented
by U.S.EPA, provides the regulations and the standards to eliminate the discharge of untreated sewage
from vessels into waters of the U.S. and the territorial seas. The U.S. Coast Guard has established
regulations governing the design and construction of marine sanitation devices and procedures for
certifying that marine sanitation devices meet the regulations of the FWPCA (33 CFR Part 159 and 40
CFR Part 140).
Combined sanitary and domestic waste discharge rates of 3,000 to 13,000 gallons per day have
been reported.- Monthly average sanitary waste flow from Gulf Coast platforms was 35 gallons per day
based on discharge monitoring reports.12
6.2 SANITARY WASTES CONTROL AND TREATMENT TECHNOLOGIES
Therearetwoalternativestohandlingofsanitarywastesfromoffshorefacilities. Thewastescan
be treated at the offshore location, or they can be retained and transported to shore facilities for treatment
However, due to storage limitations on platforms, offshore facilities usually treat and discharge sanitary
X-37
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waste at the source. The treatment systems presently in use may be categorized as physical/chemical and
biological.
Physical/chemical treatment may consist of evaporation-incineration, maceration-chlorination, and
chemical addition. With the exception of maceration-chlorination, these types of units are often used to
treat wastes on facilities with small numbers of men or which are intermittently manned. The incineration
units may be either gas fired or electric. The electric units have been difficult to maintain because of
saltwater corrosion and heating coil failure. The gas units are not subject to these problems, but create
a potential source of ignition which could result in safety hazards. Some facilities have chemical toilets
which require hauling of waste and create odor and maintenance problems. Macerators-chlorinators have
not been used offshore but would be applicable to provide minimal treatment for small and intermittently
manned facilities.
The most common 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
chlorination tank. These biological waste treatment systems have proven to be technically and
economically feasible means of waste treatment at offshore facilities which have more than 10 occupants
and are continuously manned.
BPT for sanitary wastes from offshore facilities continuously manned by 10 or more persons
requires a residual chlorine content of 1 milligram per liter (and maintained as close to the limit as
possible). Facilities continuously manned by fewer than 10 persons or intermittently manned by any
number of persons are prohibited from discharging floating solids. These standards are based on end-of-
pipe technology consisting of biological waste treatment systems (extended aeration). The system may
include a comminutor, aeration tank, clarifier, return sludge system, and disinfection contact chamber.
Studies of treatability, operational performance, and flow fluctuations are required prior to application
of a specific treatment system to an individual facility. EPA has not identified any additional control
beyond BPT appropriate for this waste stream.
7.0 MINOR DISCHARGES
The term "minor" discharges is used to describe all point sources originating from offshore oil
and gas drilling and production operations, other than produced water, drilling fluids, drill cuttings, deck
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drainage, produced sand, well treatment^ completion and workover fluids, and sanitary and domestic
wastes. The following sections identify these discharges followed by a brief description.
7.1 BLOWOUT PREVENTER (BOP) FLUID
An oil (vegetable or mineral) or antifreeze solution (glycol) are used as hydraulic fluids in
blowout preventer (BOP) stacks during drilling of a well. The blowout preventer may be located om the
sea floor, and is designed to maintain the pressure in the well that cannot be controlled by the drilling
mud. Small quantities of BOP fluid are discharged periodically to the sea floor during testing of the
blowout preventer device.
7.2 DESALINATION UNIT DISCHARGE
This is the residual high-concentration brine discharged offshore from distillation or reverse
osmosis units used for producing potable water and high quality process water. The concentrate is similar
to sea water in chemical composition. However, as the name implies, anions and cations concentrations
are higher. This waste is discharged directly to the sea as a separate waste stream.
7.3 FIRE CONTROL SYSTEM TEST WATER
Seawater, which may be treated with a biocide, is used as test water for the fire control system
on the offshore platforms. This test water is discharged directly to the sea as a separate waste stream.
7.4 NON-CONTACT COOLING WATER
Non-contact, once-through water is used to cool crude oil, produced water, power generators,
and various other pieces of machinery on offshore platforms. Biocides can be used to control biofouling
in heat exchanger units. Non-contact cooling waters are kept separately and discharged directly to the
sea.
7.5 BALLAST AND STORAGE DISPLACEMENT WATER
Two types of ballast water are found in offshore producing areas: tanker and platform ballast.
Tanker ballast water can be either sea water or fresh water from the area where ballast was pumped into
the vessel. It may be contaminated with crude oil (or possibly some other cargo such as fuel oil), if the
vessel Is not equipped for segregated cargo and does not have segregated ballast tanks.
X-39
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Unlike tank ballast water, which may be from multiple sources and may contain added
contaminants, platform stabilization (ballast) water is taken on from the waters adjacent to the platform
and will, at worst, be contaminated with stored crude oil and platform oily slop water. Newly designed
and constructed floating storage platforms use permanent ballast tanks that become contaminated with oil
only in emergency situations when excess ballast must be taken on. Oily water can be treated through
the oil/water separation process prior to discharge.
Storage displacement water from floating or semi-submersible offshore crude oil structures is
composed mainly of seawater. 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 which comes in contact
with the oil can receive a small amount of dissolved aromatic constituents through 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. The interface water is usually treated through the oil/water
separator system before discharge.
7.6 BILGE WATER
Bilge water is a minor waste for floating platforms. Bilge water is seawater that becomes
contaminated with oil and grease and with solids such as rust, when it collects at low points in the bilges.
This bilge water is usually directed to the oil/water separator system used for the treatment of ballast or
produced water, or is discharged intermittently.
7.7 BOILER SLOWDOWN
Purges from boilers circulation waters necessary to minimize solids build-up are intermittently
discharged to the sea.
7.8 TEST FLUIDS .
Test fluids are discharges that would occur if hydrocarbons are located during exploratory drilling
and tested for formation pressure and content.
7.9 DlATOMACEOUS EARTH FILTER MEDIA
Diatoraaceous earth filter media are used to filter seawater or other authorized completion fluids
and then washed from the filtration unit.
X-40
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7.10 BULK TRANSFER OPERATIONS
Bulk materials such as barite or cement may be discharged during transfer operations.
7.11 PAINTING OPERATIONS
Discharges of sandblast sand, paint chips, and paint spray may occur during sandblasting and
painting operations.
7.12 UNCONTAMINATED FRESHWATER
Uncontaminated freshwater discharges come from wastes such as air conditioning condensate or
potable water during transfer or washing operations.
7.13 WATER FLOODING DISCHARGES
Oil fields that have been produced to depletion and have become economically marginal may be
restored to production, with recoverable reserves substantially increased, by secondary recovery methods.
The most widely used secondary recovery method is water flooding. A grid pattern of wells is
established, which usually requires downhole repairs of old wells or drilling of new wells. By injecting
water into the reservoir at high rates, a front or wall of water moves horizontally from the injection wells
toward the producing wells, building up the reservoir pressure and sweeping oil in a flood pattern.
Water flooding can substantially improve oil recovery from reservoirs that have little or no
remaining reservoir pressure. Treated seawater typically is used offshore for injection purposes.
Treatment consists of filtration to remove solids that would plug the formation, and deration. Dissolved
oxygen is removed to protect the injection pipeline system from corrosion. A variety of chemicals can
be added to water flooding systems such as flocculants, scale inhibitors, and oxygen scavengers. Biocides
are also used to prevent the growth of anaerobic sulfate-reducing bacteria, which can produce corrosive
hydrogen sulfide in the injection system. Discharges to the marine environment from water flooding
operations will include excess injection water and backwash from filtering systems.
7.14 LABORATORY WASTES
Laboratory wastes contain material used for sample analysis and the material being anatyzed.
The volume of this waste stream is relatively small and is not expected to pose significant environmental
problems. Freon may be present in laboratory waste. Because freon is highly volatile, it will not remain
X-41
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aqueous state for very long. The Agency is discouraging the discharge of chlorofluorocarbon to air
or water media.
in
7.15 MINOR WASTES VOLUMES AND CHARACTERISTICS
Information concerning the characteristics, discharge volumes, and the frequency of discharge
of these minor waste streams is limited. Table X-23 provides a range of discharge volumes for the minor
waste streams.26 Data concerning the characteristics and volumes of test fluids, diatomaceous earth filter
media, bulk transfer operations, and painting operations are not available.
TABLE X-23
MINOR WASTE DISCHARGE VOLUMES26
' Waste s . ""_
BOP fluid
Boiler blowdown
Desalination waste
Fire system test water
Noncontact cooling water
Uncontaminated ballast/bilge water
Water flooding
Test fluids
Diatomaceous earth filter media
Bulk transfer operations
Painting operations
Uncontaminated fresh water
Discharge Volume
67-314 bbl/day
0 - 5 bbl/day
typically < 238 bbl/day
24 bbl/test
7 - 124,000 bbl/day
70 - 620 bbl/day
up to 4,030 Ib solids/month
Unknown
Unknown
Unknown :
Unknown
Unknown
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8.0 REFERENCES
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1. ERT. Exploration and Production Industry Associated Wastes Report, prepared for API,
Document No. 0300-004-008, May 1988.
2. Stephenson, Dr. M.T. "Produced Sand: A Presentation for U.S. Environmental Protection
Agency." June 29, 1989.
3. Chemical Engineering Department, University of Tulsa. "Effluent Limitations for Onshore and
Offshore Oil and Gas Facilities - A Literature Survey," prepared for U.S. EPA Division of Oil
and Special Materials Control. May 1974.
4. Offshore Operators Committee. "Response to EPA Request for Additional Information, " letter
from J.F. Branch, Chairman to Ronald P. Jordan, U.S. EPA Office of Water. August 30, 1991.
5. Michael Parker, Exxon, New Orleans, personal communication with Joe Dawley, SAIC,
regarding Produced sand generation volumes and washing costs. September 16, 1992.
6. Don Evans, Conoco, personal communication with Joe Dawley, SAIC, regarding Produced sand
volumes reported in the OOC Produced Sand Survey. June 3, 1992.
7. Arctic Laboratories Limited, ESL Environmental Services Limited, and SKM Consulting Ltd.
"Offshore Oil and Gas Production Waste Characteristics, Treatment Methods, Biological Effects
and Their Applications to Canadian Regions," prepared for Environmental Protection Service
Water Pollution Control Directorate. April 1983.
8. American Petroleum Institute. "Comments of the American Petroleum Institute in Response to
U.S. Environmental Protection Agency's Proposed Effluent Limitations Guidelines and New
Source Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point
Source Category 56 Federal Register 10664-10715 (March 13, 1991)." May 13, 1991.
9. Continental Shelf Associates, Inc. "Produced Sand Discharge Monitoring Study, West Delta Area
Block 103 Platform "B" - Survey Report," prepared for Shell Offshore Inc., March 26, 1991.
10. Tom Randolph, Shell Offshore, Inc., personal communication with Joe Dawley, SAIC, regarding
the Shell produced sand discharge monitoring study. September 11, 1992.
11. Letter from R.J. Vallejo, Shell Offshore Inc. to DJ. Bourgeois, Minerals Management Service.
"Produced Sand Discharge Monitoring Study Interim Data Submittal." June 11, 1991.
12. Attachment to memo from Division Operations Manager Coastal Division, OSS 2280 to
Production Superintendents Coastal Division. "Cleaning Oily Tank Solids." September 17
1990.
13. Minerals Management Service, "Gulf of Mexico Sales 142 and 143: Central and Western
Planning Areas, Final Environmental Impact Statement, Volume I: Sections I through IV.C,"
November 1992.
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14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
U.S. Department of the Interior, Minerals Management Service Letter from DJ. Bourgeois,
Regional Supervision Field Operations. "Clarification of Letter to Lessees and Operators (LTLs)
dated November 20, 1990. December 11, 1990.
Frankenberg, W.G. and J.H. Allred. "Design, Installation, and Operation of a Large Offshore
Production Complex," 1st Annual Offshore Technology Conference, (Houston, 8/18-21/69).
Preprint No. OTC 1082, pp. H 117 - II 122, 1969 (V.2).
Garcia, J.A., "A System for the Removal and Disposal of Produced Sand." 47th Annual SPE
of AIME Fall Meeting (San Antonio, 10/8-11/72) Preprint No. SPE-4015, 1972.
Memorandum from Allison Wiedeman, Project Officer to Marv Rubin, Branch Chief.
"Supplementary Information to the 1991 Rulemaking on Treatment/Workover/Completion
Fluids," December 10, 1992,
American Petroleum Institute. "Detailed Comments on EPA Supporting Documents For Well
Treatment and Workover/Completion Fluids."
Parker, M.E., "Completion, Workover, and Well Treatment Fluids," June 29, 1989.
Hudgins, Charles M., Jr., "Chemical Treatments and Usage in Offshore Oil and Gas Production
Systems." Prepared for American Petroleum Institute, Offshore Effluent Guidelines Steering
Committee. September, 1989.
Envirosphere Company. Summary Report: Cook Inlet Discharge Monitoring Study: Workover,
Completion and Well Treatment Fluids, Discharge Numbers 017, 018 and 019, prepared for the
Anchorage, Alaska Offices of Amoco Production Company, ARCO Alaska, Inc., Marathon Oil
Company, Phillips Petroleum Company, Shell Western E&P Inc., Texaco Inc., Unocal
Corporation, and the U.S. EPA Region X, Seattle Washington, April 10, 1987 - September 10,
1987. ;
Wilkins, Glynda E., Radian Corporation. "Industrial Process Profiles for Environmental Use
Chapter 2: Oil and Gas Production Industry," for U.S. EPA, EPA-600/2-77-023b. February
1977.
Arctic Laboratories Limited, et. al., Offshore Oil and Gas Production Waste Characteristics,
Treatment Methods, Biological Effects and Their Applications to Canadian Regions, prepared for
Environmental Protection Services, April 1983.
U.S. Environmental Protection Agency. "Report to Congress, Management of Wastes from the
Exploration, Development and Production of Crude Oil, Natural Gas, and Geothermal Energy,
Volume 1, EPA/530-SW-88-003. December 1987. ;
Walk, Haydel and Associates, Industrial Process Profiles to Support PMN Review;: Oil Field
Chemicals, prepared for EPA, undated but received by EPA on 6/24/83.
SAIC, "Summary of Data Relating to Miscellaneous and Minor Discharges from Offshore Oil
and Gas Structures," prepared for Industrial Technology Division, U.S. Environmental Protection
Agency, February 1990. (Offshore Rulemaking Record Volume 118)
X-44
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27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
Meyer, Robert L. and Rene Higueras Vargas. "Process of Selecting Completion or Workover
Fluids Requires Series of Tradeoffs." Oil and Gas Journal. January 30, 1984.
Acosta, Dan. "Special Completion Fluids Outperform Drilling Muds. Oil and Gas Journal
March 2, 1981.
"World Oil's 1987 Guide to Drilling, Completion and Workover Fluids," World Oil. June 1987.
Hudgins, Charles, M., "Chemical Treatment and Usage in Offshore Oil and Gas Systems,"
prepared by Petrotech Consultants, Inc., September 1987.
Burns and Roe Industrial Services Corp., "Review of USEPA Region VI Discharge Monitoring
Report, Offshore Oil and Gas Industry," draft 1984.
Dalton, Dalton, and Newport, Assessment of Environmental Fate and Effects of Discharges From
Oil and Gas Operations, March 1985.
ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the THUMS Long Beach Company Agent for the Field Contractor Long beach Unit -
Island Grissom City of Long Beach - Operator," Draft, prepared for Industrial Technology
Division, U.S. Environmental Protection Agency, March 1990. (Offshore Rulemddng Record
Volume 113)
ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the Shell Western E & P, Inc. - Beta Complex," Draft, prepared for Industrial
Technology Division, U.S. Environmental Protection Agency, March 1990. (OffshoreRulemaldng
Record Volume 114)
Thomas, David J., et al., Offshore Oil and Gas Production Waste Characteristics, Treatment
Methods, Biological Effects and Their Applications to Canadian Regions, April 1983.
Envirosphere Company, Cook Inlet Discharge Monitoring Study: Deck Drainage. (Discharge
003), 10 April 1987 to 10 April 1988, prepared for the U.S. EPA Region X. No date.
SAIC, "Trip Report for the Sampling of the Membrane Filtration Unit at the Marathon Oil Co. -
Eugene Island 349-B Platform," prepared for Engineering and Analysis Division, U.S.
Environmental Protection Agency, January 13, 1993.
Hoppy, Brian K., SAIC, telephone correspondence with Fred Duthweiler, UNOCAL, 12 June
1992 concerning deck drainage treatment practices in Cook Inlet, AK.
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 USEPA, 1982.
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 (Prepaired
for U.S. EPA Region X), no date.
X-45
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41. U.S. EPA, Development Document for Interim Final Effluent Limitations Guidelines and New
Performance Standards for the Oil and Gas Extraction Point Source Category, EPA 440/1-
76/055-a, Sept. 1976.
42. 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 (Proposed),
EPA 440/1-85/055, July 1985.
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SECTION XI
COST AND POLLUTANT LOADING DETERMINATION -
DRILLING FLUIDS AND DRILL CUTTINGS
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1.0 INTRODUCTION
This section presents costs and pollutant reductions for the final set of proposed regulatory options
for drilling fluids and drill cuttings. Compliance costs were developed for each treatment/control option
for the Gulf of Mexico and offshore of California and Alaska. Compliance costs were not developed for
the Florida and North Atlantic OCS Planning areas due to presidential moratoria on oil and gas leasing
and development in these areas. Although not specifically developed, compliance costs in these areas are
considered to be comparable to the compliance costs incurred in the California region.
2.0 OVERVIEW OF METHODOLOGY
To evaluate the compliance costs and pollutant removals associated with regulatory options
considered in this rulemaking the following information was used:
Number of offshore wells that will be drilled in the 15-year period following
promulgation of this rule in three geographic regions: Gulf of Mexico, California, and
Alaska.
Typical "model" wells to predict volumes of drilling wastes.
Characteristics of the drilling waste including additives, volumes and composition.
Drilling wastes monitoring, transportation, and disposal costs.
The data were entered into computer models designed to predict industry-wide compliance costs
and pollutant removals for the various regulatory options. No distinction was made between BAT and
NSPS options, because there are no, or minimal, differences in the compliance costs for existing and new
sources of drilling waste. Compliance costs were computed for the three geographic regions where
offshore drilling was projected (Gulf of Mexico, California, and Alaska). In characterizing the offshore
drilling industry, EPA developed two drilling activity scenarios that project the number of wells drilled
for the 15-year period following promulgation of this rule. The two scenarios of future drilling activity
XI-1
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on offshore oil and gas leasing and development. See Section III.2.2 for a discussion on the presidential
and congressional moratoria. The unconstrained scenario takes into account potential drilling activities
Discharges of drilling fluids and drill cuttings from offshore drilling projects in the Gulf of
Mexico, California, and Alaska are regulated by both individual and general NPDES permits. The
XI-2
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are: the "restricted" or "constrained" scenario and the "unrestricted" or "unconstrained" scenario. 'The
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constrained scenario accounts for less drilling activity due to the presidential and congressional moratoria
in the areas that have been excluded from leasing and development by the presidential and congressional ; _
moratoria, hi particular the Atlantic Ocean OCS planning areas and offshore California OCS planning 1
areas. Because EPA expects that existing moratoria will remain in place, and based on a review of the _^
current offshore drilling activity, EPA considered the constrained scenario a more accurate projection of |
future activity and thus, the constrained scenario is the basis for determining compliance costs and
pollutant removals for this final rule. I
2.1 CURRENT NPDES PERMIT LIMITATIONS |
NPDES permits include additional limitations on drilling fluid discharges that are more stringent than the _
BPT limitations that were promulgated in 1979. The BPT limitations on drilling fluids prohibit the |
discharge of oil-based muds and the discharge of free oil. The additional constraints imposed by the ^
general NPDES permits issued for offshore drilling operations in the Gulf of Mexico (EPA Region VI), |
California (EPA Region IX), and Alaska (EPA Region X) represent limitations established by regional
permit writers based on both BPT and best professional judgment (BPJ) of BAT-level technology. BPJ |
requirements are thus considered to represent current discharge and waste handling practices for the
offshore drilling industry. BPJ limitations represent the pollutant removals and the costs that are incurred g
by drilling operations under the NPDES permit limitations. These limitations, as they are currently
enforced, are summarized hi Table ffl-l for the three geographic areas. BPJ restrictions for drilling |
fluids were considered to represent the baseline requirements from which incremental costs and pollutant
removals for this rule were determined for drilling fluids. Since the NPDES permits do not place any |
additional limitations on drill cuttings, BPT limitations on the discharge of free oil represent current
practices and are used as the baseline requirements from which incremental costs and pollutant removals
for this rule were determined for drill cuttings.
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8
579
3
' 3
585
Total
715
32
12
759
The constrained scenario projects that an average of 759 new wells will be drilled annually over
the next 15 years. As can be seen in Table XI-1, approximately 9 percent of all wells are projected to
be drilled within 3 miles from shore, approximately 11 percent of all wells are projected to be drilled
within 4 miles from shore, approximately 15 percent of all wells are projected to be drilled within 6 miles
from shore, and approximately 23 percent of all wells are projected to be drilled within ,8 miles from
shore.
3.2 DRILLING WASTE VOLUMES
The volumes of drill waste (drilling fluid and drill cuttings) generated per well were calculated
based on muds and cuttings generation rates and on well depth. The methodology used in determining
these two components and hi determining the total drill waste generated per well are presented La the
following paragraphs.
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The methodology used for estimating the volume of drilling fluid and drill cuttings discharged
is based on the volumes generated from exploratory wells drilled in the Gulf of Mexico in 1981. Data
of muds and cuttings generation rates for a 10,000 foot well and an 18,000 foot well is presented in the
report prepared by the OOC entitled Alternative Disposal Methods for Muds and Cuttings in the Gulf of
Mexico and Georges Bank,1 For the two wells drilled, the report provides hole size diameter per depth
intervals, muds and cuttings discharge volumes per depth intervals, and total volumes of muds and
cuttings discharged. Table VIt-1 in Section VII-2 presents these data. These data were used to determine
the relationship between the theoretical hole volume and the volume of muds and cuttings discharged.
EPA estimated the cuttings generation rate for both the shallow and deep wells to be equal to one
theoretical hole volume. Based on the findings of the OOC report for drilling fluids, EPA estimated the
shallow well generation volumes to be equal to 4.7 times the theoretical hole volume and the deep well
generation volumes equal to 3.9 times the theoretical hole volume.
The estimated cuttings and fluids generation rates were then applied to estimated or "model" well
volumes to estimate the industry-wide volumes of drill cuttings and drilling fluids generated per well.
EPA developed model wells for each region based on the average depth of wells drilled in that region.
The average well depth was determined for each region based on five years (1985 through 1989) of
industry drilling data.2 The average well depth value (referred to as the "shallow well" in this discussion)
represents the ratio of total footage drilled to the total number of wells drilled for the period. The
average well depths were found to be drilled approximately 10,000 linear feet. Since deep wells require
larger diameter boreholes (thus generating a greater volume of drill waste than a smaller diameter
.borehole over a particular depth interval), the percentage of wells drilled in the five-year period which
exceed the depth of the average well for each region was determined (referred to as the "deep well").
Table XI-2 presents the well depth, mud volume, and cuttings volume estimated for the shallow
and deep wells drilled in the Gulf of Mexico, California, and Alaska.
TABLE XI-2
MODEL WELL CHARACTERISTICS2
Shallow
Well
Deep Well
} ^ Model Well
Well Depth
Mud Volume
Cuttings Vol.
Well Depth
Mud Volume
Cuttings Vol.
Percentage of Wells Greater Than
Average Well Depth
Gulf of Mexico
10,559 feet
6,938 bbl/weU
1,475 bbl/well
13,037 feet
9,752 bbl/well
2,458 bbl/well
49%
California
7,607 feet
5,939 bbl/well
1,242 bbl/well
10,082 feet
6,777 bbl/well
1,437 bbl/well
42%
Alaska
10,633 feet
6,963 bbl/well
1,480 bbl/well
12,354 feet
9,458 bbl/well
2,413 bbl/well
59%
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3.3 DRILLING FLUID CHARACTERISTICS
EPA selected three types of drilling fluids to represent the most common types of drilling fluids
used in the offshore industry. Table XI-3 presents the characteristics of these muds. For the purposes
of determining the pollutant loadings and the barite usage, EPA selected a single density mud which
would represent the average mud density over the total drilling project, from the initial seawater/spud
mud to the weighted mud used towards the final well depth. Based on a review of discharge monitoring
reports from the Gulf of Mexico and communications with the industry, EPA selected an 11 pound per
gallon mud to have the average characteristics (density) of the mud system used over the entire drilling
project.3
TABLE XI-3
DRILLING FLUIDS COMPOSITION3
Wafer-Based Mud Without Oil Additive (0-10,000 ft)
Component
Seawater
Bentonite
Barite
Drill Solids
Total:
Estimated TSS
Dry Mud
Composition (lb/bbl) -
303
20-
98
40
461
153
158
Water-Based Mud With Oil Additive fO-14T000 ft} ~~~
" ;, Component
Seawater
Bentonite
Barite
Drill Solids
Mineral Oil
Total:
Estimated TSS
Dry Mud
, Composition (Ih/bbI)
294
20
98
40
9 (3% by volume)
461
153
167
-- ^ Oil-Based Mud (10,00044,000 ft)
Component
Seawater
Bentonite
Barite
Drill Solids
Mineral Oil
Total:
Estimated TSS
Dry Mud
Composition (lb/bbl)
124
20
98
40
179 (60% by volume)
461
153
337
XI-5
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3.4 DRILL CUTTINGS CHARACTERISTICS
Drill cuttings were assumed to have a density of 543 pounds per barrel and contain 5 percent
drilling fluid.4 For the purpose of the pollutant loading analysis for this rule, the only source of
hydrocarbons or metals in the drill cuttings is the residual drilling fluids.
3.5 LUBRICITY
In 1983 and 1984, the industry surveyed 11 major drilling contractors operating in the Gulf of
Mexico to characterize: the use of hydrocarbons as lubricity agents in water-based muds and the usage
of diesel and mineral oil as spotting fluids.
Data from the 1984 survey indicate that 12 percent of all wells drilled using a water-based mud
used hydrocarbons as a lubricity agent. Of these, approximately 67 percent used mineral oil as the
lubricity agent and 33 percent used diesel oil.5 This information was used to quantify the amounts and
identify the types of oil currently being used in the offshore drilling industry.
3.6 STUCK PIPE INCIDENTS
The OOC Spotting Fluid Survey characterized stuck pipe incidents and the type of pills used to
free stuck pipes. See Section V.2.3 for a discussion about the survey. Data from the survey indicate that
22.1 percent of all wells drilled with a water-based mud experienced a stuck pipe where a pill was needed
to free the drill string.6 This information was used to quantify the volumes of oil used in spotting fluids.
3.7 MINERAL AND DIESEL OIL USAGE
The substitution of mineral oil for diesel oil is a means for compliance with the BPT and BPJ
limitations. Prior to the promulgation of BPT, operators primarily used diesel oil as a lubricity agent or
for freeing stuck pipe. However, since the promulgation of the BPT prohibitions on the discharges of
free oil, the usage of diesel oil has drastically reduced to the point where currently diesel oil is seldom
used. Table XI-4 presents the results from two industry surveys characterizing the usage of diesel and
mineral oil as lubricity agents and as spotting fluids. The API Hydrocarbon Usage Survey,5 "1984
Survey," examined diesel/mineral oil usage in spotting fluids in 1983 and 1984; and examined
diesel/mineral oil usage as a lubricity agent in 1984. The OOC Spotting Fluid Survey,6 "1986 Survey,"
compiled diesel/mineral oil usage hi spotting fluids for the years 1983 through 1986.
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TABLE Xl-4
MINERAL AND DIESEL OIL USAGE |
1
STUDY
19845
19866
Lubricity Agent
Diesel Oil
33%
Not Surveyed
Mineral Oil
67%
Not Surveyed
Spotting Fluid
Diesel Oil
79%
59%
Mineral Oil
21%
41%
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For the purpose of estimating the impact of BAT and NSPS limitations to the industry, EPA
assumed the post-BPT diesel usage rate to be equal to zero percent and that all facilities currently use only
mineral oil for lubricity agents and spotting fluids. Diesel usage for those operators participating in the
Diesel Pill Monitoring Program (DPMP) has not been factored into the post-BPT diesel usage estimates
since, the DPMP was a limited NPDES permit provision for a special test case. Table XI-5 presents the
organic constituents in the mineral oil used to calculate the pollutant loadings for this rulemaking.
TABLE XI-5
ORGANIC CONSTITUENTS IN MINERAL OIL TYPE A7
Organic Constituent
Benzene
Napthalene
Fluorene
Phenanthrene -
Phenol
Non-Conventional Organics
Concentration (mg/ml)
ND
0.05
ND
ND
ND
30.51
Notes:
(1) ND = Not Detected
(2) Non-conventional organics include 30.0 mg/ml alkylated benzenes (include Ct through C6 alkyl
homologues), 0.28 mg/ml alkylated naphthalenes and 0.23 mg/ml total biphenyls (Q through Cs
alkyl homologues).
3.8 BARITE CHARACTERISTICS
Barite is the primary source of metals (cadmium, mercury, and other priority pollutants of
concern) in drilling fluids. The characteristics of the raw barite used will determine the concentrations
of metals in the drilling fluid. The concentrations of cadmium and mercury are directly related to the
concentrations of other priority pollutants of concern in barite.8 Current NPDES permits in Regions EX
XI-7
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and X have limitations on the concentrations of cadmium and mercury in the raw (or stock) barite. On
November 19, 1992 (57 FR 54642) EPA Region VI issued an NPDES general permit for the central and
western Gulf of Mexico OCS. This permit places limitations on mercury and cadmium in the stock
barite. Stock barite that meets metals limitations is referred to as "clean" barite. For the purposes of
calculating the BPJ baseline metals concentrations in drilling fluids, the metals concentrations of clean
barite was used for California and Alaska and dirty barite was used for the Gulf of Mexico. Dirty barite
was used to develop the baseline for the Gulf of Mexico because the NPDES general permits did not
include barite limitations at the tune of the analysis. The difference in the characteristics of the drilling
fluids between the Gulf of Mexico and California/Alaska is demonstrated in the API/USEPA Metals
Database. A statistical analysis of metals concentrations in spent drilling fluids shows higher
concentrations of cadmium and mercury hi drilling fluids from the Gulf of Mexico than from offshore
Alaska and California.8
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The mean metals concentrations for "clean" and "dirty" barite are presented in Table XI-6. The
metals concentrations represent averages of untransformed data from two datasets: The 15 Rig Study
from the Gulf of Mexico and Region 10 Discharge Monitoring Report Data.8 The metals concentrations
of drilling fluids from the Gulf of Mexico are considered to represent those of dirty barite, and the metals
concentrations from Region 10 are considered to represent those of clean barite. Where no concentration
data were given for an analyte in the Region 10 data, the concentration of the analyte from the Gulf of
Mexico dataset was incorporated. The barium concentrations reported hi Table XI-6 are calculated from
the total pounds of barite in the drilling fluid. The amount of barite per barrel of drilling fluid is 98
pounds, as presented in Table XI-3. The barite was assumed to be pure barium sulfate (100% Bas04) and
the barium sulfate was assumed to contain 58.8 percent (by weight) barium.
For the purposes of calculating the pollutant loadings for the BAT and NSPS options, clean barite
was substituted for dirty barite for drilling operations in the Gulf of Mexico. Clean barite was not
substituted for duty barite where the discharges of drilling fluids are prohibited (projects using oil based-
muds and within zero discharge areas) or in areas where clean barite is required by NPDES discharge
permits (offshore California and Alaska). For those drilling operations requiring substitution of clean
barite for dirty barite (Gulf of Mexico) a substitution cost of $13.50 per ton of barite (1986$) was
incurred.9
In calculating the BCT pollutant loadings and costs, clean barite substitution was not used because
the metals limitations are not considered and/or accounted for as conventional pollutants.
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TABLE XI-6
METALS CONCENTRATIONS IN BARITE8
Metal
Cadmium
Mercury
Aluminum
Antimony
Arsenic
Barium*3'
Beryllium
Chromium
Copper
Iron
Lead
Nickel
Selenium
Silver
Thallium
Tin
Titanium
Zinc
"Dirty" Barite Concentration
{mg/kg)
2.3
0.7
9,069.9
5.7
12.0
359,747.0
0.7
561.4
39.9
15,344.3
66.7
13.5
1.1
0.7
1.2
14.6
87.5
200.5
"Clean11 Barite Concentration
(rag/kg)
1.1
0.1
9,069.9
5.7
7.1
359,747.0
0.7
240.0
18.7
15,344.3
35.1
13.5
1.1
0.7
1.2
14.6
87.5
200.5
3.9 ONSHORE DISPOSAL VOLUMES/TOXICITY TEST FAILURE RATES 1
The amount of drill waste brought to shore for disposal is a function of the compliance failure H
rates. The likelihood of drilling wastes from the model well failing either the static sheen test or the I
toxicity limit was estimated based on data and information compiled by the industry. EPA assumed that I
ill oil-based drilling fluids would fail the sheen test. According to industry sources, when oil is added 1
to water-based muds to increase the lubrication properties of the mud, there is an average 56 percent
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probability that the resultant mud will fail the toxicity limit of 30,000 ppm.10 Additionally, EPA
previously estimated the likelihood of drilling wastes from a "model well" failing the proposed static
sheen test and toxicity limit. Because no public comments addressing these failure rates have been
submitted, they are still assumed representative of the industry. Table XI-7 shows the failure rates, as
they were presented in the March 13, 1991 proposal (56 FR 10664), and as they have been used to
predict volumes of muds and cuttings requiring onshore disposal.
XI-9
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TABLE XI-7
TOXICITY/STATIC SHEEN TEST FAILURE RATES10
JDrill Waste
Water-based mud; no oil
Water-based mud; with spot
Water-based mud; with lubricity
Water-based mud; with spot and lubricity
Oil-based mud
Cuttings - water-based mud
Cuttings - oil-based mud
Fail Sheen(%)
0
0
0
0
100
0
100
Fail Toadcity(%)
1
33
33
56
N/A
N/A
N/A
The assumption was made that each drilling operation will take a minimum of two mud samples
to satisfy the requirements of the NPDES permit. Each toxicity test was estimated to cost approximately
$1,000. The cost of the visual sheen test is negligible and EPA considered the cost of the static sheen
test is negligible hi comparison with the cost of the bioassay test.
Under the current BPJ limitations and based on failure rates of the toxicity test, 12 percent of all
drilling fluids are disposed of onshore due to noncompliance and 2 percent of all drill cuttings are
disposed of onshore due to noncompliance (see Section XI-7).
3.10 ONSHORE DISPOSAL COSTS OF DRILLING WASTES
Drilling wastes disposal costs include: the gate costs charged by the onshore disposal facility,
the handling cost, the transportation cost, the container rental cost, the costs associated with rig downtime
(where applicable), and the capital cost incurred to retrofit a typical rig for additional storage space
(where applicable).11
Three estimates of total 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
retrofitting the platform to provide additional storage capacity between shipments. EPA assumed that the
majority of the existing platforms and drilling rigs would be retrofitted and that new structures would be
designed to have sufficient storage space. Because retrofitting existing platforms is the easiest and safest
method to provide additional storage space and minimizing drilling downtime is more economical for
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the industry, EPA predicted that 80 percent of the existing platforms and/or rigs will be modified for
larger storage capacity. EPA assumed that 20 percent of the existing platforms and/or rigs will not be
retrofitted because of structural limitations. Some of the older rigs have limited space and are already
at maximum loading (weight) conditions and retrofitting would be technically infeasible. The capital costs
associated,with retrofitting an offshore rig with additional storage capacity (approximately 500 barrels)
and deck space (approximately 500 ft2) to accommodate storage of muds and cuttings are $19,000 for the
installation of a drilling mud storage tank and $ 125,000 for additional deck space (1986$). The additional
deck space would accommodate four full 25 barrel cuttings containers and a 500 barrel mud storage tank.
An important factor in developing total disposal costs for muds and cuttings from platforms where
retrofitting is not a viable solution is the downtime cost incurred as a result of adverse weather conditions.
Depending on the available storage space and drilling waste generation rate, the inability to unload muds
and cuttings when generated could possibly result in a temporary shutdown of the drilling operation.
Based on significant wave height data supplied by the National Oceanic and Atmospheric Administration
(NOA.A), downtime costs were estimated for maximum significant permissible wave heights of 6 and 10
feet. These wave heights were assumed to be the maximum allowable wave conditions for safe loading
operations. For the costing scenario with no retrofit of storage capacity, EPA"projected that 10 percent
of the wells would incur downtime costs under 6 feet and 10 feet wave conditions, respectively.
Table XI-8 presents the weighted average onshore disposal costs for muds and cuttings. The costs
include costs for retrofitting 80 percent of the drilling rigs and platforms and downtime costs for the 20
percent of the drilling projects that could not increase the storage capacity due structural limitations.
TABLE XI-8
DRILL WASTE ONSHORE DISPOSAL COSTS (1986 $/BARREL)
Gulf of Mexico
Pacific
Alaska
Prilling Fluids
21.29
23.50
26.99
Drill Cuttings
23.53
28.52
29.26
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3.11 CONTAMINANT REMOVAL
In determining pollutant removals, specific pollutants were selected for evaluation based on their
consistently significant presence in drilling wastes from offshore oil and gas operations. Reductions of
pollutants being discharged to the surface waters are a result of: the no free oil limitation, the metals
limitation, and any zero discharge requirements. Removals are considered direct or incidental. The
direct removals are those pollutant removals which are targeted by the limitation. Incidental removals
are those pollutant removals that are a result of the implementation of the limitation but not specifically
targeted by the limitation. The direct removals are organic pollutants associated with diesel oil (and
present hi mineral oil), total suspended solids, oil and grease, cadmium, and mercury. Table XI-9
presents the direct and incidental pollutants as they pertain to this rulemaking.
TABLE XI-9
DIRECT AND INDIRECT POLLUTANTS AS DEFINED BY THIS RULEMAKING
Direct Discharges
Priority
Benzene
Naphthalene
Fluorene
Phenanthrene
Phenol
Cadmium
Mercury
Conventional
TSS
oa
Incidental Discharges
Priority
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Other
Aluminum
Barium
Iron
Tin
Titanium
Non-conventional
Organics
4.0 BCT OPTIONS CONSIDERED
The following options for drilling fluids and drill cuttings were evaluated as BCT control and
treatment options for the final rule:
Option 1: "3 Mile Gulf/California" - All regions except offshore Alaska would be
prohibited from discharging drilling fluids and drill cuttings from all wells located within
three miles from shore. All wells located beyond three miles from shore as well as all
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wells being drilled offshore Alaska, would be permitted to discharge drilling fluids and
drill cuttings that are in compliance with the no discharge of free oil limitation as
determined by the static sheen test.
Option 2: "8 Mile Gulf/3 Mile California" - Zero discharge for all wells in the Gulf
of Mexico located within eight miles from shore and zero discharge for all wells offshore
California located within three miles from shore. All wells located beyond eight miles
from shore in the Gulf of Mexico, beyond three miles from shore in California, arid all
wells drilled offshore Alaska are permitted to discharge drilling fluids and drill'cuttings
that are in compliance with the no discharge of free oil limitation as determined by the
static sheen test.
Option 3: "Zero Discharge Gulf/California" - Zero discharge for all wells located in
the Gulf of Mexico and offshore California. All wells being drilled offshore Alaska
permitted to discharge drilling fluids and drill cuttings that are in compliance with the no
discharge of free oil limitation as determined by the static sheen test.
Option 4: "4 Mile Gulf/California" - All regions except offshore Alaska would be
prohibited from discharging drilling fluids and drill cuttings from all wells located within
four miles from shore. All wells located beyond four miles from shore as well as all
wells being drilled offshore Alaska, would be permitted to discharge drilling fluids and
drill cuttings that are in compliance with the no discharge of free oil limitation as
determined by the static sheen test.
Options: "6 Mile Gulf/California" - All regions except offshore Alaska would be
prohibited from discharging drilling fluids and drill cuttings from all wells located within
six miles from shore. All wells located beyond six miles from shore as well as all wells
being drilled offshore Alaska, would be permitted to discharge drilling fluids and drill
cuttings that are in compliance with the no discharge of free oil limitation as determined
by the static sheen test.
Option 6: "8 Mile Gulf/California" - All regions except offshore Alaska would be
prohibited from discharging drilling fluids and drill cuttings from all wells located within
eight miles from shore. All wells located beyond eight miles from shore as well as all
wells being drilled offshore Alaska, would be permitted to discharge drilling fluids and
drill cuttings that are in compliance with the no discharge of free oil limitation as
determined by the static sheen test.
In referring to the options considered for control of drilling fluids and drill cuttings, the Gulf of
Mexico, California and Alaska regions are used in the option descriptions and accompanying discussion.
Use of these regions in this manner is only a "shorthand" way of referring to regulatory packages and
does not exclude other geographic areas from coverage under this rule. For the BCT, BAT and NSPS
limitations under this rule, all offshore areas other than offshore California and Alaska, i.e. offshore
Florida, Oregon, Washington, and the Atlantic Coast, would be required to comply with the limitations
established for the Gulf of Mexico.
XI-13
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4.1 BAT AND NSPS OPTIONS
Six options were considered for BAT and NSPS control and treatment of drilling fluids and drill
cuttings for the final rule. These options set BAT and NSPS limitations identical to BCT limits with
respect to areas of zero discharge for drilling fluids and drill cuttings. BAT and NSPS limits differ from
BCT limits in that they place additional limitations on the discharge of priority and non-conventional
pollutants for areas (greater distances from shore) in which discharges are permissible. These limitations
are being placed on the drill cuttings as well as the drill fluids because the data show that drilling fluid
adheres to cuttings and is discharged along with the drill cuttings. The same pollutants found in drilling
fluids are thus found on the drill cuttings.
The limitations for the permissible discharges (e.g., those facilities not covered by the zero
discharge limitations) consist of four basic requirements: (1) toxicity limitation set at 30,000, ppm in the
suspended particulate phase; (2) a prohibition on the discharge of diesel oil; (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
3 mg/kg and 1 mg/kg, respectively. The following paragraphs discuss the rationale behind these
limitations.
The purpose of the toxicity limitation is to encourage the use of water-based or other low toxicity
drilling fluids and the use of low-toxicity drilling fluid additives. The Agency has considered the costs
of product substitution and finds them to be acceptable for this industry, resulting in no barrier to iuture
entry. These standards are not expected to have any adverse non-water quality environmental impacts.
Where the toxicity of the spent drilling fluids and cuttings exceeds the LC50 toxicity limitation, the
method of compliance with this option would be to transport the spent fluid system to shore for either
reuse or land disposal.
The toxicity limitation would apply to any periodic blowdown of drilling fluid as well as to bulk
discharges of drilling fluids and cuttings systems. The term "drilling fluid systems" refers to the major
types of materials (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 spent drilling fluids occur when such
systems are changed during the drilling of a well or at the completion of a well.
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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 percent of actual well footage (not total vertical depth) has been
drilled and up to and including the time of discharge. This would allow time for a sample to be collected
and analyzed by bioassay and for the operator to evaluate the bioassay results so that the operator will
have adequate time to plan for the final disposition of the spent drilling fluid system. For example, if
the bioassay test is failed, the operator could then anticipate and plan for 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 prior to receiving analytical results, although the
operation would be subject to compliance with the effluent limitations regardless of when self monitoring
analyses are performed. The prohibition on discharges of free oil and diesel oil would apply to all
discharges of drilling fluid at any time.
Diesel oil and free oil serve as "indicators" of toxic pollutants, and thus these discharges are
prohibited by this rule. The discharge of diesel oil, either as a component in an oil-based drilling fluid
or as an additive to a water-based drilling fluid, would be prohibited under this limitation. Diesel oil will
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:
(1) use mineral oil instead of diesel oil for lubricity and spotting purposes; or (2) transport to shore for
recovery of the oil, reconditioning of the drilling fluid for reuse, and land disposal of the drill cuttings.
EPA believes that in most cases substitution of mineral oil will be the method of compliance with the
diesel oil discharge prohibition. Mineral oil is a less toxic alternative to diesel oil and is available to
serve the same operational requirements. Low toxicity mineral oils and other drilling fluid systems, such
as polyolefm, vegetable oil and synthetic hydrocarbon-based fluids are available as substitutes for diesel
oil and continue to be developed for use in drilling systems.
XI-15
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Free oil is being used as an "indicator" pollutant for control of priority pollutants, including
benzene, toluene, ethylbenzene, and naphthalene.
Cadmium and mercury will be regulated at a level of 3 and 1 mg/kg, respectively, in the stock
barite. This is not an effluent limit to be measured at the point of discharge but a standard pertaining to
the barite used in the drilling fluid compositions. These two toxic metals will be regulated to control the
metals content of the barite component of any drilling fluid discharges. Compliance with this requirement
will involve use of barite from sources that either do not contain these metals or contain the metals at
levels below the limitation.
5.0 OPTION EVALUATIONS
An analysis of each regulatory option was conducted to determine:
Cost incurred by industry to comply with the regulation.
Volume and percent of drilling waste requiring onshore disposal.
Reduction of pollutants discharged to surface waters.
Number of "well-equivalents" affected by the regulation. A "well-equivalent" is an
artificial measurement which is equal to the volume of one model well.
To develop the compliance costs and pollutant removals for each option several assumptions were
made about the drilling operation. Several of these assumptions were presented in Section XI-3, but they
are presented here hi tabular form for clarity. The assumptions used to characterize the industry for a
typical drilling scenario, diesel and mineral oil usage, clean and dirty barite compositions, and pollutant
concentrations in drilling fluids and cuttings are presented in Table XI-10.
The remainder of this section discusses the calculation of costs and pollutant loadings for each
regulatory option considered. Tables XI-15 through XI-18, located in Section XI.7, present the results
of all pertinent calculations.
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TABLE XI-10
INDUSTRY-WIDE DRILLING ASSUMPTIONS
1) Typical Prilling Scenario
a) 88% of all wells use water-based mud without lubricity for the first 10,000 ft.5
b) 12% of all wells use water-based mud with mineral oil as a lubricity agent for the first 10,000 ft.5
c) 15% of all deep wells use oil-based mud for depths greater than 10,000 ft.12
d) 85% of all deep wells use water-based mud with mineral oil lubricity for depths greater than 10,000 ft.12
e) 22% of all wells experience stuck pipe between 8,000 ft. and 10,000 ft or the average well depth.6 Mineral oil
pills are used to free the pipe.
f) 22% of all deep wells experience stuck pipe between 12,000 ft. and the final well depth.6 Mineral oil is used
to free the pipe.
g) 35 days are needed to drill a model well. Of this, 20 days are spent drilling.
h) 5% of mud volume is retained on cuttings.4
^^^^i^^^^^^^^^^^^^
a) Diesel oil is not currently used in drilling operations either for lubricity or as a pill.
b) Mineral oil for lubricity equals 3% of mud volume.
c) Idineral oil for pill equals 100 bbl: 50% is retained in mud and 50% is retained on cuttings.
d) Oil-based muds contain 60% by volume mineral oil.
e) Cost to substitute mineral oil for diesel oil is $2/gallon."
a) Mercury and cadmium dry weight concentrations in drilling fluids where "dirty barite" was used have been
estimated from industry data to be 0.7 and 2.3 mg/kg on dry weight basis, respectively.8
b) Mercury and cadmium dry weight concentrations in drilling fluids where "clean barite" was used have been
estimated from industry data to be 0.1 and 1.1 mg/kg, respectively.8
c) All facilities in California and Alaska were using "clean" barite in order to comply with their respective
NPDES permits until die most recently issued permit for Region VI OCS general permit for the central and
western Gulf of Mexico was issued. Drilling operations in the Gulf of Mexico use "dirty" barite because this
permit was so recently promulgated, these limits were not taken into account in establishing the baseline.
d) Cost to substitute clean barite in the Gulf of Mexico is $13.50 per ton of barite.9
5.1 BPT AND BPJ BASELINE
To determine the incremental compliance costs and pollutant removals for the BCT, BAT, and
NSPS options, the "baseline" compliance costs and pollutants for the BPT and BPJ limitations for drilling
fluids and drill cuttings are necessary.
) 5.1.1 BPT Baseline: Drilling Fluids
BPT. limitations on drilling fluids prohibit the discharge of oil-based muds and free oil, as
determined by the visual sheen test. The costs incurred by industry to comply with BPT consist of;
(1) transportation costs and onshore disposal costs for all oil based muds and (2) a product substitution
cost to replace diesel oil with mineral oil to comply with the BPT no discharge of free oil limitation.
XI-17
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The onshore disposal costs are based on the fact that fifteen percent of all deep wells use oil-based
muds for depths greater then 10,000 feet. The computer model determined the volumes of oil-based
muds generated from deep wells over 10,000 feet and the onshore disposal costs presented in Section
Xt.3.10 were used to calculate the costs incurred due to the zero discharge limitation on oil-
based muds. The pollutant reductions associated with this limitation are based on the volumes of oil
(organic pollutants) and TSS transported to shore for treatment and/or disposal. The pollutant reductions
were calculated using the total volume (weight) of drilling fluid transported to shore and the
characteristics (oil content and TSS concentration) of the drilling fluid.
Product substitution costs are based on the fact that to comply with the BFF no discharge of free
oil limitation, operators will substitute mineral oil for diesel oil where oil is used as a lubricity agent in
water-based muds and as a spotting fluid for freeing stuck pipe. EPA determined the costs of substituting
mineral oil for diesel to be $2 per barrel.13 This substitution cost is based on the increase in the purchase
cost of the mineral oil over diesel oil plus the cost to provide and maintain additional storage facilities
for the mineral oil on the platform. The total costs incurred due to product substitution are calculated
based on the total oil used for lubricity and spotting fluids and the cost per gallon of substituting mineral
oil for diesel oil. There are no calculable pollutant removals due to product substitution.
5.1.2 BPT Baseline: Drill Cuttings
BPT limitations on drill cuttings prohibit the discharge of free oil, which indirectly prohibits the
discharge of cuttings from oil-based muds. The costs incurred by industry to comply with BPT consist
of transportation costs and onshore disposal costs for cuttings from oil based muds.
The onshore disposal costs are based on the fact that fifteen percent of all deep wells use oil-based
muds for depths greater then 10,000 feet. The computer model determined the volumes of cuttings
generated from oil-based muds generated from deep wells over 10,000 feet and the onshore disposaJ costs
presented in Section XI.3.10 were used to calculate the costs incurred due to the no discharge of free oil
limitation. The pollutant reductions associated with this limitation are based on the volumes of oil
(organic pollutants) and TSS transported to shore for treatment/disposal. The pollutant reductions were
calculated using the total volume (weight) of cuttings transported to shore and the oil content of the
residual drilling fluid remaining on the cuttings.
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5.11.3 BPJ Baseline: Drilling Fluids
The BPJ limitations for drilling fluids in Region VI (Gulf of Mexico) require compliance with
a toxicity limitation of 30,000 ppm in the suspended particulate phase of the drilling fluid and a
prohibition on the discharge of diesel oil in addition to the BPT limitations. The compliance costs and
pollutant loadings incurred by industry to comply with the BPJ limitations are due to increased onshore
disposal volumes resulting from failure of the toxicity test and/or in cases where diesel oil is used.
The BPJ limitations for drilling fluids in Region IX (Pacific Coast) and Region X (Alaska) .require
compliance with a toxicity limitation of 30,000 ppm in the suspended particulate phase, a prohibition on
the discharge of diesel oil, and metals limitations in the stock barite. The compliance costs and pollutant
loadings incurred by industry to comply with the BPJ limitations are due to: (1) increased onshore
disposal volumes resulting from failure of the toxicity test and/or in cases where diesel oil is used and
(2) a product substitution cost for clean barite.
5.1.4 BPJ Baseline: Drill Cuttings
For drill cuttings, the BPJ baseline is equal to the BPT baseline since all the regional NPDES
permit limitations are equal to the BPT limitations for drill cuttings.
5.2 BCT COMPLIANCE COSTS AND POLLUTANT REMOVALS
The BCT compliance costs and pollutant removals are due to the zero discharge limitations within
certain milage delineations from shore. BCT costs and pollutant removals do not include costs and
removals due to barite substitution because metals are not conventional pollutants. Also, BCT compliance
costs and pollutant removals do not include costs and removals due to the failure of the toxicity test
because the toxicity test does not control conventional pollutants. Tables XI-16 through XI-18 present
the BCT compliance costs and pollutant removals.
5.3 BCT INCREMENTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS
The BCT incremental compliance costs and pollutant removals were determined by subtracting
the BPT compliance costs and pollutant removals from the BCT compliance costs and pollutant removals.
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5.4 BAT AND IMS PS COMPLIANCE COSTS AND LOADINGS
The determination for the BAT and NSPS compliance costs and pollutant loadings was similar
to that of the BPT/BPJ methodology, except additional costs and pollutant loadings were determined
where the limitations were more stringent. These differences will be discussed in the following
paragraphs.
For drilling operations in the Gulf of Mexico, clean barite was substituted for dirty barite to
comply with the cadmium and mercury limitations. The metals limitation results in barite substitution
costs and increased pollutant removals. Since the Region IX and X NPDES permits have metals
limitations on stock barite, the drilling operations in these regions are not affected by this limitation. For
the areas in the Gulf of Mexico where zero discharge limitations apply (within 0,3,4,6, or 8 miles from
shore), substitution costs or pollutant reductions based on clean barite were not calculated. Tables XI-16
through XI-18 present the BAT and NSPS compliance costs and pollutant removals.
5.5 BAT AND NSPS INCREMENTAL COMPLIANCE COSTS AND POLLUTANT REMOVALS
The BAT and NSPS incremental compliance costs and pollutant removals were determined by
subtracting the BPT costs and removals from the BAT/NSPS costs and removals. To relate the
cumulative volume of drilling waste requiring onshore disposal to that of the model well, a value termed
"well-equivalent" has been calculated. One well equivalent is equal to the volume of drilling fluid or drill
cuttings generated by one regionalized (shallow or deep) model well. The total number of well
equivalents determined for each geographic region was calculated by dividing the cumulative total drilling
waste volume requiring onshore disposal by the volume of drilling waste generated by the model well.
Table XI-11 and XI-12 summarizes the BAT and NSPS incremental annual compliance costs and
pollutant reductions obtained for the six drilling waste regulatory options. Section XI.7 provides
summary tables of compliance costs, well equivalents, volumes of pollutants discharged for each
regulatory option considered for the final rule.
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TABLE XI-11
ANNUAL INCREMENTAL COMPLIANCE COSTS/POLLUTANT REDUCTIONS FOR
REGULATORY OPTIONS - DRILLING FLUIDS ^^^ *ฐR
Regulatory Compliance Cost (1986 $1000/yr)
Net Decrease of Volume of Drilling Wastes
Discharged (1000 bbl/yr)
Net Hncrease of Volume of Drilling Wastes
Hauled to Shore (1000 bbl/yr)
Direct Discharges Removed
Oil Removed (1000 Ib/yr)
Incidental Discharges Removed (1000 Ib/yr)
TSS Removed (1000 Ib/yr)
62,777
BMHIII^HB
TABLE XI-12
ANNUAL INCREMENTAL COMPLIANCE COSTS/POLLUTANT REDUCTIONS FOR
REGULATORY OPTIONS-DRILL CUTTINGS ^"uwa *UK
Regulatory Compliance Cost (1986 $1000/yr)
Net Decrease of Volume of Drilling Wastes
Discharged (1000 bbl/yr)
Net Increase of Volume of Drilling Wastes
Hauled to Shore (1000 bbl/yr)
Direct Discharges Removed
Oil Removed (1000 Ib/yr)
Incidental Discharges Removed (1000 Ib/yr)
TSS Removed (1000 Ib/yr)
6.0 BCT
Section' 3040ป(4)0) of the CWA requires EPA to take into account a variety of factors in
addition to the BCT cost test discussed below, in establishing BCT limitations. These additional factors
include "non-water quality environmental impacts (including energy requirements), and such other factors
as the Administrator deems appropriate." EPA conducted an investigation into both the impacts of
transporting drilling wastes and the availability of land for drilling waste disposal (see section XVm 2 2)
These non-water quality environmental impacts and energy requirements and their effect on the control
XI-21
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of drilling fluids and drill cuttings covering existing and new sources are discussed below. Also, EPA
considered other factors such as administrative burden and enforcement issues in evaluating BCT options.
6.1 BCT METHODOLOGY
The methodology for determining "cost reasonableness" was proposed by EPA on October 29,
1982 (47 FR 49176) and became effective on August 22, 1986 (51 FR 24974). These rules set forth a
procedure which includes two tests to determine the reasonableness of costs incurred to comply with
candidate BCT technology options. If all candidate options fail any of the tests, or if no candidate
technologies more stringent than BPT are identified, men BCT effluent limitations guidelines must be set
at a level equal to BPT effluent limitations. The cost reasonableness methodology compares the cost of
conventional pollutant removal under the BCT options considered to be the cost of conventional pollutant
removal at publicly owned treatment works (POTWs).
BCT limitations for conventional pollutants that are more stringent than BPT limitations are
appropriate in instances where the cost of such limitations meet the following criteria:
The POTW Test: The POTW test compares the cost per pound of conventional
pollutants removed by industrial dischargers in upgrading from BPT to BCT candidate
technologies with the cost per pound of removing conventional pollutants in upgrading
POTWs from secondary treatment to advanced secondary treatment. The upgrade cost
to industry must be less than the POTW benchmark of $0.46 per pound ($0.25 per pound
in 1976 dollars indexed to 1986 dollars).
The Industry Cost-Effectiveness Test: This test computes the ratio of two incremental
costs. The ratio is also referred to as the industry cost test. The numerator is the cost
per pound of conventional pollutants removed in upgrading from BPT to the BCT
candidate technology; the denominator is the cost per pound of conventional pollutants
removed by BPT relative to no treatment (i.e., this value compares raw wasteload to
pollutant load after application of BPT). The industry cost test is a measure of the
candidate technology's cost-effectiveness. This ratio is compared to an industry cost
benchmark, which is based on POTW cost and pollutant removal data. The benchmark
is a ratio of two incremental costs: the cost per pound to upgrade a POTW from
secondary treatment to advanced secondary treatment divided by (he cost per pound to
initially achieve secondary treatment from raw wasteload. The result of the industry cost
test is compared to the industry Tier I benchmark of 1.29. If the industry cost test result
for a considered BCT technology is less than the benchmark, the candidate technology
passes the industry cost-effectiveness test. In calculating the industry cost test, any BCT
cost per pound less than $0.01 is considered to be the equivalent of de minimis or zero
costs. In such an instance, the numerator of the industry cost test and therefore the entire
ratio are taken to be zero and the result passes the industry cost test.
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These two criteria represent the two-part BCT cost reasonableness test. Each of the regulatory
options was analyzed according to this cost test to determine if BCT limitations are appropriate.
The conventional pollutant removals used in the BCT analysis are total suspended solids (TSS)
and oil and grease. BOD was not used because: (1) it is not a parameter normally measured in
wastewaters from this industry since it is associated with the oil content, e.g., oil and grease
measurement; and (2) the use of both BOD and oil and grease would result in double-counting the
pollutant removals, thus giving erroneous results.
6.2 BCT COST TEST CALCULATIONS
6.2.1 Drilling Fluids
Using the volumes of drilling fluids projected by the computer model for each geographic region,
it was estimated that offshore drilling activity annually generates a total of 944,364,000 Ib/yr of
conventional pollutants (TSS and oil) in the drilling fluids wastestream. Applying the BPT restrictions
on free oil, it was estimated that under BPT a total of 47,807,000 Ib/yr of conventional pollutants are
removed from this waste stream for onshore disposal, at a cost of $7, 152,000- per year (1986 dollars).
Dividing the cost by pollutant removal, the BPT cost per pound of conventional pollutant removal for
drilling fluids is $0.1496 per pound (1986 dollars). This value is the denominator of the industry cost-
effectiveness test (the second part of the two part BCT cost-reasonableness test).
BPT Result ($/lb) =
..
IDS
= $0.1496 per pound (1986 dollars)
The POTW test (first part of the two part BCT cost-reasonableness test) is calculated by
comparing the cost per pound of conventional pollutants removed in upgrading from BPT to the BCT
candidate technologies. The "3 Mile Gulf/CA" option for BCT, in relation to BPT requirements on
drilling fluids, is projected to remove an additional 71,292,000 pounds of conventional pollutants from
the drilling fluids wastestream at an incremental cost of $5,697,000 (1986 dollars). These BCT
incremental compliance costs and pollutant removals are due to onshore disposal of drilling fluids within
three miles from shore (costs and pollutant removals associated with the no free oil limit beyond three
miles from shore are attributed to BPT limitations and are not counted again under BCT). Since the cost
reasonableness methodology is concerned with the cost of conventional pollutant removal under BCT as
it is applied incrementally to BPT, the effects of existing NPDES permit limitations which may be more
stringent than BPT (such as toxicity, diesel and metals limits for the drilling fluids) are not considered
XI-23
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for the cost-reasonableness tests. These BCT cost tests focus exclusively on the incremental costs/
removals from raw wasteload to BPT, and the incremental costs/removals from BPT to BCT. Dividing
the BCT costs by the conventional pollutant removals provides a POTW test result of $0.0799 per pound.
Since the POTW test result is less than $0.46 per pound (1988 dollars), the result passes the POTW test.
POTW
($/lb) = $5'697'000 =
71,292,000 Ibs
per pound
The industry cost test compares the result of the POTW test to the cost per pound of the BPT
limitations. For the "3 Mile Gulf/CA" option, the test result for drilling fluids is 0.53.
POTW Test Result = 0.0799
BPT Result ($/lb) 0.1496
0.53
Since the test result is less than 1.29, the result passes the industry cost-effectiveness test. Since
the BCT candidate option passes both tests, it is found to be cost-reasonable.
The results of the BCT cost reasonableness test for the candidate options for drilling fluids are
presented in Table XI-13. All BCT options considered for drilling fluids pass both cost-reasonableness
tests.
TABLE XI-13
BCT COST TEST RESULTS FOR DRILLING FLUIDS
BCT Candidate Options ,
3 Mile Gulf/CA
8 Mile Gulf/3 Mile CA
Zero Discharge Gulf and CA
Conventional
Pollutants Removed*
(MMlb/yr)
71.3
161.6
879.1
Regulatory
Compliance Cost*
(MM$/yr)(B86$)
5.7
18.1
116.8
KJtW
Cost Test
(196$ $/lb)
0.08
0.11
0.13
Industry
Cost Test
0.53
0.75
0.89
'Incremental to BPT
6.2.2 Drill Cuttings
Using the volumes of cuttings predicted by the computer model for each geographic region, it
was estimated that the offshore drilling activity annually generates a total of 846,341,000 Ib/yr of
conventional pollutants (TSS and oil) in the drill cuttings wastestream. Applying the BPT restrictions on
free oil, it was estimated that, under BPT limitations a total of 9,381,000 Ib/yr of conventional pollutants
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XI-24
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are removed from this waste stream for onshore disposal at a cost of $635,000 per year (1986 dollars).
Dividing the cost by pollutant removal, the BPT cost per pound of conventional pollutant removal for
drill cuttings is $0.0677 per pound (1986 dollars). The results of the BCT cost reasonableness test for
the candidate options for drill cuttings are presented in Table XI-14. All BCT options considered for drill
_ tunings pass ootn cost reasonableness tests.
1 TABLE XI-14
BCT COST TEST RESULTS FOR DRILL CUTTINGS
1:
,
I
BCT Candidate Options;
3 Mile Gulf/CA
8 Mile Gulf/3 Mile CA
Zero Discharge Gulf and CA
Conventional
Pollutants Removed1
(MM!b/yr)
^^^^^^^^^^^^^^^^^^^^^^Bii^HiliBHHI
70.5
155.2
825.3
Regulatory
Compliance Cos*1
(MM$/yr)(1986$)
3.3
7.5
41.0
P0TW
Cost Test
(1986 S/ib)
0.05
0.05
0.05
Industry
Cost Test
0.69
0.72
0.73
7.0 COST AND CONTAMINANT REMOVAL SUMMARY TABLES
Summary tables of the compliance costs and pollutant removals have been prepared for all BAT
and NSPS options considered. Table XI-15 identifies the regulatory option with the corresponding table
presenting the compliance costs and pollutant removals. Table XI-16 and Tables XI-17a through XI-17f
pertain to drilling fluids options while Tables XI-18a through XI-18f pertain to drill cuttings options.
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XI-25
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TABLE XI-15
REGULATORY OPTIONS AND CORRESPONDING ANALYSIS DIRECTORY
Regulatory Option
Baseline of Current Industry Practice
BPT- Drilling Fluids
BPT - Drill Cuttings
. BPJ - Drilling Fluids
Wells .<. 3 miles from shore:
Zero Discharge (except Alaska)
Wells > 3 miles from shore:
No discharge of free oil
No discharge of diesel oil
Toxicity: 30,000 ppm p
1 mg/kg, 3 mg/kg (dry weight basis in barite stock)
Wells .<. 3 miles from shore (California and Gulf of Mexico)
Wells .<. 8 miles from shore ; '
Zero Discharge
Wells >, 3 miles from shore (California) , .
Wells >_ 8 miles from shore (Gulf of Mexico)
and all wells in Alaska
No discharge of free oil
No discharge of diesel oil
Toxicity: 30,000 ppm
1 mg/kg, 3 mg/kg (dry weight basis in barite stock)
Zero discharge from all wells (except Alaska)
(Limits of toxicity, diesel oil, free oil, Hg, Cd for Alaska)
Wells .<. 4 miles from shore: ;
Zero Discharge (except Alaska) 1
Wells > 4 miles from shore: ,
No discharge of free oil
No discharge of diesel oil
Toxicity: 30,000 ppm
1 mg/kg, 3 mg/kg (dry weight basis in barite stock)
Wells <. 6 miles from shore:
Zero Discharge (except Alaska)
Wells > 6 miles from shore:
No discharge of free oil
No discharge of diesel oil .
Toxicity: 30,000 ppm ;
1 mg/kg, 3 mg/kg (dry weight basis in barite stock) ;
Wells 8 miles from shore: '
Corresponding TaMe
Drilling Fluids
XI-16
XI-17A
XI-17B
XI-16G
XI-17F
XI-17C
XI-17D
XI-17E
Dri! Cuttings
XI-18A
XI-18B
XI-18G
XI-18F
XI-18C
XI-18D
XI-18E
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XI-26
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TABLE XI-16
BPT BASELINE: DRILLING FLUIDS
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Drilling Fluids Hauled to Shore (Ibs)
Oil Hauled to Shore (Ibs)
TSS hauled to Shore (Ibs)
Conventionals Hauled to Shore (Ibs)
Transportation and Onshore Disposal Costs (1986 $)
Product Substitution Costs (1986 $)
Total Compliance Costs (1986 $)
Gulf of
Mexico
141,600
25,293,488
21,662,803
46,956,291
3,014,669
3,935,537
6,950,206
California
0
0
0
0
0
57,183
57,183
Alaska "
2,565
458,152
392,387
850,539
69,222
75,399
144,621
TofaJs
144,165
25,751,640
20,055,190
47,806,830
3,083,891
4,068,119
7,152,010
TABLE XI-17A
ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS BPJ BASELINE
/','-
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drilling Fluids Discharged (bbl/yr)
Volume of Drilling Fluids Hauled to Shore (bbl/yr)
% of Total Drilling Fluids Hauled to Shore
Direct Discharges (Jb/yr)
Oil Discharges (Ib/yr)
Incidental Discharges (Ib/yr)
TSS Discharges (Ib/yr)
Location
Gulf of
Mexico
84
16,571,113
4,895,974
711,117
13%
2,906
9,608,245
300,878,994
748,090,363
California
2
325,664
180,256
11,136
6%
43
164,161
11,011,753
27,546,714
Alaska
1.5
361,538
83,146
12,506
13%.
25
169,940
5,106,849
12,703,813
Toital
88
17,258,315
5,159,376
734,759
12%
2,974
9,942,346
316,997,596
788,358,890
XI-27
-------
TABLE XI-17B
ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS (3 MILE PROFILE)
s * ., ' t
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drilling Fluids Discharged (bbl/yr)
Volume of Drilling Fluids Hauled to Shore (bbl/yr)
% of Total Drilling Fluids Hauled to Shore
Oil Hauled to Shore Ob/yr)
TSS Hauled to Shore Ob/yr)
Conventionals Hauled to Shore Ob/yr)
Direct Discharges Ob/yr)
Oil Discharges Ob/yr)
Incidental Discharges Ob/yr)
TSS Discharges Ob/yr)
Location
Gulf Of
Mexico
136.5
28,892,817
4,485,122
1,121,968
20%
26,556,515
91,692,247
118,248,762
1,375
8,801,959
275,359,068
685,313,549
California
2
325,664
180,256
11,136
6%
0
0
0
43
164,161
11,011,753
27,564,714
Alaska
1.5
361,538
83,146
12,506
13%
458,152
392,387
850,539
25
169,940
5,106,849
12,703,813
* Alaska is exempt from zero discharge.
Total
141
29,580,019
4,748,524
1,145,610
19%
27,014,667
92,084,634
119,099,301
1,443
9,136,060
291,477,670
725,582,076
TABLE XI-17C
ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS
(8/3 MILE PROFILE)
"T ,
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drilling Fluids Discharged fabl/yr)
Volume of Drilling Fluids Hauled to Shore (bbl/yr)
% of Total Drilling Fluids Hauled to Shore
Oil Hauled to Shore Ob/yr)
TSS Hauled to Shore Ob/yr)
Conventionals Hauled to Shore Ob/yr)
Direct Discharges Ob/yr)
Oil Discharges Ob/yr)
Incidental Discharges Ob/yr)
TSS Discharges (lb/yr)
JUcation "" , "\
Mexico
203
39,392,827
3,964,712
1,642,380
29%
28,156,348
180,396,210
208,552,558
1,216
7,780,663
243,409,010
605,796,252
California
2
325,664
180,256
11,136
6%
0
0
0
43
164,161
11,011,753
27,564,714
Alaska*
1.5
361,538
83,146
12,506
13%
458,152
392,387
850,539
25
169,940
5,106,849
12,703,813
* Alaska is exempt from zero discharge.
Total
207
40,080,029
4,228,114
1,666,022.
28%
28,614,500
180,788,597
209^403,097
1,284
8,114,764
259,527,612
646,064,779
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XI-28
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TABLE XI-17D
ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS ZERO DISCHARGE
"- -
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drilling Fluids Discharged (bbl/yr)
Volume of Drilling Fluids Hauled to Shore (bbl/yr)
% of Total Drilling Fluids Hauled to Shore
Oil Hauled to Shore (Ib/yr)
TSS Hauled to Shore (Ib/yr)
Conventional Hauled to Shore (Ib/yr)
Direct Discharges (Ib/yr)
Oil Discharges (Ib/yr)
Incidental Discharges (Ib/yr)
TSS Discharges (Ib/yr)
Location
Gulf of
Mexico
715
119,386,176
0
5,607,091
100%
40,344,552
856,180,349
896,524,901
0
0
0
0
California
32
4,560,971
0
191,393
100%
249,005
29,260,514
29,509,519
0
0
0
0
Alaska*
1.5
361,538
83,146
12,506
13%
458,152
392,387
850,539
25
169,940
5,106,849
12,703,813
Total
749
124,308,685
83,146
5,810,990
98.6%
41,051,709
885,833,250
926,884,959
25
169,940
5,106,849
12,703,813
* Alaska is exempt from zero discharge.
TABLE XI-17E
ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS (4 MILE PROFILE)
- ~-~
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drilling Fluids Discharged (bbl/yr)
Volume of Drilling Fluids Hauled to Shore (bbl/yr)
% of Total Drilling Fluids Hauled to Shore
Oil Hauled to Shore (Ib/yr)
TSS Hauled to Shore (Ib/yr)
Conventionals Hauled to Shore (Ib/yr)
Direct Discharges (Ib/yr)
Oil Discharges (Ib/yr)
Incidental Discharges (Ib/yr)
TSS Discharges (Ib/yr)
Location
Gulf of
Mexico
147
30,550,710
4,402,953
1,204,138
21.5%
26,809,120
105,698,136
132,507,256
1,351
8,640,701
270,314,321
672,758,186
California
2
325,664
180,256
11,136
6%
0
0
0
43
164,161
11,011,753
27,564,714
Alaska*
1.5
361,538
83,146
12,506
13%
458,152
392,387
850,539
25
169,940
5,106,849
12,703,813
Total
151
31,237,912
4,666,355
1,227,780
21%
27,267,272
106,090,523
133,357,795
1,419
8,974,802
286,432,923
713,026,713
: Alaska is exempt from zero discharge.
XI-29
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TABLE XI-17F
ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS (6 MILE PROFILE)
.
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drilling Fluids Discharged (bbl/yr)
Volume of Drilling Fluids Hauled to Shore (bbl/yr)
% of Total Drilling Fluids Hauled to Shore
Oil Hauled to Shore Ob/yr)
TSS Hauled to Shore (lb/yr)
Conventionals Hauled to Shore (Ib/yr)
Direct Discharges Ob/yr)
Oil Discharges (Ib/yr)
Incidental Discharges Ob/yr)
TSS Discharges Ob/yr)
' Location
Gulf of
Mexico
153
31,517,814
4,355,020
1,252,072
22%
26,956,473
113,868,238
140,824,711
1,355
8,546,635
267,371,555
665,434,224
California
23.5
3,323,789
50,697
140,696
73.5%
178,972
21,030,994
21,209,966
11
46,170
3,097,055
7,752,575
Alaska*
1.5
361,538
83,146
12,506
13%
458,152
392,387
850,539
25
169,940
- 5,106,849
12,703,813
Total
178
35,203,141
4,488,863
1,405,274
24%
27,593,597
135,291,619
162,885,216
1,371
8,762,745
275,575,459
685,890,612
* Alaska is exempt from zero discharge.
TABLE XI-17G
ANNUAL POLLUTANT REMOVALS AND COST - DRILLING FLUIDS (8 MILE PROFILE)
- . , _ ^ -.- . - , V.
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drilling Fluids Discharged (bbl/yr)
Volume of Drilling Ruids Hauled to Shore (bbl/yr)
% of Total Drilling Fluids Hauled to Shore
Oil Hauled to Shore Ob/yr)
TSS Hauled to Shore Ob/yr)
Conventionals Hauled to Shore Ob/yr)
Direct Discharges Ob/yr)
Oil Discharges Ob/yr)
Incidental Discharges Ob/yr)
TSS Discharges Ob/yr)
Location , /
Gulf of
Mexico
203
39,392,827
3,964,712
1,642,380
29%
28,156,348
180,396,210
208,552,558
1,216
7,780,663
243,409,010
605,796,252
California
29
4,105,911
16,899
174,494
91%
225,660
26,517,340
26,743,000
3
15,390
1,032;353
2,584,191
Alaska*
1.5
361,538
83,146
12,506
13%
458,152
392,387
850,539
25
169,940
5,106,849
12,703,813
Total
234
43,860,276
4,064,757
1,829,380
31%
28,840,160
207,305,937
236,146,097
1,244
7,965,993
249,549,2.12
621,084,256
* Alaska is exempt from zero discharge.
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XI-30
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TABLE XI-18A
BPT BASELINE: DRILL CUTTINGS
.<
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drill Cuttings Discharged (bbl/yr)
Volume of Drill Cuttings Hauled to Shore (bbl/yr)
% of Total Drill Cuttings Hauled to Shore
Oil ]3auled to Shore (Ib/yr)
TSS Hauled to Shore (Ib/yr)
Conventional Hauled to Shore (Ib/yr)
Direg$ Disejhajrgeg Qb/yr)
Oil Discharges (Ib/yr)
Incidental Discharges (Ib/yr)
TSS Discharges (Ib/yr)
Location
Gulf of
Mexico
9
621,000
1,680,066
26,371
2%
464,712
8,730,521
9,195,233
372
3,959,659
18,032,029
793,174,659
California
0
0
52,578
0
0%
0
0
0
5
54,806
61g,Q9ป
24,544,113
Alaska
0.2
14,000
29,134
470
2%
9,391
176,430
185,821
5
70,304
306,384
13,791,045
Total
9.2
635,000
1,761,778
26,841
2%
474,103
8,906,951
9,381,054
382
4,084,769
18,956,512
831,50Sl,817
XI-31
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TABLE XI-I8B
ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS (3 MILE PROFILE)
v ซ A-,
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drill Cuttings Discharged (bbl/yr)
Volume of Drill Cuttings Hauled to Shore (bbl/yr)
% of Total Drill Cuttings Hauled to Shore
Oil Hauled to Shore Qb/yr)
TSS Hauled to Shore (lb/yr)
Conventional Hauled to Shore Qb/yr)
Direct Discharges Qb/yr)
Oil Discharges Qb/yr)
Incidental Discharges Qb/yr)
TSS Discharges Qb/yr)
Location
Gulf of
Mexico
121
7,084,000
1,405,445
300,992
18%
1,663,516
77,973,221
79,636,737
172
2,151,343
14,625,734
667,544,621
California
2
80,000
49,741
2,836
5%
0
Q
0
4
35,429
580,528
23,260,048
Alaska*
1
87,000
26,597
3,006
10%
24,113
202,302
226,415
3
41,225
270,988
12,669,829
Total
124
7,251,000
1,481,783
396,834
17%
1,687,629
78,175,523
79,863,152
179
; 2,227,997
15,477,250
703,474,498
* Alaska is exempt from zero discharge.
TABLE XI-18C
ANNUAL POLLUTANT REMOVALS AND COST - DRILL gUTTINGS (8/3 MILE PROFILE)
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'' ref'tS, f , > e
, : V '.:>''' "
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drill Cuttings Discharged (bbl/yr)
Volume of Drill Cuttings Hauled to Shore (bbl/yr)
% of Total Drill Cuttings Hauled to Shore
Oil Hauled to Shore Qb/yr)
TSS Hauled to Shore Qb/yr)
Conventional Hauled to Shore Qb/yr)
Direct Discharges Qb/yr)
Oil Discharges Qb/yr) '
Incidental Discharges Qb/yr)
TSS Discharges Qb/yr)
Location "
Mexico
190
10,921,000
1,242,370
464,067
27%
2,084,402
162,262,696
i64,367,Q98
153
1,901,721
12,928,704
590,089,062
California
2
80,000
49,741
2,836
5%
0
0
0
4
35,429
580,528
23,260,048
Alaska*
1
87,000
26,597
3,006
10%
24,113
202,302
22*7415'
3
41,225
270,988
12,669,829
Total;
193
11,088,000
1,318,708
469,909
26%
2,108,515
162,484,998
"161,59,3,513
160
1,978,375
13,780,220
626,018,939
* Alaska is exempt from zero discharge.
*
XI-32
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TABLE XI-18D
ANT1UAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS ZERO DISCHARGE
v
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drill Cuttings Discharged (bbl/yr)
Volume of Drill Cuttings Hauled to Shore (bbl/yr)
% of Total Drill Cuttings Hauled to Shore
Oil Hauled to Shore (Ib/yr)
TSS Hauled to Shore (Ib/yr)
Conventionals Hauled to Shore (Ib/yr)
Direct Discharges (Ib/yr)
Oil Discharges (Ib/yr)
Incidental Discharges (Ib/yr)
TSS Discharges Ob/yr)
Location
Gulf of
Mexico
715
40,158,000
0
1,706,437
100%
5,290,895
804,587,769
809,878,667
0
0
0
0
California
32
1,500,000
0
52,578
100%
54,806
24,544,113
24,598,919
0
0
0
0
Alaska*
1
87,000
26,597
3,006
10%
24,113
202,302
226,415
3
41,225
270,988
12,669,829
* Alaska is exempt from zero discharge.
Total
748
41,745,000
26,597
1,762,021
98.5%
5,369,814
829,334,184
834,703,998
3
41,225
270,988
12,669,829
TABLE XI-18E
ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS (4 MILE PROFILE)
, -
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drill Cuttings Discharged (bbl/yr)
Volume of Drill Cuttings Hauled to Shore (bbl/yr)
% of Total Drill Cuttings Hauled to Shore
Oil Hauled to Shore (Ib/yr)
TSS Hauled to Shore (Ib/yr)
Conventionals Hauled to Shore Ob/yr)
Direct Discharges (Ib/yr)
Oil Discharges (Ib/yr)
Incidental Discharges (Ib/yr)
TSS Discharges (Ib/yr)
Location
Gulf of
Mexico
132
7,689,000
1,379,697
326,740
19%
1,729,972
91,285,244
93,015,216
168
2,111,929
14,357,781
655,314,796
California
2
80,000
49,741
2,836
5%
0
0
0
4
35,429
580,528
23,260,048
Alaska*
1
87,000
26,597
3,006
10%
24,113
202,302
226,415
3
41,225
270,988
12,669,829
Total
135
7,856,000
1,456,035
332,582
18.6%
1,754,085
91,487,546
93,241,631
175
2,188,583
15,209,297
691,244,673
* Alaska is exempt from zero discharge
XI-33
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TABLE XI-18F
ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS (6 MILE PROFILE)
V
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drill Cuttings Discharged (bbl/yr)
Volume of Drill Cuttings Hauled to Shore (bbl/yr)
% of Total Drill Cuttings Hauled to Shore
Oil Hauled to Shore (Ib/yr)
TSS Hauled to Shore (Ib/yr)
Conventionals Hauled to Shore (Ib/yr)
Direct Discharges Qb/yr)
Oil Discharges Qb/yr)
Incidental Discharges Qb/yr)
TSS Discharges Qb/yr)
Location
Gulf of
Mexko
138
8,043,000
1,364,677
; 341,761
20%
1,768,737
99,050,590
100,819,327
167
2,088,937
14,201,475
648,180,732
California
23.5
1,100,000
13,990
38,589
73%
39,392
17,641,082
17,680,434
1
9,964
163,269
6,541,888
Alaska*
1
87,000
26,597
3,006
10%
24,113
202,302
226,415
3
41,225
270,988
12,669,829
Total
163
9,230,000
1,405,264
383,356
21%
1,832,242
116,893,874
118,726,216
171
2,140,126
14,635,732
667,392,449
* Alaska is exempt from zero discharge.
TABLE XI-18G
ANNUAL POLLUTANT REMOVALS AND COST - DRILL CUTTINGS (8 MILE PROFILE)
..
Number of "Well Equivalents" Hauled to Shore
Regulatory Compliance Cost (1986 $/yr)
Volume of Drill Cuttings Discharged (bbl/yr)
Volume of Drill Cuttings Hauled to Shore (bbl/yr)
% of Total Drill Cuttings Hauled to Shore
Oil Hauled to Shore Qb/yr)
TSS Hauled to Shore Qb/yr)
Conventionals Hauled to Shore Qb/yr)
Direct Discharges Qb/yr)
Oil Discharges Qb/yr)
Incidental Discharges Qb/yr)
TSS Discharges Qb/yr)
Location
Gulf of
Mexko
190
10,921,000
1,242,370
464,067
27%
2,084,402
162,282,696
164,367,098
153
; 1,901,721
12,928,704
590,089,062
California
29
1,367,000
4,663
47,915
91%
49,669
22,243,103
22,292,772
0
3,321
54,423
2,180,629
Alaska*
1
87,000
26,597
3,006
10%
24,113
202,302
226,415
3
41,225
270,988
12,669,829
Total
220
12,375,000
1,273,630
514,988
29%
2,158,184
184,728,101
186,886,285
156
1,946,267
13,254,115
604,939,520
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* Alaska is exempt from zero discharge.
XI-34
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8.O REFERENCES
1. Offshore Operators Committee, "Alternate Disposal Methods for Muds and Cuttings, Gulf of
Mexico and Georges Bank," December 7, 1981. {Offshore Rulemaldng Record Volume 28)
2. SAIC, "Determination of Average Well Depth and Deep Well Depth for the Gulf of Mexico,
Offshore California, and Offshore Alaska," prepared for Engineering and Analysis Division, U.S.
Environmental Protection Agency, November 22, 1991.
3. Memorandum from Michael Benning, Chevron Drilling Technology Center, Houston Texas, to
Joe Dawley, SAIC, "Discussion of TSS in Average Drilling Fluid," March 25, 1992.
4. James P. Ray, "Offshore Discharges of Drill Cuttings," Outer Continental Shelf Frontier
Technology* Proceedings of a Symposium, National Academy of Sciences, December 6, 1979.
(Offshore Rulemaldng Record Volume 18)
5. Survey Results on "Use of Hydrocarbons for Fishing Operations," and "Use of Hydrocarbons
as Lubricity Agents." Attachments to Letter from J.A. Burgbacher, Shell Offshore, Inc., to D.
Ruddy, Industrial Technology Division, U.S. Environmental Protection Agency, October 30,
1985. (Offshore Rulemaldng Record Volume 60)
6. Offshore Operators Committee, "Gulf of Mexico Spotting Fluid Survey," by R.C. Ayers, Jr.,
and J.E. O'Reilly, Exxon Production Research Company, andL.R. Henry, Chevron, USA, line.,
April 4, 1987. (Offshore Rulemaldng Record Volume 60)
7. Batelle New England Marine Research Laboratory, "Final Report for Research Program on
Organic Chemical Characterization of Diesel and Mineral Oils Used as Drilling Mud Additives,"
prepared for Offshore Operators Committee, December 31, 1984. (Offshore Rulemaking Record
Volume 13)
8. SAIC, "Descriptive Statistics and Distributional Analysis of Cadmium and Mercury
Concentrations in Barite, Drilling Fluids, and Drill Cuttings from the API/USEPA Metals
Database," prepared for Industrial Technology Division, U.S. Environmental Protection Agency,
February 1991. (Offshore Rulemaldng Record Volume 120)
9. Letter to Ann Watkins, Engineering and Analysis, U.S. Environmental Protection Agency, from
Maureen Kaplan, Eastern Research Group. "Final Costs for 3,1 Stock Barite Supply,"
October 25, 1991.
10. Letter to Dennis Ruddy, Industrial Technology Division, U.S. Environmental Protection Agency,
from T.M. Randolph, American Petroleum Institute's NSPS/BAT Offshore Guidelines
Committee. "API Drilling Fluids Survey Results," October 23, 1986. (Offshore Rulemaldng
Record Volume 60)
11. Walk, Haydel & Associates, Inc., "Water-Based Drilling Fluids and Cuttings Disposal Study
Update," January 1989. Submitted as comments to 53 FR 41356 by the American Petroleum
Institute, January 18, 1989. (Offshore Rulemaldng Record Volume 94)
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12. Offshore Operators Committee. "Response to EPA Request for Additional Information," letter
from J.F. Branch, Chairman Offshore Operators Committee, to Ronald P. Jordan, Engineering
and Analysis Division, U.S. Environmental Protection Agency. August 30, 1991.
13. Memorandum to Dennis Rudy, Industrial Technology Division, U.S. Environmental Protection
Agency, from Harold Kohlman, KRE, P.C., "Differential Cost of Mineral Oil Substitution,"
June 10, 1985. (Offshore RidemaJang Record Volume 17)
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SECTION XII
COMPLIANCE COST AND POLLUTANT LOADING DETERMINATION -
PRODUCED WATER
1.0 INTRODUCTION
This section presents costs and pollutant reductions for the final set of proposed regulatory options
for produced water. The technology costs represent additional investment required beyond those .costs
associated with BPT technologies, where applicable.
2.0 BASIS FOR BCT, BAT AND NSPS OPTION EVALUATION
Several treatment options were considered as the basis for BCT, BAT and NSPS limitations for
produced water. To evaluate the proposed treatment options, EPA created a database and developed
computer models to generate regionalized compliance costs for the treatment and disposal of produced
water. The database consisted of the following elements:
Industry profile data on the number and type of platforms and produced water discharge
rates.
Projected future production activity.
Produced water contaminant effluent levels associated with BPT treatment and with BAT
and NSPS treatment options.
ซ Cost to implement the BAT and NSPS treatment technology options.
EPA entered the data into the computer models designed to predict regionalized compliance costs
and pollutant removals for the various regulatory options as defined in Part 6 of this section. These
options are comprised of three potential treatment technologies for BAT and NSPS:
Improved operating performance of gas flotation technology
Granular filtration and subsequent surface water discharge
Granular filtration followed by reinjection of the produced water into any compatible
geologic formation.
XII-1
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3.0 COMPLIANCE COSTS AND POLLUTANT REMOVAL CALCULATION
METHODOLOGY 1
For each geographical area, EPA characterized the industry as a population consisting of various
platform structure types, or model platforms. A model platform was characterized by the number of
available well slots on the platform. Each producing well is brought to the well head on the platform
through a dedicated well slot. The number of well slots on a platform indicates the maximum number
of producing wells. For example, the model platform Gulf 4 has four available well slots. This format
XII-2
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The per-platform capital costs for the treatment equipment and the associated annual operating,
maintenance and monitoring costs (annual costs) were developed for modeled treatment systems with
design capacities of 200 barrels per day (bpd), 1,000 bpd, 5,000 bpd, 10,000 bpd, and 40,000 bpd of
produced water. Costs for these systems were derived based on vendor-supplied data, industry
information, cost analyses conducted by the Energy Information Administration (Department of Energy), _'
and EPA projections. Curves depicting flow rate versus cost were generated to estimate the capital and
annual costs for treatment systems with capacities other than the five modeled systems for which cost data
were collected.
The per platform capital costs were regionalized using geographic area multipliers. The |
geographic area multipliers represent the ratios of the equipment installation costs in a particular region
compared to the costs for the same equipment installation in the Gulf of Mexico region. The area WL
multipliers are as follows:1
Gulf of Mexico 1.0 ...
Pacific Coast 1.6
Alaska - Cook Inlet 2.0
Alaska-Other 3.5 I
Atlantic 1.6
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EPA calculated total industry costs for each treatment option using; the per-platform capital and
annual costs, and industry profiles of current and projected future production activity in three
geographical offshore areas: the Gulf of Mexico and offshore of California and Alaska. EPA did not ^
develop industry costs for offshore of Florida and the Atlantic coast due to the presidential moratoria on
oil and gas leasing and development in these areas. However, the costs in these regions would be similar
to those developed for offshore southern California.
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is valid for all model platforms except for the Gulf la platform. A Gulf la platform consists of a
centralized fluid separation process and four satellite production platforms. The model platforms were
further divided into categories based on whether they produced: (1) oil only; (2) both oil and gas; or
(3) gas only. The development of the industry profiles is presented in the Economic Impact Analysis for
this rule.
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For each "model platform," EPA estimated the number of producing wells, the quantity of
produced water generated (average and peak flow), and the cost to implement a produced water treatment
system. Thus, by dividing the industry among these "model platforms," EPA derived estimates of costs
and pollutant reductions.
As with the drilling profile, the population of BAT and NSPS structures in each region was
classified within and beyond some milage delineation from shore. The milage delineations for production
profiles were three and four miles from shore. Appendix 1 present the BAT and NSPS profiles of
production platforms for the three and four mile delineations.
EPA determined contaminant removals by comparing the estimated effluent levels after treatment
by the BAT and NSPS treatment systems versus the effluent levels associated with a typical BPT
treatment.
The computer model calculated the capital costs for each model platform in each region based
on the maximum daily produced water flow rate for the given platform.- The maximum daily flow rate
for each modeled platform determined the required capacity of the treatment system. Interpolating along
the "capital cost-flowrate" curve developed for the five modeled treatment systems, EPA determined the
capital costs for each of the model platforms.
The computer model calculated the annual costs for each model platform hi each region based
on the average daily produced water flow rate for the given platform. Interpolating along the "annual
cost-flowrate" curve developed for the five modeled treatment systems, EPA determined the annual costs
for ea.ch of the model platforms.
XII-3
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4.0 CAPITAL AND ANNUAL COSTS PER PLATFORM
Capital costs and annual costs were developed for the three treatment technologies considered
using cost data obtained from equipment vendors and cost information supplied by the Department of
Energy's Energy Information Administration (DOE/EIA). To simplify the costing task, actual equipment
and annual costs were obtained for five systems with different produced water treatment capacities for
each treatment technology. To estimate costs for systems with design flow rates other than the five
selected, it was assumed that a linear relationship exists between the design flow rates and the capital and
annual costs. The capital and annual costs obtained for the five different systems were input in computer
models and, through linear interpolation, the model calculated the system costs for each model platform.
This section provides a detailed discussion on the development of these costs.
4.1.1 Gas Flotation - BAT and NSPS Capital Costs
EPA developed gas flotation equipment costs based on direct contact with vendors and
manufactures of offshore gas flotation equipment. Tables XII-1 and XII-2 present the BAT and NSPS
unit capital costs for the five systems costed. The following discussion details the assumptions made to
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develop the total unit capital costs.
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Packaged Equipment: The packaged equipment costs are the costs for the complete gas
flotation system which includes the following: a skid-mounted flotation unit, complete
electrical system, oil and water outlets brought to the edge of the skid, and sufficient
instrumentation for proper operation.
Installed Cost: An offshore installation factor of 3.5 was used to account for costs
associated with transportation to the platform and installation at the platform.2 A
conversation with an industry representative confirmed the validity of this factor by
indicating that the offshore installation factor may be about three times the equipment
capital costs. This consisted of transportation and installation. The transportation cost
was indicated to be approximately equal to the equipment cost and the installation cost
could possibly be double the equipment cost.3
Platform Addition Costs: EPA based gas flotation space requirements on informaition
provided by vendors and manufacturers of offshore gas flotation equipment. The existing
(BAT) platform addition costs are for additional space such as a cantilevered deck. (For
NSPS treatment, no platform addition or additional platform costs were incurred because
EPA assumed that the space for equipment would be included in the platform design.)
A cantilevered deck or wing deck can be added along one side of a platform to increase
the total square footage of the platform deck. For example, a one hundred foot long
cantilevered deck that extends ten feet from the edge of the existing platform deck would
add one thousand square feet to the platform deck. EPA estimated the cost of additional
platform space $250 per square foot based on information obtained from the industry and
Department of Energy.3-4 The actual areas required by the gas flotation systems were
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estimated to be twice the area of the process equipment "footprints" that were furnished
by the vendors. The additional area includes sufficient space for any additional process
equipment, instrumentation, and walkways. For the NSPS scenario, because new
facilities can include the gas flotation equipment in the design of the platform, EPA
determined that no additional platform space, such as a cantilevered deck, would be
required.
Engineering, Contingency, and Insurance-Bonding Fees: These fees were added to
the equipment capital costs to develop the actual capital costs. These fees include all
engineering design costs, administrative costs, and any incidental costs incurred in the
process of purchasing and installing the equipment.2
TABLE Xtt-1
COST DATA FOR GAS FLOTATION - EXISTING PLATFORMS (BAT)
Component
1. Capital Cost (1986 $)
Package Equipment - Installed Cost*
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Platform Space
Total Capital Cost
2. Annual Cost (1986 $/vr)
WoWate(BWPP)
200
245,557
24,556
36,834
9,822
28,000
344,769
34,477
1,000
245,557
24,556
36,834
.. 9,822
28,000
344,769
34,477
5,000
314,817
31,482
47,223
12,593
52,500
458,615
45,861
10,000
346,298
34,630
- 51,945
13,852
66,500
513,225
51,322
40,000
440,743
44,074
66,112
17,630
128,000
696,559
69,655
*Adjusted from 1991 dollars using an ENR-CCI ratio of 4295/4775.
TABLE Xn-2
COST DATA FOR GAS FLOTATION - NEW PLATFORMS (NSPS)
*Adjusted from 1991 dollars using an ENR-CCI ratio of 4295/4775.
xn-s
Component
1. Capital Cost (1986 $)
Package Equipment - Installed Cost*
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Total Capital Cost
2. Annual Cost (1986 $/yr)
Flo v, rate (BWPD)
200
245,557
24,556
36,834
9,822
316,769
31,677
1,000
245,557
24,556
36,834
9,822
316,769
31,677
5,000
314,817
31,482
47,223
12,593
406,115
40,611
10,000
346,298
34,630
51,945
13,852
446,725
44,672
40,000
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44,074
66,112
17,630
568,559
56,856
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4.1.2 Gas Flotation - BAT and NSPS Annual Costs
The annual operating and maintenance costs for the gas flotation treatment option were assumed
to be ten percent (10%) of the total capital costs for the given flow rate of the produced water stream.
In addition to labor costs, typical operating and maintenance costs may include: polymer and/or
flocculation enhancement chemicals, and pump and inductor maintenance and replacement costs. The
annual operating and maintenance costs for the five gas flotation units are presented in Tables XII-1 and
xn-2. \ I
4.2.1 Granular Filtration - BAT and NSPS Capital Costs
The Department of Energy's Energy Information Administration (DOE/EIA) assisted the EPA 4
in the development of capital costs for granular filtration technology. The capital costs developed are for
a skid-mounted multi-media granular filtration system with a complete backwash system. Tables XII-3
and XH-4 present the BAT and NSPS unit capital costs for the five filtration systems costedl. A
discussion detailing the assumptions made to develop the total unit capital costs is as follows.
Filtration Unit: The filtration unit costs represent the total system costs. The filters are |
granular media, pressure downflow type units which utilize polymer injection to enhance
fine solids separation from the water stream. The filtration system includes one filter and
a spare to be used during backwashing. The filtration system also includes piping around
the filters, backwash basin and pumps, a backwash pump, a tank for backwash liquids,
and the piping and controls necessary for recirculation of the fluids into the treatment
system. The 40,000 BWPD system uses two operating filters in parallel. The following
design parameters were used for equipment sizing:4 |
Filter flow rate: 10-25 gpm/ft2 ซ
Filter feed pump: no pump, assume gravity feed adequate
Media material: granular garnet and coal I
Backwash tank volume: 6,300 gal for 40,000 BWPD system
Backwash cycle frequency: every eight hours
Backwash cycle time: 10 minutes
Q
Backwash flow rate: 3% of the produced water flow
Installation costs: included in unit costs
Offshore transportation costs: included hi unit costs.
XII-6
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TABLE XII-3
COST DATA FOR GRANULAR FILTRATION - EXISTING PLATFORMS (BAT)
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Component
1. Capital Cost (1986 $)
Filtration Unit*
Centrifuge**
Piping
Sub-Total:
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Platform Space
Total Capital Cost:
2. Annual Cost (1986 $/yr)
Labor
Maintenance
Chemicals
Sludge Disposal
Total Annual Cost:
Flowrate (BWPD)
200
315,000
0
47,000
362,000
36,000
54,000
14,000
42,000
508,000
25,600
50,800
170
370
77,000
1,000
315,000
128,000
66,000
509,000
51,000
77,000
20,000
42,000
699,000
25,600
69,900
860
1,800
98,100
5,000
315,000
128,000
66,000
509,000
51,000
77,000
20,000
42,000
699,000
25,600
69,900
4,300
9,300
109,100
10,000
450,000
128,000
66,000
644,000
64,000
97,000
26,000
42,000
873,000
25,600
87,300
8,600
18,500
140,000
40,000
630,000
256,000
88,000
974,000
98,000
146,000
39,000
137,000
1,394,000
25,600
139,400
34,300
74,000
237,300
*Adjusted from 1991 dollars using an ENR-CCI Ratio of 4295/4775
**Adjusted from 1981 dollars using an ENR-CCI Ratio of 4295/3535
TABLE XII-4
COST DATA FOR GRANULAR FILTRATION - NEW PLATFORMS (NSPS)
'
Component
1. Capital Cost (1986 $)
Filtration Unit*
Centrifuge**
Piping
Sub-Total:
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Total Capital Cost:
2. Annual Cost (1986 %/yr)
Labor
Maintenance
Chemicals
Sludge Disposal
Total Annual Cost:
Flowrate (BWPD>
200
315,000
0
47,000
362,000
36,000
54,000
15,000
467,000
25,600
46,700
170
370
72,800
1,000
315,000
128,000
66,000
509,000
51,000
77,000
20,000
657,000
25,600
65,700
860
1,800
94,000
5,000.
315,000
128,000
66,000
509,000
51,000
77,000
20,000
657,000
25,600
65,700
4,300
9,300
105,000
10,000
450,000
128,000
66,000
644,000
64,000
97,000
26,000
831,000
25,600
83,100
8,600
18,500
136,000
40,000
630,000
256,000
88..000
974,000
98,000
146,000
39,000
1,257,000
25,600
126,000
34,300
74,000
260,000
*Adjusted from 1991 dollars using an ENR-CCI Ratio of 4295/4775
**Adjusted from 1981 dollars using an ENR-CCI Ratio of 4295/3535
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These costs were readjusted to represent 1986 dollars, by using the ratio of ENR-CCI indices of 4295
(1986) to 4775 (1991).
Centrifuge: In order to reduce the backwash volumes that would be required to be
hauled to shore, a centrifuge would be installed on the platform as part of the filtration
system. The volumes of filter backwash and sludge generated after dewatering are
presented in Section IX.5.2.3. Centrifuge costs are based on a centrifuge sized to
process seventy five barrels of backwash concentrate per day. The cost of this unit was
assumed to be no more than $30,000 in 1981 dollars.5 This centrifuge was assumed
adequate to process the backwash concentrate for all the model platforms except for
systems treating less than two hundred barrels of produced water per day. For these
facilities, it was assumed that the backwash volumes would be minimal and dewatering
would not be necessary or economically justifiable. For costing purposes, two
centrifuges were assumed adequate for systems treating more than forty thousand barrels
of produced water per day. The centrifuge cost was adjusted from 1981 to 1986 dollars
using the ratio of ENR-CCI indices of 4295 (1986) to 3535 (1981). The centrifuge costs
presented in this Section are adjusted to 1986 dollars and include the cost for
transportation and installation( offshore factor of 3.5).
Piping: Piping cost represents fifteen percent (15%) of the equipment cost for systems
treating 200 and 1000 BWPD and ten percent (10%) of the equipment cost for systems
treating 5,000, 10,000 and 40,000 BWPD.2
Engineering, Contingency, and Insurance-Bonding Fees: These fees were added to
the equipment capital costs to develop the actual capital costs. These fees include all
engineering design costs, administrative costs, and any incidental costs incurred in the
process of purchasing and installing the equipment.2
Platform Space: The platform space costs are for additional space such as a cantilevered
deck. Platform addition costs were estimated by DOE/EIA and are based on the area
requirements of the filtration system. EIA estimated platform addition costs to be $235
per square feet (1991 dollars). The platform addition costs were not backdated to 1986
dollars since the ENR-CCI factors are not applicable for the platform construction
industry and no applicable costing factor was available. The following costs and platform
space requirements were supplied by EIA:4
A. Area requirements for each system
For 200 to 40,000 BWPD: 200 ft2
For 40,000 BWPD: 600 ft2 ,
B. Cost requirements for additional platform space
Additional area: $235/ft2
C. Cost for auxiliary platform :
$3,500,000 for two decks, 2500 ft2 each in deep water
$2,900,000 for two decks, 2500 ft2 each in shallow water.
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Cost for auxiliary platforms were only assigned to platforms with maximum daily produced water
flow rates greater than forty thousand barrels. This consists of the Beaufort Sea, Navarian, and Pacific
70 facilities. For these model platforms, the filtration equipment would require more space than what
could be added as a cantilevered deck to an existing platform. It was also assumed that the cost of an
additional platform would be dependent on the water depth. In this costing exercise, all additional
platforms constructed within four miles from shore were assigned the shallow water cost of $2,90b,000.
Those platforms beyond four miles from shore were assigned the deep water cost of $3,500,000.
4.2.2 Granular Filtration Annual Costs
The annual BAT and NSPS operating and maintenance costs for granular filtration are presented
in Tables XH-3 and XH-4. The assumptions used to develop the BAT and NSPS annual costs for
granular filtration are as follows:
Labor: The labor costs are based on two man-hours per day at a rate of $35 per hour
(1986 dollars).4
Maintenance: Maintenance costs represent 10% of the capital costs, and include- energy
costs, occasional unit cleanout, inspection of the filtration media and replacement if
necessary.4
Chemicals: The raw chemical costs are for polymer addition to enhance filtration. A
dosage of 5 mg/1 of polymer is assumed at a cost of $11.20/gal. This cost is in 1989
dollars and it was not backdated to 1986 dollars because it was assumed that these .costs
are relatively constant.6
Sludge Disposal: EPA estimated the sludge volume generated from the granular
filtration backwash stream to be 0.06% of the produced water flow.2-5 This estimate is
based on the following assumptions:
1.
2.
3.
Filter backwash volumes are three percent of the total volume of produced water
filtered.2
Solids contained in the backwash are at a concentration of 5,000 mg/1 and are
thickened to 20,000 mg/1 in the backwash tank prior to dewatering2 or
approximately 0.5 percent of the total volume filtered.5
The solids are concentrated in a centrifuge to a sludge of 25 percent solids by
weight2 or approximately 0.06 percent of the total volume filtered.5
4. The cost of sludge disposal and handling is assumed to be $8.45/barrel.3
xn-9
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The volumes of backwash water and sludge generated from operation of the granular filtration
units for the five model flow rates are presented in Table XII-5.
TABLE XH-5
BACKWASH AND SLUDGE VOLUMES GENERATED FROM MULTI-MEDIA FILTRATION
(volumes in barrels per day)
Flow - Barrels of Produced Water Per Day
Stream
PUter Backwash
Concentrated Backwash
Dewatered Concentrate
200
6
1
0.12
1,000
30
5
0.6
5,000
150
25
3
xo,ooo
300
50
6
40ปซW
1,200
200
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4.3.1 Reinjection-BAT and NSPS Capital Costs
Part of the basis for the reinjection costing methodology is similar to that of the granular filtration
option since filtration of the produced water is typically necessary prior to reinjection. Without this
pretreatment, fine solids can plug the pores of the formation, decreasing the capacity of the formation,
thus preventing the reinjection of the produced water. For this costing estimation, it was assumed that
multi-media filtration would be the pre-treatment filtration technology used. The DOE/EIA developed
capital costs for gas turbine injection pumps. Tables XII-6 and XII-7 present the BAT and NSPS capital
costs for the five granular filtration/reinjection systems costed. Several of the assumptions made to
develop the capital costs for reinjection are similar to those made for the granular filtration system. The
following discussion details the assumptions made in developing the capital costs for reinjection pumps
and injection wells. The development of the costs for the granular filtration components of the reinjection
system are discussed in Section xn.4.2.1.
Reinjection Pumps: The reinjection pumps are high pressure, positive displacement
pumps suitable for sea water environment. The pumps are natural gas-engine driven, and
are capable of delivering 1,800 pounds per square inch of discharge head at the specified
flow rate. The pump costs were developed by the EIA and include a spare.4 These costs
were adjusted to 1986 dollars by applying the ratio of ENR-CCI indices of 4295 (1986)
to 4775 (1991).
Instrumentation and Controls: The instrumentation and controls pertain to the injection
pump and the centrifuge system. The installation and control costs are 20% of the capital
costs for the injection pump and the centrifuge.2
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TABLE XII-6
COST DATA FOR REINJECTION - EXISTING PLATFORMS (BAT)
Component
1. Capital Cost (1986 $)
Disposal Pumps*
Instrumentation & Controls
Filtration Unit*
Centrifuge**
Piping
Sub-Total:
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Platform Space
Total Capital Cost:
2. Annual Cost (1986 $/yr)
Labor
Maintenance
Chemicals
Sludge Disposal
Total Annual Cost:
200
32,000
7,000
315,000
0
52,000
406,000
41,000
61,000
16,000
72,000
596,000
38,300
59,600
170
370
98,400
Flowrate (BWPD)
1,000
32,000
33,000
315,000
128,000
72,000
579,000
58,000
87,000
23,000
72,000
819,000
38,300
81,800
860
1,800
122,700
5,000
119,000
49,000
315,000
128,000
84,000
695,000
70,000
104,000
28,000
79,000
976,000
38,300
97,600
4,300
9,300
149,500
10,000
434,000
113,000
450,000
128,000
101,000
1,226,000
123,000
184,000
49,000
79,000
1,661,000
38,300
166,100
8,600
18,500
231,500
40,000
1,350,000
321,000
630,000
256,000
223,000
2,780,000
278,000
417,000
112,000
197,000
3,784,000
38,300
378,400
34,300
74,000
525,700
*Adjusted from 1991 dollars using an ENR-CCI Ratio of 4295/4775
**Adjusted from 1981 dollars using an ENR-CCI Ratio of 4295/3535
TABLE XII-7
COST DATA FOR REINJECTION - NEW PLATFORMS
'"Adjusted from 1991 dollars using an ENR-CCI ratio of 4295/4775
**Adjusted from 1981 dollars using an ENR-CCI ratio of 4295/3535
XII-11
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Component
1. Capital Cost (1986 $)
Disposal Pumps*
Instrumentation & Controls
Filtration Unit*
Centrifuge**
Piping
Sub-Total:
Engineering (10%)
Contingency (15%)
Insurance/Bonding (4%)
Total Capital Cost:
2. Annual Cost (1986 $/yr)
Labor
Maintenance
Chemicals
Sludge Disposal
Total Annual Cost:
Flowrate (BWPD)
200
32,000
6,000
315,000
0
53,000
406,000
41,000
61,000
16,000
524,000
38,300
52,300
170
370
91,200
1,000
32,000
32,000
315,000
128,000
72,000
579,000
58,000
87,000
23,000
747,000
38,300
74,600
860
1,800
115,600
5,000
119,000
49,000
315,000
128,000
56,000
667,000
67,000
100,000
27,000
861,000
38,300
86,100
4,300
9,300
138,000
10,000
434,000
113,000
450,000
128,000
101,000
1,226,000
122,000
184,000
49,000
1,581,000
38,300
158,100
8,600
18,500
223,500
40,000
1,350,000
321,000
630,000
256,000
224,0001
2,781,000
278,000'
417,000
111,000
3,587,000
38,300
358,700
34,300
74,000
505,300
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Platform Space: The platform space costs for the reinjection technology are similar to
the cost developed for the granular filtration option. The reinjection system requires
additional space beyond that required for granular filtration due to the area requirements
of the injection pump. The EIA estimated that the area requirements for injection pumps |
on platforms processing up to 40,000 barrels of produced water per day is 140 square
feet and the area requirement for a 40,000 barrel per day system is approximately 250 ซ
square feet. For those facilities processing over 40,000 barrels per day construction of I
auxiliary platforms would be necessary.4
Reinjection Wells: The reinjection wells costs are based on $750,000 per well to
recomplete an existing available well bore and $1,500,000 per well to drill a new well |
bore.7 These estimates are based (up to 5,000 ft true vertical depth) wells drilled in the
Gulf of Mexico, on actual costs for similar depth Each well has a flow capacity of _
6,000 BWPD. It was assumed that available slots not utilized for producing wells on I
model platforms are "dry holes" and can be converted to injection wells.8 The number "^
of injection wells required per structure was calculated based on that platforms average
daily produced water flow rate. It was assumed that for every two wells required, one
spare well would be necessary to handle the injection flow requirements if mere was a
problem with the two operating wells. For fields producing less than 1,000 BWPD, it
was assumed that only one injection well was necessary. These fields would either shut
down during an injection well workover or would have sufficient water holding capacity
to continue production operations. These costs were adjusted from 1991 dollars to
represent 1986 dollars by applying the ratio of ENR-CCI indices of 4295 (1986) to 4775
(1991). The well costs were added into the capital costs in the model, where the number
of existing wells, the number of wells to be reworked, and the number of new wells to
be drilled is estimated for each structure type.
4.3.2 Reinjection Annual Costs Assumptions
The annual operating and maintenance costs for reinjection are presented in Tables XII-6 and
Xn-7. The assumptions used to develop the BAT and NSPS annual costs for reinjection are the same
as the assumptions used for granular filtration except for additional labor requirements. The labor
requirements for granular filtration are as follows:
Labor: The labor costs are based on two man-hours per day at a rate of $35 per hour
(1986 dollars). An additional one man-hour per day was added to the base cost for the
operation and maintenance of the reinjection system.4
5.0 REGIONAL AND TOTAL INDUSTRY COSTS
The regional costs were calculated based on the per-platform capital and annual costs developed
and the number of platforms within each geographical region. For the purposes of determining produced I
water compliance costs for this rule, EPA assumed that all new sources would be new platforms and no
allowances were made to account for existing platforms being moved to new locations. An existing
platform moved to a new location would be classified as a new source; however, EPA was unable to
determine the extent to which existing platforms would be used to develop new hydrocarbon reserves.
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Compliance costs for all existing platforms are included as BAT costs in this rule. Also, EPA is unaware
of any existing contractual obligations which could result in new platforms being classified as existing
sources. For this rule, new platforms are included as new sources.
Based on information from the Department of Energy and as presented in the March 1991
proposal, EPA estimated that thirty-seven percent (37%) of existing platforms in the Gulf of Mexico
currently pipe their produced water to shore for treatment.9 Therefore when developing the regional costs
for the Gulf of Mexico, only sixty-three percent (63 %) of the total number of existing platforms and one
hundred percent (100%) of new platforms were assigned offshore treatment costs. Onshore treatment
costs were assigned to those facilities currently piping to shore. Onshore treatment costs are detailed in
Section XII.5.2. EPA cost projections for new platforms indicate that the cost of offshore treatment will
be less than the combined cost of installing piping and establishing onshore treatment facilities. Thus,
EPA assumed all new sources will treat water offshore. The total industry costs for the granular filtration
and the reinjection option are the sum of the regional costs for each treatment option. The total industry
compliance costs as they pertain to the regulatory options considered are presented in Section XII.8.1.
The total capital costs for gas flotation were more complicated to determine because many
operators currently use the gas flotation technology to comply with the current BPT regulations,, To
avoid over-costing by assigning capital costs to all platforms, EPA made several assumptions to predict
the number of existing platforms that currently have gas flotation systems and the number of platforms
that will have to install new flotation systems. The following sections detail the assumptions made in
estimating the total industry costs for the gas flotation option.
5.11.1 Gas Flotation - BAT Total Industry and Capital Costs
EPA determined that to achieve BAT oil and grease limitations based on improved performance
of gas flotation technology, operators who currently have gas flotation treatment systems would continue
to use the same treatment units, although some changes to those systems or their manner of operation
might be necessary. For existing platforms that do not currently have gas flotation systems and can not
meet the limitations of the final rule with their existing treatment systems, some form of add-on treatment
would be necessary. For costing purposes, EPA assumed that all facilities currently without gas flotation
systems are unable to meet the BAT (or for new sources, NSPS) limitations and flotation units would
need to be installed. This assumption does not take into consideration the fact that other treatment
technologies currently used by the operators, such as: parallel plate separators, corrugated plate
XII-13
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interceptors, hydro-cyclones, or filtration, may enable operators to meet the effluent limitation without
requiring installation of flotation units. (The establishment of an effluent limitation based on a given
technology does not require use of the treatment technology upon which the .limitation is based. EPA
selects a technology basis to demonstrate that the effluent limitations are technologically feasible and
economically achievable.) A report prepared in 1984 for the Offshore Operators Committee (OOC) found
that thirteen percent of 319 outer continental shelf (OCS) facilities surveyed used flotation systems for
treatment of produced water.10 Since that same study noted that nearly all new platforms were expected
to install gas flotation systems for produced water treatment; and considering that the profile would likely
have changed in the years since that survey was conducted, EPA collected information from the Minerals
Management Service and various industry sources to update projections of existing gas flotation systems.
EPA learned from MMS, which in 1990 conducted 1,667 drilling inspections and 4,830 production
inspections," that approximately thirty-five percent (35%) of the offshore facilities in Gulf of Mexico are
now using gas flotation systems for produced water treatment.12
In developing the estimate of the current usage of gas flotation technology in the offshore
industry, EPA contacted several members of the OOC. Although estimates of gas flotation usage varied
between companies (some operators indicated 100% usage while others indicated partial usage), most
operators indicated that gas-only production facilities were the least likely to use gas flotation to treat
produced water. The operators indicated that this is because for gas production, an easy separation exists
between the produced water and the condensate and/or oil. Some gas production facilities can meet the
BPT limitations on oil and grease with basic gravity separation. However, for most oil production
facilities, treatment with gas flotation or some other add-on treatment technology is necessary to achieve
the BPT limitations on oil and grease. This is because often an emulsion is created between the oil and
produced water and additional treatment beyond gravity separation is necessary to assure BPT
compliance.
To characterize the variation of gas flotation usage between gas only, oil and gas, and oil only
production projects, EPA developed a distribution profile of facilities currently using gas flotation
technology for the three different types of production facilities. Since the produced water flow rates are
significantly different from a "gas only" and a "oil only" project, a distribution profile is necessary to
accurately estimate the gas flotation capital and annual O&M costs for each production type. Applying
a straight profile of thirty-five percent for each production type would lead to overcounting of large flow,
higher cost flotation systems for "oil only" projects and undercounting of low flow, lower cost flotation
systems for "gas only" projects. The distribution profile is as follows:
xn-14
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Production Type
Gas production
Oil and Gas production
Oil production
Existing Gas
Flotation Systems
20%
40%
60%
This distribution profile is based on the estimate that thirty-five percent (35%) of offshore
operators use gas flotation technology and the general fact that less "gas only" platforms currently have
gas flotation systems than "oil only" platforms.12 The aggregate number of platforms for each production
type with gas flotation units equals thirty-five percent of the total platform population. Although EPA
Is unaware of any data of gas flotation usage in the offshore industry to verify the distribution profile,
EPA is confident that the profile accurately parallels the actual gas flotation population and for costing
purposes it provides a conservative basis for developing industry compliance costs. Total industry gas
flotation capital costs were based on the number of facilities that do not currently have gas flotation units.
5.1.2 Gas Flotation - BAT Annual Costs
EPA calculated the BAT annual operating and maintenance (O&M) costs using the gas flotation
distribution profiles discussed in the preceding section. For those platforms that already have gas
flotation units installed, the annual O&M costs of complying with BAT limitations based gas flotation are
estimated to be higher .than their current annual O&M costs because of modifications and enhancements
needed to improve system performance. Enhanced removals of oil and grease can be achieved by existing
gas flotation systems through closer supervision of the units by the platform operators, additional
monitoring of the systems operating parameters, proper sizing of the unit to improve hydraulic loading,
additional maintenance of the process equipment, and addition and/or proper usage of flocculation
enhancement chemicals. These costs are incremental to the current annual costs. EPA estimates that the
additional labor and other improvements necessary to achieve compliance with BAT limits will
approximately double the annual O&M costs for existing flotation systems currently achieving BPT
quality effluent. Since BAT facilities needing to install a gas flotation unit (or other technology) to
comply with the limit would design and select a treatment system to meet the BAT oil and grease limit,
additional O&M costs would not be incurred. Total annual O&M costs for existing platforms that will
need to install gas flotation were determined to be approximately ten percent (10%) of the capital costs
of the new flotation system. EPA notes that the BAT and NSPS limitations of the final rule are based
on data from existing facilities identified as being representative of platforms having well-operated gas
XII-15
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flotation units. Thus, although not all existing facilities with gas flotation units would be expected to
already be meeting the BAT and NSPS oil and grease limits of this rule, the data shows that a portion
of the industry can already comply with the limitations of this final rule without incurring an additional
cost. Because EPA does not know how many of these facilities would be able to comply without
incurring additional cost, no allowance is made in EPA's cost projections to exclude such facilities in
determining the cost of compliance for this rule. Thus, EPA is confident that compliance costs are not
underestimated, and likely to be somewhat overestimated. Qn balance, however, EPA believes these cost
projections are representative of the aggregate compliance costs for the entire subcategory.
5.1.3 Gas Flotation - NSPS Total Industry Capital Costs
The 1984 OOC report stated that even in the absence of produced water limitations more stringent
than BPT, eighty percent (80%) of new platforms would be designed with gas flotation systems for
treatment of produced water.10 EPA based compliance cost projections on the assumption that in the
absence of NSPS limitations 20 percent of new platforms would not include a flotation unit in their
treatment system design. This 20 percent of new platforms is considered to incur an incremental cost
to comply with NSPS limitations. In estimating NSPS capital costs, EPA assumed that it was necessary
for the operator to add-on a complete flotation system. The entire costs for adding on such a system were
used in EPA's economic impact analyses. EPA notes that although some new platforms would not have
planned to install flotation systems, the platforms would have contained some other type of treatment
technology and it is entirely possible that the alternative system would enable compliance without
incurring additional costs to comply with the NSPS limitations. EPA also notes that by adding on a
flotation system to comply with NSPS limits the operator may actually forego installation of other
produced water treatment units, with the result being that the gas flotation unit would serve as a
replacement system rather than an add-on system, incurring no, or reduced, incremental costs. However,
in costing this rule it has been assumed that an add-on treatment system will be required and costs of
entire flotation systems for 20 percent of all new sources have been included.
r
For those eighty percent (80%) of new platforms that are expected to include gas flotation in the
original design, capital costs consist only of an engineering redesign cost and not a new unit cost. It is
assumed that the gas flotation units included in the existing design of the new source platforms were able,
at a minimum, to achieve the current BPT oil and grease limitations. For these systems to achieve the
more stringent limitations of this final rule, EPA assumed that there may be an additional cost to upgrade
the system. A design upgrade could consist of increasing the system's retention time through increasing
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the cell size or the addition of another cell, maximizing separation efficiency through properly sizing
rotors, gas dispersers, and chemical injection equipment, and optimizing the system's performance
through the addition of state-of-the-art instrumentation and controls. This system redesign cost was
assumed to be fifteen percent (15%) of the NSPS flotation system capital cost.
5.1.4 Gas Flotation - NSPS Total Industry Annual Costs
The NSPS annual O&M costs for new platforms were calculated using the same NSPS profile
used In the development of the NSPS capital costs. For the twenty percent (20%) of new platforms
assumed to not already include flotation systems in the design, the annual costs are ten percent (10%) of
the capital costs. However, for those new platforms that already have flotation systems in the design
plans of the facility, there are no incremental annual costs for compliance with the NSPS limitations.
EPA assumed that since there is a flotation system in the design of a facUity, there are also annual cost
associated with operation of that system in the financial projection of that project. The improved
performance of that system has been accounted for by improving the design parameters of the flotation
system.
5.2 ONSHORE DISPOSAL COSTS
EPA assumed that those facilities currently piping produced water to shore for treatment would
continue to do so and;no additional offshore treatment would be necessary. Since they are treating and
discharging produced water which originated in.the offshore subcategory, the onshore treatment facilities
are required to meet the oil and grease limitations of this final rule and are expected to achieve
compliance through either upgrading existing equipment or installing new treatment equipment. For this
costing exercise, EPA evaluated the costs for installing new equipment at the onshore treatment facilities.
For the 37 percent of the facilities piping to shore for treatment, EPA developed costs for onshore
treatment by gas flotation, granular filtration, and reinjection technologies. No onshore treatment costs
were developed for the Pacific or Alaska offshore regions since no information was available on the
extent to which operators pipe produced water to shore for treatment.
The onshore treatment costs were evaluated for both the BAT and NSPS scenarios. However,
for the NSPS scenario, EPA projects that the cost to install piping to the offshore facility would greatly
exceed the costs of installing the necessary treatment control technology onsite at the offshore platforms.
Thus, it is assumed no new sources will pipe produced water to shore for treatment.
XII-17
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The basis for the onshore treatment system costs are similar to the offshore per-platform system
costs, although there are a few exceptions. The exceptions are: (1) the offshore installation factor (a
multiplier applied to onshore costs to account for the increased cost of transporting and installing
equipment offshore) of 3.5 was not used; (2) there were no platform addition costs; (3) no centrifuge cost
was assigned for onshore filtration or reinjection; and (4) the cost for the installation of injection wells
was estimated at $155,000 (1986 dollars).13 EPA assumed that a centrifuge would be unnecessary to
dewater the filter backwash because adequate space would be available at an onshore treatment facility.
The centrifuge is assumed to be needed on offshore platforms because of the limited space available to
capture, settle and store backwash volumes from the granular filter.
Table XII-8 and XII-9 present the onshore capital and annual costs for the gas flotation, granular
filtration, and reinjection technologies. Tables XH-10 and XII-11 present the regional and total capital
and annual costs for onshore gas flotation, granular filtration, and reinjection at both the three and four
milage delineations.
TABLE XII-8
BAT ONSHORE TREATMENT CAPITAL COSTS
(COST IN 1986 DOLLARS)
J-'-
Gas Flotation*
Granular Filtration*
Reinjection*
System Flow Rate - Barrels of Produced Water Per Day
200 -
90,505
133,515
160,832
1,000
90,505
187,769
170,313
5,000
116,032
187,796
214,649
10,000
127,636
237,526
404,392
40,000
162,445
359,210
908,175
*Adjusted from 1991 dollars using an ENR-CCI Ratio of 4295/4775
TABLE XII-9
BAT ONSHORE TREATMENT ANNUAL COSTS
(COST IN 1986 DOLLARS)
s
Gas Flotation
Granular Filtration
Reinjection
System Flow Rate - Barrels "of Produced Water Per Day
200
9,505
13,892
16,623
1,000
9,051
21,437
19,691'
5,000
11,603
32,377
35,649
10,000
12,764
50,853
67,539
40,00>J
16,245
144,221
199,118
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TABLE XII-10
BAT - GULF OF MEXICO ONSHORE COMPLIANCE COSTS: 3 MILE PROFILE
.
Capital Costs
Flotation
Filtration
Reinjection
Gulf of Mexico
<. 3
2,597,529
4,561,941
9,896,552
>3
64,125,816
110,536,066
246,026,369
Total
.
66,723,345
1 15,098,007
255,922,921
O&M Costs
Flotation
Filtration
Reinjection
258,962
1,094,053
3,434,251
6,189,233
26,838,862
88,611,928
6,448,195
27,932,915
92,046,179
TABLE XII-11
BAT - GULF OF MEXICO ONSHORE COMPLIANCE COSTS: 4 MILE PROFILE
Capital Costs
Flotation
Filtration
Reinjection
Gulf of Mexico
<.4 ' ,
6,837,250
12,061,468
28,310,413
>4
59,886,094
103,036,539
267,612,508
Total ^
66,723,344
115,098,007
295,922,921
O&M Costs
Flotation
Filtration
Reinjection
678,706
2,905,422
9,258,965
5,769,490
25,027,493
82,787,214
6,448,196
27,932,915
92,046,179
B.O BCT OPTIONS CONSIDERED
The five options selected for final consideration in developing BCT limitations for produced water
lischarges were based on reinjection, gas flotation, or granular filtration technologies.
Option 1: BPT All Structures: EPA included as an option setting BCT equal to BPT
By doing so, EPA realized that the removals of conventional pollutants due to compliance
with stricter standards may not be cost reasonable under the BCT cost tests.
XII-19
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Option 2: Flotation All: All discharge? of produced water, regardless of the water depth
or distance from shore at which they are located, would be required to meet limitations
on oil and grease content at 29 mg/1 monthly average and a daily maximum of 42 mg/1.
The technology basis for these limits is improved operating performance of gas flotation.
Option 3: Zero 3 Miles Gulf and Alaska: Wells located at a distance of 3 nautical miles
or less from shore would be prohibited from discharging produced water. Facilities
located more than 3 miles from shore would be required to meet oil and grease
limitations of 29 mg/1 monthly average and 42 mg/1 daily maximum based on the
improved operating performance of gas flotation technology. Because of the unacceptable
level of air emissions associated with reinjection off California, all wells off California
would be excluded from the zero discharge requirement. Currently existing single-well
dischargers in the Gulf of Mexico would also be excluded from the discharge prohibition
because of the economic impacts of a zero discharge limit on these projects. Single-well
dischargers are single-well facilities which operate their own and do not share produced
water treatment systems. Discharges of produced water from these excluded facilities
would be required to comply with the oil and grease limitations based on improved
operating performance of gas flotation technology.
Option 4: Zero Discharge Gulf and Alaska: This option would prohibit all discharges
of produced water based on reinjection of the produced water. All facilities off
California and all currently existing single-well dischargers in the Gulf of Mexico would
be excluded from zero discharge limitation. They would, however, be required to
comply with the oil and grease limitations developed based on improved operating
performance of gas flotation technology.
Option 5: Filter 4 miles Gulf and Alaska: Wells located at a distance of 4 nautical
miles or less from shore would be required to meet oil and grease limitations of 16 mg/1
monthly average .and 29 mg/1 daily maximum based on granular filtration technology.
Facilities located more than 4 miles from shore would be required to meet the existing
BPT oil and grease limitations of 48 mg/1 monthly average and 72 mg/1 daily maximum.
In referring to the options considered for control of produced water discharges, the Gulf of
Mexico, California and Alaska regions are used in the option descriptions and accompanying discussion.
Use of these regions in this way is only a "shorthand" way of referring to regulatory packages and does
not exclude geographic areas from coverage under this rule. For the BCT, BAT and NSPS limitations
under this rule, all offshore areas other than offshore California and Alaska would be required to comply
with the limitations established for the Gulf of Mexico.
7.0 BAT AND NSPS OPTIONS CONSIDERED
The BAT limitations considered for produced water are similar to those previously discussed for
BCT. The only difference is that while BCT options are intended to control the conventional pollutants,
BAT options focus on the control of toxic and nonconventional pollutants. Oil and grease remains the
xn-20
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Oflty regulated pollutant in produced water. It is being limited under BAT as an indicator pollutant
controlling the discharge of toxic pollutants.
The options considered for NSPS are similar to those considered for BAT, with the only
exception being that the exclusion for single-well dischargers (Gulf tb) from the zero discharge limitation
is not applicable under NSPS. This exclusion was developed because of the costs, economic impacts and
production impacts associated with requiring single-well dischargers currently in operation to retrofit
filtration and reinjection equipment. Since new sources are able to allow for adequate space in designing
new facilities and compliance costs are less for the new sources, economic and production impacts on
these facilities are significantly reduced.
8.0 OPTION EVALUATION
An analysis of each regulatory option was conducted to determine:
Incremental costs incurred by industry to comply with the regulation.
Reduction of pollutants discharged to the surface waters.
The following sections present the analysis of each regulatory option.
8.1 BCT, BAT AND NSPS INCREMENTAL COMPLIANCE COSTS
The BCT and BAT incremental costs are the same for each option because oil and grease is the
only regulated pollutant in produced water (oil and grease is considered both a conventional and an
indicator for toxic pollutants for this rule). The incremental compliance costs are equal to the total
compliance incurred under BCT or BAT because all of the regulatory options, besides the BPT All option
(which incurs zero incremental costs), are add-on technologies. Except in the case where existing gas
flotation systems exist and in this case the compliance costs are incremental to the current BPT
compliance costs. Table XH-12 presents the BCT and BAT incremental compliance costs for the five
regulatory options.
The incremental costs for NSPS are also equal to the total costs for the add-on technology except
for the facilities that have gas flotation systems in the design plans for future platforms. In this case the
design upgrade costs are considered incremental to original design and capital costs included in the
financial projection of that production operation. Table XII-13 presents the NSPS incremental compliance
costs for the five regulatory options.
xn-2i
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TABLE XII-12
SUMMARY OF INCREMENTAL COSTS AND CONTAMINANT REMOVAL - BAT
Options
Potion 1
BPT All
Option 2
Improved Gas Flotation All
Potion 3
Zero Discharge Within 3 Miles (Gulf
and Alaska) Exemption: Gulf Ib and
California - Improved Gas Flotation
Improved Gas Flotation Beyond 3
Miles
Option 4
Zero Discharge All (Gulf and Alaska)
Exemption: Gulf Ib and California -
Improved Gas Flotation
Options
Granular Filtration Within 4 Miles
(Gulf of Mexico, California, Alaska)
BPT Beyond 4 Miles
'Capital
Cost
($000}
0
382,488
465,470
2,698,632
158,106
Annual
O&M Cost
($000/yr)
0
46,598
54,147
292,531
14,250
Pollutant Reduction (Ib/yr)
Conventional
0
9,611,917
9,768,688
20,111,718
1,839,391
Metals
0
12,934,384
13,199,699
30,702,408
306,626
Organics
0
2,531,860
2,552,511
3,914,715
41,473
Total
Radium
0
0.0197
0.0218
0.1607
O.W24
TABLE XII-13
SUMMARY OF INCREMENTAL COMPLIANCE COSTS AND CONTAMINANT
REMOVAL-NSPS
OptwnS
OPTION 1
BPT All
OPTION 2
Improved Gas Flotation All
OPTIONS
Zero Discharge Within 3 Miles (Gulf
and Alaska) Exemption: California -
Improved Gas Flotation
Improved Gas Flotation Beyond 3
Miles
OPTION 4
Zero Discharge All (Gulf and
Alaska)Exemption: California -
Improved Gas Flotation
OPTIONS
Granular Filtration Within 4 Miles
(Gulf of Mexico, California, Alaska)
BPT Beyond 4 Miles
Capital
Cost
($000)
0
84,936
435,432
2,346,308
90,231
Annual
O&M Cost
($000/yr)
0
5,066
26,432
156,310
9,124
Pollutant Reduction (It>/yr)
Conventional
0
6,059,111
7,357,669
14,370,969
1,581,232
Metals
0
5,253,258
6,655,486
14,315,268
168,326
OrganicS
0
1,028,305
1,137,436
1,733,585
22,767
Total
Radium
0
0.0080
0.0191
0.0800
0.0130
XII-22
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8.2 BCT, BAT AND NSPS POLLUTANT REMOVALS
1
: ^1
The incremental pollutant removals associated with BAT and NSPS treatment technologies are 1
determined by comparing the effluent levels after treatment by BAT/NSPS technologies (flotation,
granular filtration, or reinjection) with the effluent levels associated with a typical
flotation or gravity separation).
8.2.11 Gas Flotation and Granular Filtration Effluent Characterization
Characterizations of produced water effluent from granular filtration were
statistical analysis of data collected during EPA's three facility study.14
The characterizations of produced water effluent from gas flotation were
statistical analysis of data collected by EPA and submitted by industry.15 The data
BPT treatment (gas
1
: . 1
obtained through a 1
obtained through a 1
used to develop gas I
flotation effluent estimates are from the OOC 10 Platform Database, the OOC 42 Platform Study, and ' , 1
the Thirty Platform Study. The total oil and grease concentrations available from this data were taken |
1
1
1
for 455 samples from 60 platforms, using well performing platforms and screening for BPT compliance. 1
Appendix 2 presents the data from the above sources. The variation estimates for
from this data subset are presented in Table XII-14.
TABLE XII-14
total oil and grease
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TOTAL OIL AND GREASE VARIATION ESTIMATES
PHYSICAL COMPOSITING - SCREENED FOR BPT COMPLIANCE
Parameters
Delta (6)
Mean concentration (EX)
Log-mean (n J
Log-mean adjusted for 4 grab samples Ou4)
Log-mean adjusted for 4 composite samples Ot4M))
Process variation (a2,,)
Measurement variation (a2^)
Process variation of 4 grab samples (o2^)
Measurement variation of 4 grab samples (a2,*)
Process. variation of 4 composite samples (o2^^)
Estimate
0.0044
23.2256
3.0563
3.1197
3.1357
0.1578
0.0285
0.0441
0.0726
0.0190
The estimated long-term average and limitations for total oil and grease from Data Set Three are:
Long-Term Average = 23.5 mg/1
Daily Maximum = 42.4 mg/1
Monthly Average = 28.9 mg/1.
XH-23
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Table Xn-15 presents the produced water effluent characteristics following BPT-level treatment
and BCT/BAT/NSPS-level treatment.16
TABLE XII-15
POLLUTANT LOADING CHARACTERIZATION PRODUCED WATER16
]?olluf ant Parameter
:
Oil & Grease
TSS
Priority and Non-conventional
Organic Pollutants:
2-Butanone
2,4-Dimethylphenol
Anthracene
Benzene
Benzo(a)pyrene
Chlorobenzene
Di-n-butylphthalate
Ethylbenzene
n-Alkanes
Naphthalene
p-Chloro-m-cresol
Phenol
Steranes
Toluene
Triterpanes
Total xylenes
Priority and Non-conventional
Metal Pollutants:
Aluminum
Arsenic
Barium
Boron
Cadmium
Copper
Iron
Lead
Manganese
Nickel
Titanium
Zinc
Radionuclides:
Radium 226
Radium 228
BPT-tevel
Effluent
Improved Gas
Flotation Effluent
Granular Filtration
Effluent
Concentrations jng/l
25.0
67:5
23.5
30.015
11.33'"
21. 1714
, y '""" 'Concentrations #g/l
1028:96
317.13
18.51
2978:69
11.61
19.47
16.08
323.62
1641,50
243.58
25.24
1538:28
77.50
1897.11
78.00
695.03
78.01
114.19
55563.80
25740.25
22.62
444.66
4915.87
195.09
' 115,87
1705.46
7.00
1190.13
0.00022628
0.00027671
411.58
250.00
7.40
1225.91
4.65
7.79
6.43
62.18
656.60
92.02
10.10
536.00
31.00
827.80
31.20
378.01
49.93
73.08
35560.83
16473.76
14.47
284.58
3146.15
124.86
74.16
1091.49
4.48
133.85
0.00020365
0.00024904
926.06
285.41
16.66
2875.92
10.45
17.52
14.47
297.02
1477.35
176.81
22.34
1384.46
69.75
1749.14
70.20
664.45
34.30
15.81
51624.33
25593.53
18.09
418.65
3618.57
156.07
110.19
1364.37
5.83
832.38
0.00020365
0.00024904
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Note
Radium values are based only on averages of the OOC 44 platform study and are used to approximate radium removal.
The values are based on concentrations in picocuries per liter and are as follows:
(1) Average Radium-226 estimated at 226.28 pCi/1.
(2) Average Radium-228 estimated at 276.71 pCi/1.
XII-24
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8.2.2 Annual BCT/BAT/NSPS Pollutant Removals
Computer models were developed to calculate pollutant removals for the five treatment options
on a regional basis using the model flow and contaminant removal data. BAT and NSPS pollutant
removal quantities for each option were calculated by multiplying the average produced water flow rate
for each model platform by the difference in pollutant concentrations in BPT effluent and BAT or NSPS
effluent concentrations.
Table XII-16 presents the annual volumes of produced water treated and discharged offshore for
existing structures (BAT flow rates) and for new structures (NSPS flow rates). These volumes are based
on the yearly average produced water flow rates presented in Appendix 1 and do not include produced
water flows from existing (BAT) structures which currently treat produced water onshore (thirty-seven
percent of all existing structures pipe produced water to shore for treatment).
TABLE XII-16
ANNUAL PRODUCED WATER DISCHARGES
(bbl/yr)
_4
BAT
Within 3 miles
Beyond 3 miles
Total
Within 4 miles
Beyond 4 miles
Total
NSPS
Within 3 miles
Beyond 3 miles
Total
Within 4 miles
Beyond 4 miles
Total
<ปulf of Mexico
All Structures
9,263,996
559.867.083
569,131,079
35,957,511
533.173.568
569,131,079
31,761,205
345.481.625
377,242,830
37,420,895
339.821.935
377,242,830
All Structures
Except IBs
^^i
8,361,212
551,635.103
559,996,315
34,001,327
525.994.988
559,996,315
31,704,995
343,927.455
375,632,450
37,303,365
338.329.085
375,632,450
Pacific
All Structures
HHBBMBI^BHM
36,797,749
97.310.701
134,108,450
51,516,848
82,591.601
134,108,449
0
0
0
0
0
0
Alaska
All Structures
0
0
0
0
o
0
35,532,020
9,287.060
44,819,080
35,532,0206
9,287.060
44,819,080
Pollutant removals were determined for each regulatory option considered and are presented in
Tables XH-17 and XII-18 for BAT and NSPS respectively. The terms organics and metals represents
those analytes presented in Table XII-15 and conventional refers to oil and grease and TSS.
xn-25
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TABLE XII-17
BAT ANNUAL REGIONALIZED POLLUTANT REMOVALS16
(POUNDS)
Option 1
Option 2
Conventional
Organics
Metals
Radium 226
Radium 228
Option 3
Conventional
Organics
Metals
Radium 226
Radium 228
Option 4
Conventional;;
Organics
Metals
Radium 226
Radium 228
Option 5
Conventional
Organics
Metals
Radium 226
Radium 228
"Wi&ut*
Gulf of
Mexico
0
126,621
33,356
170,408
0.0001
0.0001
283,392
54,007
435,723
0.0011
0.0013
283,392
54,007
435,723
0.0011
0.0013
756,107
17,049
126,051
0.0005
0.0006
Pacific
0
502,954
132,479
676,787
0.0005
0.0006
502,954
132,479
676,787
0.0005
0.0006
502,954
132,479.
676,787.
0.0005
0.0006
1,083,285
24,424
180,575
0.0006
0.0008
Sub-Total
0
629,574
165,835
847,195
0.0006
0.0007
786,345
186,486
1,112,510
0.0015
0.0019
786,345
186,486
1,112,510
0.0015
0.0019
1,839,391
41,473
306,626
0.0011
0.0013
Beyond*
Gulf of
Mexico
0
7,652,294
2,015,692
10,297,453
0.0070
0.0086
7,652,294
2,015,692
10,297,453
0.0070
0.0086
17,995,325
3,377,894
27,800,162
0.0695
0.0850
0.0
0.0
0.0
0.0
0.0
Pacific
0
1,330,048
350,333
1,789,736
0.0012
0.0015
1,330,048
350,333
1,789,736
0.0012
0.0015
1,330,048
350,335
1,789,736
0.0012
0.0015
0.0
0.0
0.0
0.0
0.0
Sub-Total
0
8,982,342
2,366,025
12,087,189
0.0083
0.0101
8,982,342
2,366,025
12,087,189
0.0087
0.0101
19,325,373
3,728,229
29,589,898
0.0708
0.0865
0.0
0.0
0.0
0.0
0.0
, Total
0
9,611,917
2,531,860
12,934,384
0.0089
0.0108
9,768,688
2,552,511
13,199,699
0.0098
0.0120
20,111,718
3,914,715
30,702,408
0.0723
0.0884
1,839,391
41,473
306,626
0.0011
0.0013
*For all Options, Alaska has been removed since there are no BAT structures.
2Radium values are based only on averages of the OOC 44 platform study and are used to approximate radium
removal. The values are based on concentrations in picocuries per liter and are as follows:
(1) Average Radium-226 estimated at 226.28 pCi/1.
(2) Average Radium-228 estimated at 276.71 pCi/1.
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TABLE XII-18
NSPS ANNUAL REGIONALIZED POLLUTANT REMOVALS"
(POUNDS)
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-
Option 1
Option 2
Conventionals
Organics
Metals
Radium 226
Radium 228
Option 3
Conventionals
Organics
Metals
Radium 226
Radium 228
Option 4
Conventionals
Organics
Metals
Radium 226
Radium 228
Option 5
Conventionals
Organics
Metals
Radium 226
Radium 228
Within*
Gulf of
Mexico
0
460,959
78,527
401,171
0.0003
0.0003
1,093,300
132,388
1,093,201
0.0027
0.0034
1,093,300
132,388
1,093,201
0.0027
0.0034
834,073
12,155
89,864
0.0003
0.0004
Alaska
0
485,654
80,591
411,703
0.0003
0.0003
1,151,821
135,861
1,121,901
0.0028
0.0034
1,151,871
135,861
1,121,901
0.0028
0.0034
747,159
10,612
78,462
0.0003
0.0003
Sub-Total
0
946,612
159,118
812,874
0.0006
0.0007
2,245,171
268,249
2,215,102
0.0056
0.0068
2,245,171
268,249
-* 2,215,102
0.0056
0.0068
1,581,232
22,767
168,326
0.0006
0.0007
Beyond1
Gulf of
Mexico
0
4,985,563
848,126
4,332,777
0.0030
0.0036
4,985,563
848,126
4,332,777
0.0030
0.0036
11,824,732
1,429,826
11,806,933
0.0297
0.0363
0.0
0.0
0.0
0.0
0.0
Alaska
0
126,936
21,061
107,607
0.0001
0.0001
126,936
21,061
107,607
0.0001
0.0001
301,066
35,510
293,233
0.0007
0.0009
0.0
0.0
0.0
0.0
0.0
Sub-Total
0
5,112,499
869,187
4,440,384
0.0030
0.0037
5,112,949
869,187
4,440,384
0.0030
0.0037
12,125,798
1,465,336
12,100,166
0.0304
0.0372
0.0
0.0
0.0
0.0
0.0
Total
0
6,509,111
1,028,305
5,253,258
0.0036
0.0044
7,357,669
1,137,436
6,655,486
0.0086
0.0105
14,370,969
1,733,585
14,315,268
0.0360
0.0440
1,581,232
22,767
168,326
0.0006
0.0007
'For all Options, Pacific has been removed since the there are no NSPS Structures.
2Radium values are based only on averages of the OOC 44 platform study and are used to approximate
radium removal. The values are based on concentrations in picocuries per liter and are as follows:
(1) Average Radium-226 estimated at 226.28 pCi/1.
(2) Average Radium-228 estimated at 276.71 pCi/1.
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9.0 BCT COST TEST
The BCT cost test methodology produced water is the same as that described in Section XI.7.0.
The pollutant parameters used in this analysis are total suspended Solids (TSS) and oil and grease. Refer
to Table Xtt-12 for a summary of incremental costs and conventional pollutant removals for each
regulatory option.
9.1 BCT COST TEST CALCULATIONS
All of the produced water options considered for BCT regulation fail the BCT cost test except
for the BCT option equal to BPT. For every option, except BPT AH, the ratio of cost of pollutant
removal to pounds of pollutant removed (POTW Test) exceeds the POTW benchmark of $0.46 per
pound. Table XH-19 presents the BCT Cost Test Analysis.
TABLE XII-19
PRODUCED WATER BCT COST TEST
<**0ป
Option 1
Option 2
Options
Option 4
Options
Pollutant Removals
(Ibs)
0
9,611,917
9,768,688
20,111,718
1,839,391
Peak Annualized
Costs ($/yr)
0
96,290,000
115,474,000
654,217,000
38,635,000
POTW Cost
Ratio <$/ซ>)
0
10.02
11.82
32.53
21.00
Pass
POTW?
Yes
No
No
No
No
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10.0 REFERENCES
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
NKRE, "Costing of Produced Water Treatment and Disposal for Platforms in Various
Locations," prepared for the Environmental Protection Agency, February, 10, 1983.
Hydrotechnic Corporation, "Cost Estimates for Systems to Treat Produced Water Discharges hi
the Offshore Gas and Oil Industry to Meet BAT and NSPS," prepared for Effluent Guidelines
Division, U.S. Environmental Protection Agency, August 27, 1982.
Larry Moore, Chevron, New Orleans, personal Communication with Joe Dawley, SAIC,
regarding available platform space and platform addition costs. September 19, 1991.
Energy Information Agency, "Analysis of Produced Water Treatment Technology Costs "
September 12, 1991.
Walk, Haydel & Associates, "Estimated Costs of Removal and Disposal of Produced Water
Solids from New Facilities - Summary Report.No. 7," prepared for American Petroleum Institute,
submitted with API comments to the 1985 Proposal, March 14, 1986.
ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
Wastes at the Conoco, Inc. - Maljamar Oil Field," Draft, prepared for Industrial Technology
Division, U.S. Environmental Protection Agency, March 1990. (Offshore RulemaJdng Record
Volume 115)
Gruy Engineering Corporation, "A Study of the Economic Impacts of Produced Water Effluent
Guidelines for the United States Offshore Area," prepared for the Effluent Guidelines Steering
Committee of the American Petroleum Institute, November 1990.
Letter from'Maureen Kaplan, Eastern Research Group, to Joe Dawley, SAIC, "Reconstruction
of the logic used by Kohlmann Ruggiero Engineers in estimating the number of dry holes
available for reinjection of produced water," June 4, 1992. ;
U.S. Department of Interior, "Comments to the March 13, 1991 Proposal of Offshore Oil and
Gas Industry Effluent Guidelines," submitted to the U.S. Environmental Protection Agency May
13, 1991. ' y
Walk, Haydel & Associates, Inc., "Potential Impact of Proposed EPA BAT/NSPS Standards for
Produced Water Discharges from Offshore Oil and Gas Extraction Industry," prepared for the
Offshore Operators Committee, January 1984.
Ron Jordan Correspondence with the MMS regarding Platform Inspections.
SAIC, "Estimate of Existing Platforms with Gas Flotation Treatment Systems," prepared for
Engineering and Analysis Division, U.S. Environmental Protection Agency, December 1992.
ERCE, "Offshore Oil and Gas Industry BAT and NSPS Analysis of Implementation Cost and
Contaminant Removal: Produced Water," prepared for USEPA, March 8, 1991.
XH-29
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14. SAIC, "Produced Water Pollutant Variability Factors and Filtration Efficacy Assessments from
the Three Facility Oil and Gas Study," prepared for U.S. Environmental Protection Agency,
March 1991. (Offshore RulemaMng Record Volume 120)
15. SAIC, "Analysis of Oil and Grease Data Associated with Treatment of Produced Water by Gas
Flotation Technology," prepared for Engineering and Analysis Division, U.S. Environmental
Protection Agency, January 13, 1993.
16. Memorandum from Ronald Jordan, Engineering and Analysis Division, U.S. Environmental
Protection Agency, to the Record. "Offshore jbil and Gas - Characterization of BPT- and BAT-
Level Produced Water Effluent," December 1(3, 1992.
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SECTION XIII
COMPLIANCE COSTS AND POLLUTANT LOADING DETERMINATION -
PRODUCED SAND
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1.0 INTRODUCTION
This section presents costs and pollutant reductions for the final proposed regulatory options for
produced sand. These technology costs represent additional investment required beyond those costs
associated with BPT technologies. The methodology used to determine compliance costs and pollutant
loadings for the options considered is based on produced sand generation rate estimates, the characteristics
of unwashed and washed produced sand, and onshore disposal at permitted nonhazardous oilfield waste
(NOW) facilities and at permitted low level radioactivity disposal facilities.
2.0 PRODUCED SAND GENERATION RATES AND DISPOSAL VOLUMES
The volume of produced sand generated is related to the oil production rate. For this evaluation,
EPA used the general rule of thumb that one barrel of produced sand is generated for every two thousand
barrels of oil produced.1 EPA calculated produced sand volumes using peak year oil production estimates
obtained from the Minerals Management Service. From industry data, EPA estimated that approximately
thirty-four percent (34%) of the produced sand generated offshore is transported to shore for disposal and
sixty-six percent (66%) of the produced sand generated offshore is discharged to surface waters.2 Table
Xffl-1 presents the total produced sand volumes generated in each offshore region and the volumes of
produced sand being discharged into the surface waters and transported to shore for disposal under the
BPT no free oil limitations.
3.0 PRODUCED SAND CHARACTERISTICS
The concentrations of oil and grease, moisture content (TSS content), and radioactivity of
unwashed and washed sand are based on the Shell Offshore, Inc. sand washing study conducted in 1991.3
Table XEI-2 presents the characteristics of unwashed and washed produced sand.
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TABLE XIII-1
PRODUCED SAND GENERATION VOLUMES AND BPT DISPOSAL PRACTICES
Region
Gulf of Mexico
Pacific
Alaska
All Regions
Oil
Production
Volume
(Mbbls)
300,000.00
150,000.00
30,000.00
480,000.00
Produced
Sands'
Volume {bbls)
150,000.00
75,000.00
15,000.00
240,000.00
Offshore Disposal
Volume (bbls)
99,000.00
51,00.00
10,200.00
160,200.00
Onshore Disposal
Volume (bbte)
51,000.00
24,000.00
4,800.00
79,800.00
TABLE Xffl-2
PRODUCED SAND CHARACTERISTICS
Aaatyte
Oil & Grease (wt%)
TSS (wt%)
Radium 226 (pCi/1)
Radium 228 (pCi/1)
Unwashed Produced Sand
3.38
75.1
39
41
Washed Produced Sand
1.63
75.1
39
41
4.0 BPT COMPLIANCE COSTS
i
The costs incurred by the industry to comply with the no discharge of free oil limitation on
produced sand consist of two components: onshore disposal cost and sand washing costs. Onshore
disposal costs were assigned to the volumes of produced sand currently being transported to shore for
treatment and/or disposal (thirty-four percent of the total produced sand generated offshore). Sand
washing costs were assigned to the volumes of produced sand currently being discharged to the surface
waters. Table Xffi-3 presents the BPT compliance costs and the following two sections detail the
assumptions used to develop these costs.
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TABLE XIH-3
BPT COMPLIANCE COSTS
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Region
Gulf of Mexico
Pacific
Alaska
All Regions
Total Compliance Costs
Onshore Disposal Cost
(1986$)
502,860
67,200
274,560
844,620
Offshore Compliance Costs
(1986$)
990,000
102,000
510,000
1,602,000
2,446,620
4.1 ONSHORE DISPOSAL COSTS
Transportation costs from the platform to shore were not assigned to the compliance costs because
EPA determined that no direct transportation costs would be associated with the zero discharge
requirement. EPA's determination is based on data from the Offshore Operators Committee (OOC)
produced sand survey and additional information on produced sand handling and disposal practices
submitted by the industry.1 Information from the OOC produced sand survey indicates that produced
sand collected regularly through operation of desanders and blowdowns through valves on vessels,
accounts for less than ten percent of the volume of sand collected annually. The majority of sand is
collected during scheduled cleanouts. The information also indicates that ninety percent (90%) or more
of the produced water treatment system cleanouts produce less than 100 barrels of produced sand. The
cleanouts occur during a platform shutdown and a typical cleanout cycle is once every three to five years.
An operator in the Gulf of Mexico indicated that produced sand is transported to shore by supply boats
and dedicated vessels are seldom used to transport produced sand to shore.4 Based on the available
information, EPA concluded that the volume of produced sand collected from vessel blowdowns is small
enough that operators are able to use the supply boats that service offshore platforms on a frequent and
regular basis, rather than contract for dedicated vessels to transport the waste to shore. The produced
sand collected during tank and vessel cleanouts are typically small volumes that can be transported to
shore using either the regularly scheduled supply boats or the work boats chartered to support the sand
removal or other general maintenance during the platform shutdown.
XIH-3
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The disposal costs for the produced sands were the same as for drill cuttings and are as follows:
$9.86 per barrel in the Gulf of Mexico; $11.44 per barrel in California (Pacific); and $14.00 per barrel |
in Alaska (1986 dollars).5 These costs include transportation from the shore base and disposal at the
facility. |
4.2 SAND WASHING COSTS |
EPA assumed that those operators currently discharging produced sand to the surface waters (66 _
percent by volume of all produced sand generated offshore) would incur some cost to assure compliance. I
EPA assigned sand washing costs to all volumes of produced sand discharged offshore to account for an
offshore compliance cost. ] I
EPA encountered difficulties in estimating the sand washing costs for produced sand. EPA was |
unable to obtain firm estimates of sand washing costs from industry operators. EPA did receive sand
washing cost estimates of $125 per barrel of produced sand from an equipment vendor.9-22 Since the |^
estimate of sand washing is substantially higher than EPA and industry estimates of the cost for onshore
disposal of produced sand, EPA does not consider the $125 per barrel quote to be representative of the
industry-wide cost of sand washing to comply with BPT. In addition, the sand washing estimate provided
by the vendor was for a prototype sand washing system under development and was estimated as the cost ฃ
for a demonstration washing project.
The cost for sand washing can be difficult to estimate, even for the operators. The cost per unit
volume of sand can vary significantly as a function of the sand volume washed, difficulties encountered
in washing, and the success (or lack of success) in washing the sand. Depending on the volume of sand
generated, scheduling constraints, and other economic and logistical considerations, operators choose
between: (1) sand washing and discharge on-site; (2) transporting the sand to another platform where _
the sand from several platforms may be washed and discharged; or (3) onshore disposal to comply with |
the prohibitions on the discharge of free oil. If sand washing is selected by the operator, it is usually j
contracted out to offshore service companies. The goal of the sand washing is to reduce the oil content \
of the produced sand to the extent that the discharge complies with the no free oil limitation. There is, $
however, no guarantee that sand washing will be successful. If after washing the produced sand is still
unable to comply with the no free oil limit, onshore disposal is usually necessary (and therefore incurring ซ
both washing and onshore disposal costs). Also, according to data submitted by the industry, the sand
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washing process generates wastes (washing liquids and a portion of the solids) which are unable to meet
the no free oil limit. These wastes are typically disposed of onshore.3
For the purpose of conducting the BCT cost reasonableness test, and based on the information
discussed above and the frequency at which produced sand is currently disposed of onshore as an
alternative to sand washing, EPA estimated the cost of sand washing to be comparable to the cost of
onshore disposal. The average industry-wide BPT cost of sand washing is estimated at $10 per barrel
of produced sand. Using this cost and the offshore disposal volumes listed in Table XIII-1, the total
industry-wide costs for washing produced sand for each of the three major production regions in the U.S.
were determined. Considering that day rates for offshore service vessels are approximately $3,000 per
day aiad that produced sand volumes are typically less than 100 barrels each, it would be difficult for
operators to achieve significantly lower sand washing costs even if the produced sand from several
platforms are combined. Using a higher per barrel sand washing cost for BPT (as would be suggested
by the equipment vendor estimate discussed above) provides a lower value in the BCT industry cost test
and would make the BCT zero discharge limitation more cost reasonable.
5.0 BPT POLLUTANT REMOVALS
The technology basis for BPT compliance of no free oil is sand washing to remove the free oil
and onshore disposal. The BPT pollutant removals are based on two components: the reduction of oil
and grease due to sand washing and the reduction of TSS, and oil and grease. Some estimates were also
made for removals of radionuclides due to onshore disposal. However, these estimates are only based
on limited information contained in the Shell Offshore, Inc. sand washing study.3
Oil and grease reductions due to sand washing are based on an average oil and grease
concentration of 3.38 percent by weight in untreated produced sand and 1.63 percent by weight in washed
sand. The BPT reductions in oil and grease due to washing (to prevent free oil) are 1.75 percent by
weight oil and grease.
The BPT reductions from onshore disposal of produced sand are based on the sand containing
3.38 percent by weight oil and grease (concentration in unwashed sand). The TSS reductions are based
on the fact that the moisture content of produced sand brought to shore for disposal is 24.9 percent by
weight (or 75.1 percent by weight of the total produced sand is TSS). The reductions in the discharges
of radionuclides are based on average concentrations of Radium-226 and Radium-228 in produced sand.
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The average concentrations of Radiura-226 and Radium-228 in produced sand are calculated to be 39
picocuries per gram of Radium-226 and 41 picocuries per gram of Radium-228. Table Xffl-4 presents
the pollutant removals due to BPT compliance for produced sand.
TABLE XIII-4
BPT POLLUTANT REDUCTIONS
Oil and Grease (Ibs)
Total Suspended Solids (Ibs)
Conventional (Ibs)
Total Conventional (Ibs)
Radium 226 (microcuries)
Radium 228 (microcuries)
Reductions due tj)
Onshore Disposal
2,834,368
62,976,631
65,810,999
Reductions due to
Sand Washing
2,946,030
0
2,946,030
68,757,029
950,055
998,776
6.0, BCT, BAT AND NSPS OPTIONS CONSIDERED
There were two options considered for this waste stream: (1) establish the requirement equaJ to
the current NPDES permit limitations prohibiting discharge of free oil; or (2) prohibit discharge of
produced sand, technologically based on transporting to shore for treatment and/or disposal. The
technology basis for the option limiting free oil content is a water or solvent wash of produced samds
prior to discharge. For the option of no discharge of free oil, the method of determining compliance with
the free oil prohibition is the static sheen test. The prohibition on the discharge of free oil (as; an
indicator of toxic pollutants) or the zero discharge requirement for produced sand would reduce or
eliminate the discharge of conventional and toxic pollutants to surface waters. Since the BPT limitations
prohibit the discharge of free oil, EPA determined that the industry would incur no additional costs from
the BCT, BAT, and NSPS limitations on free oil (Option 1). The incremental costs and the pollutant
removals for the zero discharge option (Option 2) are presented in the following sections.
7.0 ZERO DISCHARGE COMPLIANCE COSTS
In calculating onshore disposal costs of produced sand from production operations in the Gulf of
Mexico, EPA assigned separate costs for the disposal of produced sand at non-hazardous oil field waste
facilities (NOW facilities) and at low level radioactivity disposal facilities. Data from the OOC produced
sand survey indicate that 25 percent of the production facilities located in the Gulf of Mexico generate
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produced sand with radioactivity levels above regulatory concern. Produced sand with NORM levels
above 50 microroentgens per hour or 30 picocuries per gram were assumed to be disposed of in low level
radioactive waste facilities because MMM's Letter to Lessee requires this sand to be transported to shore
for disposal. The available data from production operations offshore Alaska and California indicate that
produced sands from these operations do not have NORM above these levels. Because of pending state
guidelines potentially banning the disposal of NORM contaminated sand at NOW facilities, EPA assigned
costs for disposing the produced sand at a low level radioactivity disposal facility for 25 percent of the
volume of produced sand brought to shore under the zero discharge requirement. Based on disposal
information from a Superfund cleanup project transporting and disposing of low level radioactive solids,
EPA estimated that transportation costs would be $200 per cubic yard. Transportation would be in a
closed gondola railcar. The disposal costs were estimated to be $135 (1986 dollars) per cubic yard at
a NORM facility in Utah. The total transportation and disposal cost at the NORM facility was calculated
to be $69.64 per barrel (1986$).6 The NORM disposal facility is located on a 540-acre site and is
currently in the phase 1 cell of a three phase cell program. Each cell has a capacity of 3 million cubic
yards and all cells are permitted by the State of Utah. In 1992 the facility accepted approximately
200,000 yards of NORM and mixed wastes. After 3 years of operation the first cell is at 20 percent
capacity.7 " ' .,-, -., , - --.
Produced sands generated offshore Alaska, California, and the Gulf of Mexico not considered
to contain NORM were assigned costs for disposal at NOW facilities under the zero discharge
requirement. These costs are the same as those presented in Section XHI.4.1. Table XHI-5 presents the
regional and total costs for the zero discharge option.
TABLE Xm-5
ZERO DISCHARGE DISPOSAL COSTS
f f
, Region
Gulf of Mexico
Pacific
Alaska
All Regions
Disposal
at E&P Facility
Volume (bbls)
112,500
75,000
15,000
202,500
Disposal
at NORM Facility
Volume (bbls)
37,500
0
0
37,500
E&P Facility
.. Disposal Costs
($>
1,109,250
858,000
210,000
2,177,250
NORM Facility
DisposaJ Costs <$)
2,611,500
0
0
2,611,500
Total Disposal Costs: 4,788,750
XIII-7
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8.0 ZERO DISCHARGE POLLUTANT REMOVALS
The technology basis for the BCT, BAT and NSPS zero discharge option for produced sand is
onshore disposal. Oil and grease reductions are based on the assumption that the cleaned produced sand
will no longer be discharged to the surface waters. Thus a net reduction of 1.63 percent oil and grease
is achieved through the zero discharge limitation. The reductions in TSS are based on the moisture
content of produced sand (24.9 percent) and thus a net reduction in TSS of 75.1 percent of the volume
currently discharged is achieved through the zero discharge requirement. The reductions in the
discharges of radionuclides into the surface waters are based on average concentrations of Radium-226
and Radium-228 in produced sand. Table XHI-6 presents the BCT, BAT and NSPS pollutant removals
for oil and grease, TSS, and radionuclides.
TABLE XIH-6
BCT/BAT/NSPS POLLUTANT REDUCTIONS
" s fJ ss * -A j. s |- ff' * ^ " > 'ฃ<**<$
Pollutant Parameter
Oil and Grease (Ibs)
Total Suspended Solids (Ibs)
Total Conventional (Ibs)
Radium 226 (microcuries)
Radium 228 (microcuries)
Removals due to
Zero Discharge
8,524,414
189,403,402
197,927,816
2,790,000*
2,940,000*
*Radium removals are estimated based on rough extrapolation of data included in OOC Produced
Sand Survey.
9.0 BCT/BAT/NSPS INCREMENTAL COSTS AND POLLUTANT REMOVALS
The incremental compliance costs and pollutant removals due to zero discharge of produced sand
are calculated by subtracting the BCT/BAT/NSPS costs and removals from the BPT costs and removals.
Table Xffi-7 presents the incremental compliance costs and pollutant removals for the zero discharge
option.
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TABLE XIII-7
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ZERO DISCHARGE INCREMENTAL COMPLIANCE COSTS AND POLLUTANT
REMOVALS
Pollutant Parameter
Oil and Grease (Ibs)
Total Suspended Solids (Ibs)
Total Conventional (Ibs)
Radium 226 (microcuries)
Radium 228 (microcuries)
jncremental Compliance Costs (1986$)
Removals due to
Zero Discharge
2,744,016
126,426,771
129,170,787
1,839,945*
1,941,224*
2,342,130
*Radium removals are estimated based on rough extrapolation of data included in OOC Produced
Sand Survey.
10.0 BCT COST TEST
Since there are no incremental costs due to the no free oil limitation, Option 1 was assumed to
pass the BCT cost test. This section presents the results of the BCT cost test for the zero discharge
option. The methodology for the BCT cost test is presented in Section XI.7.0.
The BPT limitations on produced sand of no free oil result in a reduction of 68,757,029 pounds
per year of conventional pollutants at a cost of $2,446,620 per year (1986 dollars). Dividing the cost
by pollutant removal, the BPT cost per pound of conventional pollutants removed for produced ,-sand is
$0.0355 per pound (1986 dollars). The calculation is as follows:
BPT Cost Ratio = $2,446,620 $
68,757,029 Ibs. *U'U:O:)
The POTW cost test represents the cost per pound of BCT level of control incremental to BPT,
or tilie ratio of incremental cost to incremental pollutant removal. The POTW rate is calculated as
follows:
POTW Cost Test Ratio = $2,342,130
129,170,787 Ibs.
XIII-9
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The industry cost ratio (ICR) represents the ratio of achieving BCT level of control incremental
to BPT versus achieving BPT level of control to the raw waste load, or the POTW ratio divided by the
BPT ratio. The ICR calculation is as follows:
ICR = POTW Ratio ป 0-0181 = o
BPT Cost Ratio 0.0355
The results of the BCT cost reasonableness test for the zero discharge option are presented! in
Table Xffl-8.
TABLE XIII-8
BCT COST TEST PRODUCED SAND
.
BCT Option
Zero Discharge
Incremental
Conventional
Pollutants
Removed
flb/ytf
129,170,787
,,, >-,-
Incremental
Compliance
Cost
($/year),
2,342,130
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POTW
Cost/ Ratio
<$/ซ))
0.0181
Pa$s
Y
**
ICR
Ratio
0.5099
J*ass
Y
Since the ICR test result is less than 1.29, the result passes the industry cost-effectiveness test.
The zero discharge option for produced sand is found to be cost-reasonable since the option passed both
tests.
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11.0 REFERENCES
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1. James P. Ray, "Offshore Discharges of Drill Cuttings," Outer Continental Shelf Frontier
Technology. Proceedings of a Symposium, National Academy of Sciences, December 6, 1979.
{Offshore Rulemaking Record Volume 18)
2. Offshore Operators Committee. "Response to EPA Request for Additional Information," letter
from J.F. Branch, Chairman Offshore Operators Committee, to Ronald P. Jordan, Engineering
and Analysis Division, U.S. Environmental Protection Agency. August 30, 1991.
3. Letter from R.J. Vallejo, Shell Offshore Inc. to D.J. Bourgeois, Minerals Management Service.
"Produced Sand Discharge Monitoring Study Interim Data Submittal." June 11, 1991. (Offshore
Rulemaking Record Volume 147)
4. Andrew Parker, Marathon Oil Co., Lafayette, LA., personal communication with Joe Dawley,
SAIC, regarding produced sand washing and disposal costs. September 16, 1992.
5. Walk, Haydel & Associates, Inc., "Water-Based Drilling Fluids and Cuttings Disposal Study
Update," January 1989. Submitted as comments to 53 FR 41356 by the American Petroleum
Institute, January 18, 1989. (Offshore Rulemaking Record Volume 94)
6. New Jersey Department of Environmental Protection, "Briefing to the U.S. Department of
Energy on the use of the Envirocare of Utah Facility for Disposal of Wastes from the Formerly
Utilized Sites Remedial Action Program Sites in New Jersey," September 14, 1989.
7. Kurt Higgins, Envirocare of Utah, personal communication with Joe Dawley, SAIC, regarding
capacity at Envirocare NORM facility. January 12, 1993.
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SECTION XIV
COMPLIANCE COST AND POLLUTANT LOADING DETERMINATION -
WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
1.0 INTRODUCTION
This section presents the compliance costs for the final regulatory options for treatment and
disposal of well treatment, workover, and completion fluids.
2.0 COMPLIANCE COSTS AND POLLUTANT REMOVAL CALCULATION
METHODOLOGY
The compliance costs for the BCT, BAT and NSPS treatment options for well treatment,
workover, and completion (TWC) fluids are based on volumes of TWC fluids generated and the size of
the production platform where the fluids are being generated. Pollutant removals associated with the
treatment options were not calculated because there is insufficient data on the chemical characteristics of
well treatment, workover, and completion fluids and the fact that since these fluids vary from well to
well, a generalized characterization of TWC fluids would be inadequate.
3.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS GENERATION
RATES
The average volume of workover and completion fluids generated is 300 barrels per well. This
volume accounts for a preflush and postfiushing of the well and weighting fluid for a 10,000 foot well.
According to industry comments and literature, workover and completion fluids are typically reused at
least once, so if the same workover or completion is used for two wells, the fluid generated per well is
reduced to 150 barrels. The average volume of treatment fluids generated is 250 barrels per well and
treatment fluids are typically spent at the end of the job, and thus are not reused. Well workovers or
treatment jobs were reported to occur approximately every four years. Well completions are a function
of the number of development wells drilled.1
For the purpose of estimating the volumes of well treatment, workover, and; completion fluids
generated, EPA projected the occurrences of well treatments, workovers, and completions over a fifteen
XIV-1
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year period. Yearly vommes were calculated based on the yearly average of the total volumes generated
over the fifteen year period.
4.0 BCT REGULATORY OPTIONS ;
The BCT limitations for the final rule prohibit the discharge of free oil. Compliance with this
limitation is determined by the static sheen test. Because of a lack of sufficient data regarding the levels
of conventional pollutants present in both treated and untreated well treatment, workover, and completion
fluids, EPA only considered the BCT option as being equal to BPT. There are no costs or non-water
quality environmental impacts associated with this BCT limitation.
5.0 BAT AND NSPS OPTIONS CONSIDERED
Well treatment, workover, and completion fluids may either stay in the hole, resurface as a
concentrated volume (slug), or surface from the well dispersed with the produced water. Two options
were considered for BAT and NSPS control for this waste stream: (1) establish the requirements equal
to the current BPT limit of no discharge of free oil (with compliance determined by the static sheen test);
or (2) meet the same limitations on oil and grease content as produced water.
In its preferred option for the March 1991 proposal, EPA presented effluent limitations for well
treatment, completion, and workover fluids based on requiring zero discharge of any concentrated fluids
slug along with a buffer volume preceding and following the fluids slug. Fluids which did not resurface
as a distinct slug were proposed to comply with produced water limitations. EPA has since determined
that a limitation which requires capturing a buffer volume on either side of a fluids slug is not
technologically achievable because it is not always possible and may not be entirely effective. In
commenting on the proposal, the industry characterized completion and workover fluid discharges as
small volume discharges which occur several times during the workover or completion operations which
can last between seven and thirty days. Based on this information, EPA no longer considers the discrete
slug and buffer to be a proper characterization of the way workover, completion or treatment fluids
resurface from the well. Since the fluids often resurface slowly and over a period of time, and are often
commingled with produced water, EPA considers treatment of these fluids commingled with produced
water in the produced water treatment system to be the appropriate technology.
The prohibition on the discharge of free oil and cotreatment with produced water requirement are
both intended to reduce or eliminate the discharge of toxic pollutants. The method of compliance with
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the free oil prohibition is the static sheen test. For the no free oil limitation, EPA determined that there
would be no incremental compliance costs. The incremental costs and pollutant removals for option 2
are discussed in Sections XIV.5. Pollutant removals are not calculated for option 2 because of the
difficulty in characterizing this wastestream.
6.0 INCREMENTAL COST CALCULATIONS
Option 2 requires well treatment, workover, and completion fluids to meet the oil and grease
limitations of produced water based on the technology of cotreating these fluids with the produced water
treatment system. Treating these fluids with produced water is considered to incur no, or minimal,
additional compliance costs. Costs to properly operate the produced water treatment system and monitor
for compliance are accounted for in the compliance cost projections for produced water. However, some
facilities may be unable to treat well treatment, workover, and completion fluids with the produced water
and would incur compliance costs under this option. The following paragraphs discuss the costing
methodology for those facilities.
Some facilities may not be able to commingle TWC fluids with the produced water stream for
treatment because of the relative volume of produced water generated and/or the size of the produced
water treatment system. In this case, the introduction of the TWC fluids to the produced water treatment
system may dramatically affect the separation efficiency of the treatment system resulting in non-
compliance with the NPDES permit and subsequent fines. A 1989 industry report stated that faculties
with less than ten producing wells would most likely experience produced water treatment system upsets
due to commingling of TWC fluids with the produced water stream for treatment. The report stated that
facilities with greater than ten wells will have large enough treatment systems to provide sufficient
dilution of the TWC fluids such that upsets will not occur. To account for the technical limitations of
commingling TWC fluids, EPA developed compliance costs based on the technology of capturing and
transporting the wastes to shore for treatment and/or disposal for facilities with fewer than ten well slots.
The only platforms with fewer than ten well slots are located in the Gulf of Mexico. In the EPA's
production profiles, these facilities are the model platforms Gulf la, Ib, 4, and 6. Onshore disposal costs
for TWC fluids were developed for the Gulf la, Ib, 4, and 6 facilities currently discharging offshore,
which is 67 percent since 37 percent of all structures hi the Gulf are currently piping produced water to
shore for treatment.1
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6.1 VOLUMES GENERATED FROM EXISTING STRUCTURES
i
To calculate the volumes of well treatment and workover fluids generated from existing facilities
(completions are considered new sources), EPA assumed that a well treatment or workover job would
occur every four years. EPA also estimated the average volume generated from either a well treatment
or workover job as being 200 barrels a job (This is the arithmetic average of typical volume generated
from a well treatment, which is 250 barrels, and from a workover, which is 150 barrels). EPA
developed a yearly well treatment/workover volume by dividing the average volume generated by four.
The total volumes of well treatment and workover fluids generated were calculated by multiplying the
average yearly volume by the total number of wells. Table XTV-1 presents the volumes of well treatment
and workover fluids generated from the existing Gulf la, Ib, 4, and 6 model platforms.
TABLE TOV-l
TOTAL BAT WORKOVER AND TREATMENT VOLUME GENERATION ESTIMATES
Structure
fy$et
Oil Facilities:
Gulf la
Gulf Ib
Gulf 4
Gulf 6
Oil and Gas:
Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gas:
Gulf la
Gulf Ib
Gulf 4
Gulf 6
Total:
Total Structures
Discharging
Offshore
89.55
13.23
27.72
11.97
139.86
61.74
75.6
80.01
332.01
170.1
110.88
100.8
1,213.47
Number of
Wetts per
Structure
' 2
2
8
12
2
2
8
12
2
2
8
12
Total Number
of Producing
Welfc
89.55
13.23
110.88
71.82
139.86
, 61.74
302.4
480.06
332.01
i 170.1
443.52
604.8
2^819.97
Volume of
Workover/Treatment Fluids
Generated (barrels per year)
4,477.5
661.5
5,544
3,591
6,993
3,087
15,120
24,003
16,600.5
8,505
22,176
30,240
140,998.5
Onshore
Reinjection
Co$ts ($/yr)
53,730
7,938
66,528
43,092
83,916
37,044
181,440
288,036
199,206
102,060
266,112
362,880
1,691,982
6.2 VOLUMES GENERATED FROM NEW STRUCTURES
The constrained scenario drilling profiles werfc used to calculate the volumes of completion fluids
generated from new sources. EPA identified the projected number of new wells drilled associated with
the Gulf Ib, 4, and 6 model platforms. EPA determined that 1754 wells would be drilled under the
constrained scenario from the Gulf Ib, 4, and 6 model platforms over the 15 year period following
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promulgation of this rule. For a more detailed discussion on the constrained scenario refer to the
Economic Impact Analysis for this rule. A yearly average of wells drilled was calculated to determine
the yearly number of completions and the yearly volume of completion fluids generated. The average
number of wells drilled per year from a Gulf Ib, 4, and 6 model platform is 115.
The number of well treatment and workover jobs for new source wells was determined based on
the fact that a well treatment or workover is done every four years and that 115 new wells are drilled per
year. In the first four years of the fifteen year period, no treatment or completion jobs are done but in
the fifth year 115 treatment or completion jobs are performed and in the subsequent years more treatment
or workover jobs are performed as the population of existing wells increases. The average well
treatrnent/workover fluid volume was used to determine the total treatment/workover fluid volumes
generated from new sources.
Table XIV-2 presents the volumes of well treatment, completion, and workover fluids generated
from new source Gulf Ib, 4, and 6 model platforms.
TABLE XIV-2
NSPS WORKOVER AND COMPLETION SCHEDULE, VOLUME ESTIMATES,
DISPOSAL COSTS
Yeair
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Tfotafe:
Number
af Wdls
Drilled
PcrYeat
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
1,725
Number of
Workover/
Treatment Jobs
Done Per Year;
0
0
0
0
115
115
115
115
230
230
230
230
345
345
345
2,415
Number of
Completion
Jobs Done
Per Yeaf
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
1,725
Volumes of
Workover/Treatment
Fluids Generated
(barrels per year)
0
0
0
0
23,000
23,000
23,000
23,000
46,000
46,000
46,000
46,000
69,000
69,000
69,000
483,000
Volumes of
Completion Fluids
Generated
(barrels pefr year)
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
17,250
258,750
Workover/
Treatment
Injection Costs
ฃpefryear)
0
0
0
0
276,000
276,000
276,000
276,000
552,000
552,000
552,000
552,000
828,000
828,000
828,000
5,796,000;
Completion
Idjettion
Costs
t^jper^dar)
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
207,000
3,105,000
Total Ojisnore
Injection
Costs
($ per fear)
207,000
207,000
207,000
207,000
483,000
483,000
483,000
483,000
759,000
759,000
759,000
759,000
1,035,000
1,035,000
1,035,000
8,901,000
Average workover/treatment costs over 15 year period: 386,400 dollars per year
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6.3 STORAGE COSTS I
EPA assumed that there would be no cost for the containment of the spent fluids prior to
transporting them to shore for disposal. This assumption is based on the fact that during well treatment,
workover, or completion, storage tanks currently exist on the platform or on tending workboats for fluid
storage and separation. (To ensure compliance with the current BPT limitations prohibiting discharge
of free oil, operators must maintain the capability to capture fluids which, if discharged, would cause a
sheen on the receiving waters.) EPA believes that these tanks would provide adequate storage between
capturing the fluids as they come out of the well and the time of transporting the fluids to shore.
6.4 TRANSPORTATION COSTS
EPA also did not assign any incremental costs to the transportation of the fluids to shore. Based
on comments from industry, EPA determined that the volumes would be small and the regularly
scheduled supply boats would have adequate space to transport the containers of spent fluids. As
discussed in the above paragraph, EPA determined that the platforms would have adequate space for
storage of the spent fluids for the periods when the supply boats are not scheduled for the platform or
when offloading to the supply boats is infeasible due to weather conditions.
6.5 ONSHORE DISPOSAL COSTS
EPA determined the most common method of onshore treatment of spent fluids to be injection
into underground formations at a centralized treatment facility. The disposal costs are estimated to be
$12 per barrel. This cost includes the costs of transporting the fluids from an inland port transfer station
to the disposal facility, solids removal if necessary, and reinjection.
6.6 BAT AND NSPS VOLUMES AND DISPOSAL COSTS
Table XIV-1 presents the BAT workover and treatment volume generation estimates and onshore
disposal costs. Volume estimates and disposal costs for completion fluids are not Included in the BAT
costs because completion fluids are considered wastes from new sources and hence are only assigned to
the NSPS costs.
Table XIV-2 presents the yearly NSPS workover, treatment, and completion generation volumes
and disposal costs for the fifteen years following promulgation of this rule. Table XIV-2 also presents
the average yearly workover and treatment fluid disposal costs for the 15 year period.
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7.0ป
1.
REFERENCES
Memorandum from Allison Wiedeman, Project Officer to Marv Rubin, Branch Chief
Supplementary Information to the 1991 Rulemaking on Treatment/ Workover/Completion
Fluids, December 10, 1992.
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SECTION XV
BASIS FOR REGULATION - DECK DRAINAGE
1.0 BCT, BAT AND NSPS OPTIONS CONSIDERED
EPA has selected the option requiring no discharge of free oil for BCT, BAT and NSPS control
of deck drainage. Because of the difficulties in obtaining a representative sample of this wastestream for
conducting the static sheen test since the effluent is located in an inaccessible location, compliance with
this limitation is determined by the visual sheen test. Deck drainage is typically collected in a sump tank
where initial oil/water separation takes place. Water discharged from the sump tank is usually directed
to a skim pile, where additional oil/water separation occurs. The separation process in the skim pile
typically occurs beneath the ocean surface, and the separated water is discharged to the ocean from the
bottom of the skim pile. (The skim pile is essentially a bottomless pipe with internal baffles to collect
the separated oil.) The difficulties in obtaining a representative sample of skim pile effluent preclude the
use of the static sheen test for this wastestream. (The operation of a skim pile is discussed in more detail
in the Development Document.)
In the proposal, EPA presented as its preferred option establishing effluent limitations for deck
s
drainage based on commingling the deck drainage with the produced water. As such, limits based on
filtration within 4 miles from shore, and oil and grease limits equal to current produced water BPT were
selected as preferred hi that proposal. Upon review of information received by EPA since proposal, EPA
determined that because of adverse effects on the produced water treatment system, basing the limitations
on commingling deck drainage with produced water is not technologically available. Commingling deck
drainage with produced water was rejected because (1) the resulting flow variations could result in
frequent upsets of the produced water treatment system, (2) oxygen-enriched deck drainage water, when
combined with the high salt content of produced water could result in increased corrosion, (3) oxygen
present in deck drainage may combine with iron and sulfide in produced water causing solids formation
and fouling treatment equipment, and (4) detergents used in deck washdown cause emulsification of oil
and may degrade the produced water treatment process.
EPA considered and rejected the option of establishing limitations on deck drainage based on an
add-oin system specifically designed to treat only deck drainage. An add-on treatment specifically
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designed to capture and treat deck drainage, other than the type of sump/skim pile systems typically used,
on offshore platforms is not technologically feasible. Deck drainage discharges are not continuous
discharges and they vary significantly in volume. At times of platform washdowns, the discharges are
of relatively low volume and are anticipated. During rainfall events, very large volumes of deck drainage
may be discharged hi a very short period of time. A wastewater treatment system installed to treat only
deck drainage would have to have a large treatment capacity, be idle at most times, and have rapid startup
capability. Since startup periods are typically the least efficient for treatment systems and offshore
platforms have limited available space for storage of the volumes of deck drainage which occur, EPA
determined that an add-on treatment system appropriate for the treatment of deck drainage was not
available.
Since BCT, BAT, and NSPS are being set equal to the current BPT, there are no costs or non-
water quality environmental impacts associated with this limitation and it is available and economically
achievable. The BCT limitation of no discharge of free oil is also considered to be cost reasonable under
the BCT cost test. Since the POTW test result pressure scenario, the peak year required 2,800 gallons
of diesel fuel and.emitted 2.8 tons of air pollutants, decreasing to 1,000 gallons of diesel fuel and 1.0 ton
of air emissions in year 15. For the low pressure scenario, 700 gallons of diesel fuel were required and
1 ton of air pollutants emitted in the first year after promulgation, decreasing to 250 gallons of diesel fuel
and 0.4 tons of air emissions in year 15.
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SECTION XVI
BASIS FOR REGULATION - DOMESTIC WASTE
1.0 BCT, BAT, AND NSPS OPTIONS CONSIDERED
Under BCT and NSPS, EPA is prohibiting the discharge of all floating solids, and incorporating
limits on garbage as currently required at 33 CFR Part 151. Discharges of garbage, including plastics,
are already prohibited at 33 CFR Part 151, which implements Annex V of the Convention to Prevent
Pollution from Ships (MARPOL) and the Act to Prevent Pollution from Ships, 33, U.S.C. 1901 et seq.
Discharges of foam are also prohibited under BAT and NSPS. (The subject of the referenced regulations
is the disposal of garbage generated during the normal operation of ships. One category of ships includes
fixed and floating platforms "engaged in the exploration, exploitation and associated offshore processing
of seabed mineral resources." One category of garbage is plastic.) [The definition of "garbage" is
included in 33 CFR 151.05.]
The limitations established for BCT, BAT, and NSPS are all technologically available and
economically achievable because they are either currently required in Coast Guard regulations or are
required in current NPDES permits. Under the Coast Guard regulations, discharges of garbage, including
plastics, from fixed and floating platforms engaged in the exploration, exploitation and associated offshore
processing of seabed mineral resources are prohibited with one exception. Victual waste (not including
plastics) may be discharged from fixed or floating platforms located beyond 12 nautical miles from
nearest land, if such waste is passed through a comminuter or grinder meeting the requirements of 33
CFR 151.75. Section 151.75 requires that the grinders or comminuters must be capable of processing
garbage so that is passes through a screen with openings no greater than 25 millimeters (approximately
1 inch) in diameter. A permit promulgated by Region VI for the Western Gulf of Mexico OCS
incorporates the Coast Guard regulations (57 FR 54642; November 19, 1992). Discharge of foam in
other man trace amounts is included in this Region VI permit and the 1986 general permit for the Gulf
of Mexico OCS as a mechanism for controlling detergents (51 FR 24922). A similar prohibition on
discharge of visible foam in other than trace amounts was proposed in the proposed reissuance of the
general permit for the Gulf of Mexico in 1991, (56 FR 15359).
XVI-1
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Since these BCT, BAT, and NSPS limitations for domestic waste are already in either existing
NPDES permits or Coast Guard regulations, these limitations will not result in any additional compliance
cost, or additional non-water quality environmental impacts. There are no incremental costs associated
with the BCT limitations; therefore, it is considered to pass the two part BCT cost reasonableness test.
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SECTION XVII
BASIS FOR REGULATION-SANITARY WASTE
1.0 BCT, BAT, AND NSPS OPTIONS CONSIDERED
BCT and NSPS limitations for sanitary wastes in this rule are equal to the current BPT
limitations. Sanitary waste effluents from facilities continuously manned by 10 or more persons must
contain a minimum residual chlorine content of 1 mg/1, with the chlorine level maintained as close to this
concentration as possible. Offshore facilities continuously manned by nine or fewer persons or only
intermittently manned by any number of persons must comply with a prohibition on the discharge of
floating solids.
At proposal, EPA discussed the availability of alternative treatment and control options. No
alternative technologies available for installation at the offshore facilities were identified. EPA did
consider the appropriateness of requiring operators to capture sanitary wastes and transport the wastes
to shore for treatment. Specific data were not available regarding the costs of transporting sanitary wastes
to shore for treatment. EPA projected compliance costs based on the costs of transporting drilling wastes
to shore (excluding the fee charged by onshore drilling waste disposal facilities). These projected
compliance costs, in conjunction with pollutant removal estimates, did not pass the BCT cost-
reasonableness tests and therefore EPA decided not to base limits on onshore disposal. EPA rejected zero
discharge of sanitary wastes under NSPS because such a limitation would in reality result in operators
transporting the wastes to shore for treatment and subsequent discharge by POTWs back into surface
waters. The discharge mechanisms have comparable pollutant removals; however, the zero discharge
limitation would incur additional non-water quality environmental impacts and compliance costs.
Since there are no increased control requirements beyond that already required by BPT effluent
guidelines, there are not incremental compliance costs or non-water quality environmental impacts
associated with BCT and NSPS limitations for sanitary wastes. Since these limitations are equal to BPT,
they are available and economically achievable. In addition, the BCT limitation is also considered to be
cost reasonable under the BCT cost test. Since the POTW test result and the industry cost-effectiveness
test results are both zero (and therefore pass their respective tests), the limitation is cost reasonable.
EPA is not establishing BAT effluent limitations for the sanitary waste stream because no toxic
or nouconventional pollutants of concern have been identified in these wastes.
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SECTION XVIII
NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND
OTHER FACTORS
1.0 INTRODUCTION
The elimination or reduction of one form of pollution has the potential to aggravate other
environmental problems, an effect frequently referred to as cross-media impacts. Under sections 3Q4(b)
and 306 of the Clean Water Act, EPA is required to consider these non-water quality environmental
impacts (including energy requirements) in developing effluent limitations guidelines and new source
performance standards. In compliance with these provisions, EPA has evaluated the effect of these
regulations on air pollution, solid waste generation and management, consumptive water use, and energy
consumption..
This section discusses the non-water quality environmental impacts associated with the final
regulations for each waste stream, and other factors such as safety and administrative burden.
2.0 DRILLING WASTES
The technology basis for the limitations on drilling fluids and drill cuttings is transportation of
these wastes to shore for treatment and/or disposal. Therefore, adequate onshore disposal capacity for
these wastes is critical ,in assessing the options. Safety, impacts of marine traffic on coastal waterways,
and implementation considerations such as administrative burden and enforcement were other factors also
considered.
EPA evaluated the non-water quality environmental impacts on a regional basis because the
different regions each have their own unique considerations (e.g., air emissions are a particular concern
hi southern California, while availability of disposal sites is more limiting for the Gulf of Mexico).
Although not specifically detailed in the discussion below, the non-water quality environmental impacts
associated with any potential drilling and production activities in regions other than the Gulf of Mexico,
California, and Alaska have been considered acceptable.
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2.1 ENERGY REQUIREMENTS AND AIR EMISSIONS
The control technology basis for compliance with the options considered for the drilling fluids
and drill cuttings waste streams is a combination of product substitution and/or transportation of drilling
wastes to shore for treatment and/or disposal. EPA estimated air emissions resulting from the operation
of boats, cranes, trucks, and earth-moving equipment by using emission factors relating the production
of air pollutants to time of equipment operation and amount of fuel consumed. The differential increase
in fuel requirements and air emissions associated withithe control options in the final rule are presented
in Table XVm-1.1 Nitrogen oxides (NOJ emissions from exploratory drilling activities are estimated
at 78 tons/operation. For comparison, the increase in1 air emissions due to offshore activities related to
onshore disposal of drilling wastes is estimated at approximately 1.5 tons of NOX (less than 2%) for each
well subject to the zero discharge limitations.
*-..>
TABLE XVIII-1
AIR EMISSIONS AND ENERGY REQUIREMENTS FOR DISPOSAL DRILLING FLUIDS
AND DRILL CUTTINGS
Options
3 Mile Gulf/CA
8 Mile Gulf/ 3 Mile CA
Zero Discharge Gulf and CA
Volume of Barged Waste
(bbl/yr)
691,000
1,374,000
6,811,000
Air Emissions
(tons/yr)
298
466
1,798
Fuel RequirememtS
(BOE/yr)
34,900
55,700
221,400
2.1.1 Energy Requirements
Energy requirements for each of the treatment options considered for the final rule were
calculated by identifying those activities necessary to support onshore disposal of drilling wastes. Those
activities requiring fuel consumption include:. :
Supply boats to transport the drilling wastes
Crane operation at the drilling sites and marine transfer stations to facilitate off-loading
the wastes
Trucks to transport the wastes from the marine transfer station to the onshore disposal
site
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ซ Earth-moving equipment at the disposal site to facilitate land spreading and landfill
operations.
The following sections present the assumptions and the methodology used to estimate the energy
required by the various transportation and handling activities associated with onshore disposal of offshore-
generated drilling fluids and drill cuttings.1
2.1.1.1 Supply Boats
'The fuel usage due to operation of supply boats to transport drilling waste to shore accounts for
the highest percentage of fuel used in onshore disposal. Supply boat energy requirements were calculated
by estimating the fuel consumption from each of the aspects associated with transporting drilling waste
to shore, including:
Transit fuel consumption
Maneuvering fuel consumption
Idling fuel consumption
Auxiliary electrical generation
Supply boat capacity and usage.
This section details the assumptions made to estimate the fuel usage for each of these activities.
Transit Fuel Consumption: The supply boat horsepower rating, operating efficiency,
transit speed, and average transit distance are as follows:
Power Rating: 2,500 horsepower diesel powered engine.2
Fuel Consumption: 110 gallons of diesel per hour.2 The supply boat operates at
65 percent of the rated horsepower during open water transit Extrapolating from
110 gal per hour at 65 percent power, the full throttle fuel consumption rate is
estimated at 169 gallons per hour.3
Boat Speed: The average boat speed during transit is 10 knots.2
Average Distance: The average round trip distance is 100 miles.4
Maneuvering Fuel Consumption: Supply boats are estimated to maneuver at the platform
for an average of one hour per visit to the drill site. The maneuvering fuel use factor is
15 percent of full throttle fuel consumption.3
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Idling Fuel Consumption: Due to ocean current and wave action, boats must maintain
engines idling while at the drill site unloading empty cuttings boxes and loading drilling
fluids and boxes. The average time idling on station at the drill site is 4 hours per visit.
This is based on the crane operating time of 2.4 hours to transfer empty cuttings boxes
to the rig or platform and loading the full cuttings boxes onto the supply boat. The
average idling time includes an additional 1.6 hours to account for potential delays in the
transfer process.
Auxiliary Electrical Generator: The usage of an auxiliary generator is needed for
electrical power only when propulsion engines are shutdown. Since the supply boats
remain at the drill site only for the length of time necessary to conduct loading/unloading
evolutions and propulsion plant remains idling at the drill site, the auxiliary generator is
only used while inport.
The average inport time for unloading drilling fluids and drill cuttings, tank cleanout, and
demurrage is 24 hours per supply boat trip.2 The boat engines would be shutdown during
this period. EPA assumed that while inport, the boat operator will rely on the auxiliary
generator for electrical power. ,
For the purposes of estimating fuel requirements and air emissions, EPA assumed that
the auxiliary generator is rated at 120 HP, operates at 50 percent load3 and consumes 6
gallons of diesel fuel per hour.2
Supply Boat Capacity and Usape.: An offshore supply boat typically measures 160 to 180
feet long and can store approximately 12 to 18 cuttings boxes (25 barrel) on deck and
2,500 barrels of drilling fluids in tanks below deck. Dedicated supply boats typically
carry 16 cuttings boxes while regularly-scheduled supply boats typically carry 10 cuttings
boxes. For the purposes of estimating fuel requirements and air emissions, EPA used
an average supply boat (dedicated and regularly scheduled) capacity of 12 boxes.
EPA assumed that dedicated supply boats are necessary during the first phase of drilling
the well, approximately the first 4,500 linear feet, to prevent stoppage of drilling due
to lack of storage space. The drilling platform or rig has sufficient available deck area
to store 12 cuttings boxes and 500 barrels of excess drilling fluids without affecting
drilling operations.5 The cuttings generation rate is the highest during the first 4,500 feet
of drilling due to the large diameter borehole diameter and the volume of drill cuttings
are the limiting factor for boat capacity. Between 4,500 feet and final well-depth, the
drill cuttings generation rate subsides as the borehole diameter decreases and the drilling
fluids generation rate is low enough that there is sufficient capacity on the platform/rig
deck to store the drilling waste and that the regularly-scheduled supply boats have
sufficient capacity to transport the accumulated volumes of drilling fluids and drill
cuttings. Regularly-scheduled supply boats service the drilling site once every two days
At the final well-depth an additional dedicated supply boat is required because there is
a large volume of drilling fluids from cleaning out the well casing and mud tanks which
require onshore disposal. At final well-depth the volume of drilling fluids requiring
disposal are the limiting factor since there may be more than 2,500 barrels (the liquid
storage capacity of a supply boat).
EPA estimated that 6 dedicated boat trips would be required for drilling operations ira the
Gulf of Mexico and offshore of Alaska. This consists of 5 boats trips to haul cuttings
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during the first 4,500 linear feet of drilling and one dedicated boat trip to transport the
drilling fluid at final well-depth. For drilling projects offshore of California, EPA
estimated 5 dedicated boat trips; 4 to haul cuttings from the initial drilling phase and 1
dedicated boat trip to haul drilling fluid at final well-depth.1
2.1.1.2 Cranes
Cranes used to load and offload cuttings boxes at the drill site and inport are diesel powered and
contribute to additional fuel requirements and air emissions. The assumptions used to estimate the fuel
usage and air emissions from crane operation are as follows:
Power Rating: 170 horsepower operating at 80 percent of rated load.3
Fuel Consumption: 67 gallons of diesel fuel per hour.2
Lift Capacity: 10 lifts per hour.2 The unloading of 12 empty cuttings boxes and loading
12 full cuttings boxes on the supply boat requires a minimum of 2.4 hours.
2.1,1.3 Trucks
Since many disposal sites are either located at marine transfer stations, or transfer wastes at the
marke transfer stations from supply vessels to barges and then use the waterways to carry the drilling
wastes to the drilling sites, much of the drilling waste may not actually require truck transportation.
However, the fuel requirements and air emissions attributed to truck usage in EPA's own analysis are
considered to approximate the energy requirements and air emissions resulting from the alternative use
of barge traffic. The number of truck trips, in conjunction with the-distance travelled between the marine
transfer station and the disposal site is the basis in estimating the fuel usage. The following assumptions
were used in developing fuel requirements and air emissions resulting from onshore transportation of
drilling wastes:
Truck Capacity: 5,000 gallons (119 barrels) of .drilling fluids and drill cuttings.2
Fuel Consumption: 4 miles per gallon of diesel fuel.2
Distance: The average round trip distance between the marine transfer station (port
facilities) and the final treatment and disposal site (landfill/landfarm) is estimated at 100
miles. For Alaska, an average round trip of 1,600 miles is used.
XVIII-5
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hi
2.1.1.4 Land Disposal Equipment I
The use of land-spreading equipment at the disposal site was based on the drilling waste volumes ,
and the projected capacity of the equipment. The following assumptions were made in developing fuel |
requirements and air emissions resulting from onshore treatment of drill waste:
Wheel Tractor: Wheel tractors are used at the facility for grading. It is estimated mat 9
8 hours of tractor operation is required to grade the drill ing waste volume from one well.
The estimated fuel consumption rate for a wheel tractor is 1.67 gallons of diesel fuel per I
hour.2
Track-Type Dozer/Loader: A track-type dozer is required at the facility for |
wastespreading. EPA estimated that 16 hours of dozer operation are required to spread
the drilling wastes generated from one well. The estimated fuel consumption rate for a
dozer is 22 gallons of diesel fuel per hour.2 |
2.1.2 Air Emissions
Emission factors were determined for both controlled and uncontrolled sources. The term
"uncontrolled refers to the emissions resulting from a source which does not utilize add-on control |
technologies or methodologies to reduce the emissions of specific pollutants. "Controlled" emission
factors are developed for the case in which the source of emissions has implemented some means of
control to reduce emissions of specific pollutants. "Controlled" emission factors are developed for the
case in which the source of emissions has implemented some means Of control to reduce specific |
emissions. In the case of sulfur dioxide (SO^, the use of low-sulfur fuel results in reduced SQ,
emissions. The control method for nitrogen oxides (NOJ was based on retarding the injection timing of I
engines. Injection tuning retard is estimated to reduce NOX emissions by 20 percent; however, the
implementation of this NOX control method was also assumed to increase carbon monoxide and total
hydrocarbon emissions by 10 percent each.
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Much of southern California is in nonattainment of NAAQS air quality standards, and regulatory
bodies hi that area have typically implemented stringent controls on emissions of air pollutants. It is
expected that many of the controls currently required for onshore and nearshore emitters of air pollutants ^
will soon be applied to oil and gas activities further offshore through the implementation of the air
regulations for OCS activities. Therefore, controlled air emission factors are used in estimating the air
emissions from activities hi the California region. Uncontrolled emission factor are used in all other
regions to estimate air emissions associated with onshore treatment and disposal of drilling wastes. m
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A number of sources were reviewed to reexamine the emission factors utilized in previous
estimates, by EPA for the 1991 proposal4 and by Walk, Haydel & Associates in 19892, of non-water
quality environmental impacts. EPA's recent review of emissions factors included environmental impact
statements developed by the Minerals Management Service (MMS) of the Department of Interior, EPA
reports, contractor reports prepared for EPA and MMS, and contacts with MMS and EPA's Office of
Air Quality Planning and Standards (OAQPS).6 Table XVIII-2 presents the uncontrolled and controlled
emissions factors used to develop air emissions .from onshore disposal of drilling waste. (Note that the
factors are not all based on the same units.)
TABLE XVHI-2
UNCONTROLLED AND CONTROLLED EMISSION FACTORS
Source
Nitrogen Oxides (NOx)
- Uncontrolled
- Controlled
Total Hydrocarbons (THC)
- Uncontrolled
- Controlled
Sulfur Dioxide (SO^
- Uncontrolled
- Controlled
Carbon Monoxide (CO)
- Uncontrolled
- Controlled
Total Suspended
Particulates (TSP)
- Uncontrolled
- Controlled
Supply BAT?!
Ob/IOQO Gallons)
Idle
419.6
335.7
22.6
24.9
28.48
7.12
59.8
65.8
33.0
NC,
Transit
391.7
313.4
16.8
18.5
28.48
7.12
78.3
86.1
33.0
NC
(g/bhp-hr)
14.0
11.2
1.12
1.232
0.931
0.23
3.03
3.33
1.0
NC
Trucks
fc/mile)
11.44
NA
2.53
NC
NA
NA
8.67
NA
NA
NA
Wheel
Ob/hr)
1.269
NA
0.188
NA
0.090
NA
3.59
NA
0.136
NC
Track-type
0.827
NA
0.098
NA'
0.076
NA
0.201
NA
0.058
NC
Auxiliary
(g/bhp-Jir)
14.0
NC
1.12
NC
0.931
NC
3.03
NC
1.0
NC
NOTES: NC = No Controls
NA = Not Available
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2.1.3 Interaction With OCS Air Regulations
which will continue to administer the DOI regulations for the Western and Central Gulf of Mexico
planning areas, and EPA, which has responsibility for the regulation of OCS sources for all other OCS
longitude (near the border of Florida and Alabama).
The National Ambient Air Quality Standard (NAAQS) attainment classification of the onshore
area determines the degree of additional control and emission offset requirements for OCS sources within
25 miles of. a state seaward boundary (except in the Central and Western GOM planning areas). If any
part of the onshore area adjacent to an OCS planning area is designates as nonattainment for a pollutant,
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The regulation of air emissions from outer continental shelf (OCS) sources prior to the passage ,
of the Clean Air Amendments of 1990 (CAA) was the sole responsibility of the Minerals Management
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Service (MMS), which administered the Department of the Interior (DOI) air quality rules (30 CFR
270.45, 46). The CAA partitioned the regulation of air emissions from OCS sources between MMS,
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planning areas. The Central and Western Gulf of Mexico planning area are located west of 87.5 degrees
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On September 4, 1992, EPA promulgated new requirements to control air pollution from OCS |
sources (57 FR 40792). The purpose of the requirements is to attain and maintain Federal and State
ambient air quality standards, and to provide for equity between onshore facilities and OCS facilities |
located within 25 miles of state seaward boundaries (outer boundary of territorial seas). It should be
noted that the offshore guidelines under the Clean Water Act will apply to all activities located seaward I
of the inner boundary of the territorial seas, and thus includes the territorial seas, the contiguous zone
and the ocean.
The OCS rule establishes two separate regulatory regimes. For sources within 25 miles of states' I
seaward boundaries, the requirements are the same as those that would be applicable if the source were
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located in the corresponding onshore area (CO A). Sources located beyond 25 miles of states' seaward
boundaries are subject to federal requirements for Prevention of Significant Deterioration (PSD), New
Source Performance Standards (NSPS) and, to the extent that they are rationally related to the attainment
and maintenance of federal and state ambient air quality standards or to PSD, National Emission
Standards for Hazardous Air Pollutants (NEHSHAPS). All OCS sources operating adjacent to any state
other than Texas, Louisiana, Mississippi, or Alabama will be subject to requirements under one of the *
above regimes.
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then the regulatory requirements applicable to the nonattainment classification for that area would apply
to the entire area of the OCS planning area within 25 miles of the State seaward boundary.
Air emission offset costs consist of those costs related to the trading of emission reductions. The
Emission Offset Trading Policy was initiated by EPA in December 1976. The offset policy applies to
new or expanding emission sources in nonattainment areas. In these areas, a new operation producing
emissions must secure offsetting emission reductions from existing sources in order to compensate for
the increases in emissions from the new source. The primary vehicle for accomplishing these offsets is
the Emission Reduction Credit (ERC). '
In theory, and ERC can result from a process change, a retrofit of control technology, or a
shutdown of an operation. The ERC, once established, represents a marketable commodity which can
be transferred either among firms or internal to one firm. Emission offsets are required for new sources
that wish to construct a facility in an offshore area adjacent to an onshore area that is already exceeding
the NAAQS for a particular pollutant.
In reevaluating the non-water quality impacts associated with onshore disposal requirements for
the final offshore guidelines, EPA considered the impact of the OCS air regulations and state
requirements on air emissions resulting from transporting drilling wastes. Areas requiring emissions
offsets under the OCS, air regulations (those adjacent to nonattainment areas) are located seaward of the
outer boundary of the territorial seas (states' seaward boundary) to a distance of 25 miles from mat
boundary. Drilling activity within state waters would not come under the OCS air regulation, and those
activities beyond the 25 mile delineation would not be subject to the limitations of a corresponding
onshore area. Emissions in state waters would, however, be subject to state and local rules and may also
require offsetting. In analyzing the impacts associated with the offshore guidelines, EPA quantified
potentially needed emissions offsets and calculated their associated costs.
For the purpose of analysis for the offshore guidelines, the following criteria have been used to
quantify any potentially needed emission offsets and the associated costs:
The pollutants which would require offsetting because of nonattainment of ozone
standards are NOX and volatile organic compounds (VOC), which are a fraction of the
total hydrocarbon emissions. For the purpose of analyses under the proposed effluent
guidelines, the total hydrocarbon (THC) emissions are used to quantify and cost
emissions offsets for VOC.
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All drilling activity off California, regardless of the distance from shore or whether it
occurs in State or Federal waters, is considered to result in incremental increases NOX
and hydrocarbons which would require emissions offsets. , *
No offsets are quantified for the Eastern Gulf of Mexico. This is based on the low level
of drilling activity projected for the entire Eastern Gulf of Mexico, coupled with the fact
that the actual area which could trigger the need for offsets is only a small fraction of the
planning area. Any errors introduced by this exclusion would be negligible in ^
comparison to the other compliance costs associated with the offshore guidelines, as well
as in relation to the total drilling costs and total air emissions resulting from the drilling |
activities. '
Emissions requiring offsets are to be offset in the ratio of 1.2:1. In other words, a
source would be required to obtain offsets or reduce emissions by 1.2 tons for every one
ton of new emissions.
The cost of emissions offsets used in the final rulemaking for the offshore guidelines is
an annual cost of $15,000 (1992 dollars) for NO, and $5,000 (1992 dollars) for VOC.1
Only those emissions strictly due to discharge limitations of the offshore guidelines are
considered to be an incremental cost attributable to the guidelines. Any emissions offsets
necessary to offset the level of air emissions currently generated by drilling activities are
a cost of doing business borne by the operators and are not considered incremental costs
attributable to the offshore guidelines.
Only those emissions occurring within 25 miles of the drill site area are considered to
require emissions offsets.
2.2 SOUDS WASTE GENERATION AND MANAGEMENT ^
The regulatory options considered for this rule will not cause generation of additional solids as |
a result of the treatment technology. However, spent drilling fluids and drill cuttings contain high levels
of solids; and therefore, under any zero-discharge option, these drilling fluids and drill cuttings would |
be disposed of onshore.
EPA estimates that drilling activity in the offshore subcategory generates approximately 7.7
million barrels per year of drilling wastes (drilling fluids and drill cuttings). Of that volume, about
760,000 barrels per year of drilling waste already are disposed of onshore to comply with current BPT
effluent limitations and NPDES permit requirements. J
Prior to the 1990/1991 proposals, EPA surveyed State and local regulatory agencies and disposal {
facilities in late 1989 and early 1990 to estimate permitted disposal capacities of sites which could treat
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and dispose of drilling waste. The evaluation reviewed the situation in the three major areas where
onshore disposal of offshore drilling waste would be necessary: Gulf of Mexico, California, and Alaska.
2.2.1 Gulf of Mexico Region
A March 1991 study, entitled "Onshore Disposal of Drilling Waste: Capacity and Cost of
Onshore Disposal Facilities," investigated permitted disposal capacity.7 EPA found that in the Gulf of
Mexico, most of the existing permitted disposal sites are located relatively near the coast, because that
is where the demand for such disposal sites exists. Under State law in Texas and Louisiana, onshore oil
drilling facilities are allowed to use on-site drilling pits for storage of drilling fluids and drill cuttings and
upon closure, drilling waste at onshore facilities can be either buried onsite, land spread, or injected into
an underground formation. Because State law allows onsite disposal of drilling fluids and drill cuttings,
most onshore waste is disposed of at the drilling site. Most of the waste currently being disposed of in
commercial oilfield waste disposal facilities originate from coastal drilling operations and offshore
operations (that do not meet the current BPT effluent limitations and NPDES permit requirements).
The 1991 study classified disposal sites in the Gulf of Mexico into three categories. First, Tier
I sites included those permitted to accept nonhazardous oilfield wastes and which were accepting wastes
from offshore. These sites are located in very close proximity to shore, are generally accessible by boat
or barge, and charge competitive rates for disposal. Tier 2 sites included facilities that were permitted
to accept nonhazardous oilfield wastes but were not doing so because of their relative distance from drill
sites;, their lack of marine unloading terminals or water access, and their inability to compete with the
rates charged by Tier 1 facilities. Finally, Tier 3 sites were those permitted to accept hazardous waste
and which could theoretically accept oilfield wastes, should there be no other alternative. The study
projected the combined permitted capacity of Tier 1 and Tier 2 sites at 30.7 million barrels of drilling
wastes per year, with Tier 3 sites providing an additional 10.9 million barrels per year permitted capacity.
In developing options for the final rule, EPA improved upon the capacity estimates used for the
proposal. EPA believes that in addition to the CWA's requirement to consider non-water quality
environmental impacts, sound environmental policy requires that there be adequate onshore disposal
capacity to dispose of drilling fluids and drill cuttings that will need to be barged to shore to comply with
the zero discharge requirements, toxicity limits, and other requirements imposed by this rule.
XVIII-11
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Accordingly, it is appropriate to determine how much of the permitted capacity is actually
available for disposal of drilling fluids and drill cuttings generated offshore. Disposal estimates for the
1990 and 1991 proposals did not take into account the increased volume of coastal-generated drilling
wastes resulting from a Region VI general permit that, if promulgated as proposed, will require zero
discharge of drilling fluids and drill cuttings by facilities in the coastal subcategory in Louisiana and
Texas. EPA anticipates an increase of 1.1 million barrels per year of coastal drilling waste requiring
onshore disposal as a result of these new permit requirements.
EPA also reviewed the analysis prepared for the 1990 and 1991 proposals to evaluate what
facilities should be considered as available sites for disposal of drilling fluids and drill cuttings from
offshore oil and gas platforms for purposes of determining nonwater-quality environmental impacts.
EPA has determined that it should not include hazardous waste facilities in its overall capacity
estimates for this rule. Drilling wastes are exempted from Federal regulation as hazardous waste under
Subtitle C of RCRA. While exempt from Subtitle C, there are existing State requirements for disposal
of these wastes. In the Gulf coast States, commercial disposal facilities are permitted to accept specific
types of nonhazardous oilfield waste. In EPA's judgment, adequate disposal capacity for hazardous waste
disposal is an ongoing problem, and these hazardous waste facilities should be reserved for use to dispose
of waste which cannot be disposed of hi any other type of facility.
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Because EPA wanted to make a realistic estimate of disposal capacity, EPA included hi its
estimates of available disposal capacity only those facilities that are currently accepting the type of drilling
fluids and drill cuttings that would be generated offshore. EPA excluded one site which is permitted but
not yet constructed (BFI). EPA also excluded another site (Goolong Newpark) because its permit is
currently suspended. EPA also excluded a facility in northern Louisiana (Campbell Wells) because
disposal at this facility would require at least a 5-hour truck ride, resulting in additional air emissions,
energy use, and significantly higher disposal costs than the other sites which are located closer to shore.
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Based on this analysis, total permitted capacity in the Gulf of Mexico region is estimated to be
8.5 million barrels (MM/bbls) per year. A review of the receipts from available disposal facilities
indicated that approximately 3 MM/bbls of wastes were accepted for treatment and/or disposal at these
facilities in 1989. Using the permitted capacity estimate of 8.5 MM/bbls per year, approximately 5.5
MM/bbls per year of onshore disposal capacity is available to accept additional drilling wastes (8.5 - 3.0
= 5.5. MM/bbls per year available capacity).8
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EPA has determined that the volume of offshore-generated drilling wastes resulting from the
regulatory option requiring zero discharge at 3 miles, regardless of whether onshore disposal is driven
by this rule or State water quality standards, would occupy 33 percent of the excess available landfill
disposal capacity. Even taking a facility such as Campbell Wells into account, EPA predicts that the
offshore-generated drilling wastes from the 3 mile zero-discharge option would occupy 28 percent of the
excess landfill disposal capacity. While this level of non-water quality environmental impact is acceptable
to EPA, EPA is concerned that any greater area of zero-discharge (even if the Campbell Wells facility
is included as an available site in the analysis) would occupy too great a percentage of excess landfill
disposal capacity.
EPA has used a conservative estimate of excess disposal capacity for several reasons. EPA is
concerned that its estimate of the amount of drilling fluids and drill cuttings requiring onshore disposal
may be an underestimate because the amount of drilling fluids and drill cuttings expected to be required
disposed of onshore by the Region VI coastal drilling permit ranges from 671,000 to 1,620,000 bbl/yr.
If EPA used the upper bound estimate, this would change the percentage of excess available landfill
disposal! capacity needed to accept the increased volume of drilling wastes to a range of 35 to 42 percent
(depending on whether the Campbell Wells facility was included).
In addition, EPA is well aware of many of the commenter's concerns that it is difficult to permit
these facilities, and that a number of factors, such as citizen opposition and potential toxic tort liability
issues, may make it difficult to keep some of these facilities in operation. Accordingly, EPA attempted
to identify permitted facilities in Louisiana and Texas where EPA feels reasonably confident that these
facilities will remain available over a 15-year period. At the same time, the option selected by EPA
allows for sufficient additional available excess capacity should some of these facilities unexpectedly close
in the future.
2.2.2 California Region
California laws and regulations provide for oil and gas wastes to be designated either hazardous
or nonhazardous. Drilling wastes in California are considered nonhazardous provided the operator uses
only approved additives and fluids. Although offshore drilling wastes requiring onshore disposal in
California would be nonhazardous if the operator uses the approved additives and fluids in the drilling
operations, disposal options appear limited. While in theory it may be possible to dispose of any oilfield
waste in local Class HI (nonhazardous waste that will not decompose) landfills, local regulatory agencies
XVHI-13
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have indicated that they are not inclined to allow such disposal unless the waste is first stabilized for use
as landfill cover. If not stabilized and disposed in a Class III landfill, the alternative disposal option for
offshore drilling waste is disposal at a Class I hazardous waste site. In the 1991 study report, permitted
Class HI (stabilized, nonhazardous waste) disposal capacity was estimated at 3.4 million barrels per year
and the Class I (hazardous waste landfill) disposal capacity at 6.5-10.5 million barrels per year.7 It was
projected that the facilities available to perform the stabilization necessary to allow disposal at Class III
landfills were operating at no more than 50 percent of the permitted capacity. As part of the final
rulemaking, EPA reevaluated capacity estimates and to be approximately 19.4 million barrels per year
(including 15.4 MMbbl/yr for Class III landfills) in the California region.9
Under the option requiring zero discharge of all drilling wastes for the California region, EPA
projects that 233,000 bbl/yr of offshore generated drilling fluids and drill cuttings will require onshore
disposal at facilities on the California coast. Comparing that to the projected disposal capacity in the
California region, EPA concluded that the wastes requiring onshore disposal under this option would use
less than 2 percent of the available disposal capacity. Other distances considered for this rule require less
than 1 percent of the disposal capacity.
2.2.3 Alaska Region
The 1991 report identified no commercially operating disposal sites in Alaska accepting offshore
drilling wastes.7 This lack of commercial disposal sites would require operators to transport the drilling
wastes to another location such as Washington, Oregon, or California for disposal; apply to the State of
Alaska for a permit to operate a commercial disposal facility for the offshore wastes; apply to the State
to allow disposal of drilling wastes which have been either thermally treated or chemically stabilized
(solidification) in currently existing landfills; or inject the drilling wastes into underground formations.
Injection of slurried drilling fluids and drill cuttings is currently practiced on a limited trial basis on the
North Slope and has been considered for onshore use in other regions such as the Gulf of Mexico.
However, the technology of injecting slurried drill cuttings is not sufficiently developed to apply to
offshore at this time.
Under all options considered by EPA, drilling wastes generated off Alaska would be excluded
from the zero discharge limitation. Under the limitations imposed by this rulemaking, EPA does
anticipate a relatively small increase in the volume of offshore generated drilling wastes requiring onshore
disposal in the region. EPA considers the disposal options discussed above, in conjunction with privately-
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owned (industry-owned) onshore disposal sites, to provide ample capacity for disposal of these wastes.
Onshore disposal capacity was a factor in excluding drilling wastes in this region from zero discharge;
however, the difficulties involved in transporting large quantities of these wastes to shore, and the limited
amount of storage space on-site at offshore drilling facilities (particularly mobile drilling units), also serve
as a basis for the exclusion. Although the transportation and onshore disposal considerations precluded
the zero discharge requirement for this region, these factors are not considered to prevent the industry
from capturing and transporting the relatively small volumes of drilling wastes that are anticipated to
require onshore disposal in this region. The volumes requiring onshore disposal under this rule would,
for the most part, be of relatively small volumes, anticipated by the operator (and thus could be planned
for accordingly), and typically occur toward the end of a drilling program when the potential for causing
a halt to drilling would likely be minimized (since the waste volumes to be handled would either be small
or onsite storage would be available). Such waste handling practices and operations would not be
inconsistent with current practices under the current NPDES permit limitations.
2.2.4 Atlantic Region
Landfill capacities were not evaluated along the Atlantic coast due to the limited projected drilling
activity in this region: Currently there is no drilling activity in this region and there has not been any
drilling activity since the early 1980's.
2.3 CONSUMPTIVE WATER USE
Since little or no additional water is required above that of usual consumption, no consumptive
water loss is expected as a result of the final rule.
2.4 OTHER FACTORS
2.4.1 Impact of Marine Traffic on Coastal Waterways
In evaluating the impact of the final rule on the potential for increased service vessel traffic,
dredging, and the widening of navigation channels, EPA reviewed MMS data and industry comments
regarding current practice in supply boat usage. The service vessel usage at offshore facilities may be
as high as two supply boats per day and two crew boats per day during the exploration and development
phases!. In general, service vessels make three trips per week to exploration and development operations
and one trip per week to production platforms. A boat may visit only one site or, if it is only going to
production platforms, may visit as many as five platforms in a single trip.
XVIII-15
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The oil and gas industry in the Gulf of Mexico uses the extensive waterway system located within
the Gulf Coastal States to provide access between onshore support operations and offshore platforms and
rigs. Oil industry support vessels moving along coastal navigation channels include crewboats, supply
boats, barge system, derrick vessels, geophysical-survey boats, and floating production platforms.
Navigation channels serve as routes for service vessels traveling back and forth from service and supply
bases. Generally, oil and gas industry use accounts for less than 10 percent of all commercial usage of
the Gulf Coastal navigation channels according to MMS data.
MMS data show that there were 25,000 service vessel trips to support oil and gas related activities
hi Federal waters of the Gulf of Mexico in 1988. These data do not include vessel traffic destined for
coastal or offshore activities in the State territorial seas and therefore under counts actual boat traffic.
In estimating the vessel traffic resulting from this rule, EPA projected that transporting drilling wastes
ashore from a well subject to zero discharge would require, on average, 5 to 6 service vessel trips and
result in a differential increase of approximately 740 service vessel trips per year. Ninety percent (90%),
or 670, of these boat trips would take place in the Gulf of Mexico. Despite the limitations of the MMS
data, it does indicate that the differential increase in 'boat traffic due to this rule would be less than 3
percent of all service vessel traffic.10
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In evaluating impacts of vessel traffic for its Environmental Impact Statement for its five-year
comprehensive program, MMS projected that an additional 100,000 service vessel trips will result from
planned leasing and development activities. Although this boat activity will occur over the life of the new
activities, the majority of the vessel traffic is expected to occur within 10-15 years. Upon analysis of
current and projected vessel traffic and data on navigational channel usage, MMS concluded that some
maintenance dredging or deepening of navigation channels may be required, but no new navigation
channels were anticipated due to the increased traffic.'0
Since service vessels must have unimpeded access to supply bases to continue servicing offshore
activities, maintenance dredging of navigation channels would be required regardless of whether this rule
was promulgated. The channels used by vessel traffic in transporting drilling wastes to onshore disposal
sites would also continue to be maintained since over 700,000 barrels of offshore generated drilling
wastes are already being transported to shore in compliance with NPDES permit limitations. Recalling
that oil and gas related traffic accounts for less than 10 percent of all commercial use of the navigation
channels and that oil/gas related vessel traffic resulting from this rule will increase less than 3 percent,
any increase in vessel traffic due to this rule is expected to total less than 1 percent of all commercial
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traffic in these channels (3% of 10%, or 0.3%). No significant increase in dredging activities is
anticipated as a result of this rule.
2.4.2 Safety
In 1992, EPA evaluated data associated with personnel casualties that occurred on mobile offshore
drilling units (MODUs) and offshore supply vessels (OSV) for the years 1981 through 1990. The
personnel casualty data was compiled from the U.S. Coast Guard's Personnel Casualty file (PCAS). The
study focused on accidents related to the handling and transportation of material, since this would be most
similair to the additional activities required should a zero discharge limitation be imposed.11
EPA reviewed the data to determine the number of accidents related to activities similar to those
that would occur during the handling of drill cuttings. The following types of accidents were selected
from the database as indicators of injuries that may have resulted from the handling of drill cuttings:
Struck by falling object
Struck by flying object
Struck by moving object
Struck by vessel
Struck by object, NOC
Bumped fixed object
Cargo handling-NOC
Line handling
Caught in Lines
Pinched/crushed
Unknown
Not classified.
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The PCAS file is composed of U.S. Coast Guard 2692 forms and contains the following
information: case number, last name, first name, date of birth, status, nature of the accident, nature of
the injury, the body part injured, result, cause, office, location of the person at the time of accident, the
activity of the person at the time of the accident, the body of water, the year the vessel was built, the date
of the casualty, industry time, company time, name of the vessel, operating company, vehicle
identification number, flag, service, use, design, length, gross tonnage, time on duty, and case year.
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Form 2692 is entitled, "Report of Marine Accident, Injury or Death." The 2692 form is included in the
PCAS file based on the occurrence of the following:
A death
An injury to five or more persons in a single incident
An injury causing any person to be incapacitated for more than 72 hours.
The actual injury report forms were not reviewed, therefore the specific number of casualties
resulting from the handling of drilling waste is not known. The casualties evaluated in this report are
the total number of casualties for general types of accidents and may include casualties resulting from
other drilling activities as well as the handling of drilling waste.
In addition to the type of accident, the survey identified the cause of the accidents. The cause
of accidents was further classified into "safety related!" and "not safety related" categories. Safety related
causes were results of accidents that could be avoided through some form of increased safety awareness.
Non-safety related causes were those accidents considered unavoidable. Table XVIII-3 presents the
primary causes and classification of accidents on MODUs and OSVs.
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Evaluation of the database revealed that the majority of the accidents were caused by human
factors related to safety practices and procedures. Accident reports from one oil and gas company
"showed that more than 80 percent of all injury accidents were caused by human behavior or more
specifically, by unsafe practices. "12 The casualty data from MODUs indicated that the cause of more than
75 percent of the reported casualties were due to human factors related to safety practices and procedures.
For OSVs more than 60 percent of the reported casualties were related to safety practices and procedures.
The evaluation the personnel casualty data concluded the following:
Greater than 75 percent of the accidents occurring on MODUs between 1981 to 1990 were
caused by human error or unsafe practices or procedures.
Greater than 60 percent of the accidents occurring on OSVs between 1981 to 1990 were
caused by human error or unsafe practices or procedures.
Over the last three years (1988-1990) the number of casualties on MODUs has decreased
while the drilling activity has remained fairly constant.
From the data examined it is not possible to predict the effect of transportation of drilling
waste to shore on the number of personnel casualties.
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TABLE XVIII-3
PRIMARY CAUSES AND CLASSIFICATION OF ACCIDENTS ON MODUS AND OSVS
Primary Cause
Adverse Weather
Carelessness, Another or Self
Chemical Reaction
Deck Cluttered or Slippery
Equipment or Material Failure
Failure to use Safety Equipment
Improper Loading/Storage
Improper Maintenance or Supervision
Improper Tools/Equipment
Inadequate/Missing Guarding or Railing
Inadequate Training
Misuse of Tools/Equipment
Mooring Line Surge
Physical Factors, Self
Unsafe Movement, Another or Self
Unsafe Practice, Another or Self
Vessel Casualty
Unknown
Not Elsewhere Classified
Classification
unavoidable
avoidable
unavoidable
avoidable
unavoidable
avoidable
avoidable
avoidable
avoidable
avoidable
avoidable
avoidable
unavoidable
avoidable
avoidable
avoidable
unavoidable
unavoidable
unavoidable
The number of casualties occurring on supply vessels does not appear to be directly related
to drilling activity.
Since the number of increased crane handling events is very small in relation to the total
number of handling operations occurring at drilling and production sites, no disceraable
increase in casualties attributable to onshore disposal of drilling wastes is anticipated.
The technology basis for compliance with zero discharge limitations of drilling fluids and cuttings
will be either to bulk load the material onto barges or to load individual containers onto offshore service
vessels (OSV). Typically, OSVs are used for facilities located in the OCS while barges are used in
>rotected, near shore drilling sites. Containers or boxes are used to hold the excess and/or used muds
md cuttings and have an approximate capacity of 25 barrels. Cranes load these containers onto and off
XVIII-19
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of offshore service vessels. The implementation of a zero discharge standard may ultimately increase
crane-related and transport activity because of the need to deliver drilling fluids and cuttings wastes to
shore for land disposal. ฃ
2.4.3 Administrative/Enforcement Considerations
1
EPA received a number of comments recommending the establishment of the zero discharge zone
at 3 miles from shore. At proposal, EPA considered the 3 mile distance in addition to the distances
discussed above. However, EPA declined to choose that distance in its preferred option because industry
profile information on existing platforms within 3 miles from shore was limited and projections for new
well drilling activity within 3 miles needed additional confirmation. In the 1991 proposal, EPA solicited ^
information regarding activity within State waters (3 miles), and stated that it would consider setting the
final rule on distances other than 4 miles, including a 3-mile delineation, if additional information
regarding activity in State waters became available. Subsequent to the proposal, EPA received additional
data on the number and location of existing platforms which increased estimates of existing platforms and
confirmed earlier estimates of projected activity within 3 miles of shore. _
EPA also received comments regarding the potential for confusion and the administrative burden
in selecting a delineation other than the pre-existing 3-mile boundary between State territorial seas and |
Federal waters. In all offshore areas with the exception of Texas and the Gulf coast of Florida, States
assert jurisdiction over the mineral rights off their shores up to a distance of 3 miles. There is I
overlapping jurisdiction under the CWA and the Submerged Lands Act (SLA) (43 U.S.C. 1301, et seq.). _
to these waters are required to comply with any State water quality standards. Under the SLA, Texas
and Florida exercise mineral rights in the Gulf of Mexico up to 3 marine leagues (approximately 10.35 I
statute miles). In waters beyond 3 miles, or 3 marine leagues for Texas and Florida, the MMS of the 9
Department of the Interior leases mineral rights and manages OCS mineral operations under the authority I
of the Outer Continental Shelf Lands Act (OCSLA). MMS conducts periodic inspections of offshore oil
and gas activities In the Federal waters under the OCSLA and, under a Memorandum of Understanding I
(MOU) with EPA, conducts NPDES compliance inspections on behalf of EPA in those areas. ^
Commenters asserted that it would be more appropriate to select the State/Federal water boundary as the
delineation for a zero discharge limitation, rather than the 4-mile limit so that MMS or the Region would
not have to inspect for zero discharge at any facilities within the 1-mile band between 3 and 4 miles while
: I
inspecting for compliance with a different set of discharge limitations beyond 4 miles. EPA also believes
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that the 3-mile option, which is consistent with State waters under the CWA, will help to simplify the
regulatory framework applicable to offshore waters. Another factor considered by EPA is that only about
12 wells per year (less than two percent of the total wells drilled annually) are expected to be drilled in
the 1 -mile band between 3 and 4 miles from shore.
EPA agrees that these administrative and enforcement concerns are valid and has agreed to adopt
the 3-mile option in the interest of simplifying the regulatory framework applicable to offshore oil and
gas activities.
3.0 PRODUCED WATER
In assessing non-water quality environmental impacts for produced water, EPA projected energy
requirements and air emissions associated with the regulatory options considered, and considered the
potenual for degradation of underground sources of drinking water. The following is a description of
the non-water quality environmental impacts and a summary of the results of the evaluation identifying
the estimated levels and impacts for each option.
3.1 ENERGY REQUIREMENTS AND AIR EMISSIONS
Energy requirements and resulting air emissions for the control options considered by EPA are
presented in Table XVIIW. Estimates are presented incremental to current BPT limitations and thus
represent the expected increase above current emissions levels and energy consumption.
TABLE XVIII-4
NON-WATER QUALITY ENVIRONMENTAL IMPACTS PRODUCED WATER
Fuel Requirements
(thousand BOE/year)
Total Emissions
(tons/yr)
Option
OMMMI
Option 2 Flotation All
___
Option 3 Zero 3 Miles Gulf & Alaska
Option 4 Zero Discharge Gulf & Alaska
XVIII-21
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As can be seen from Table XVIII-4, the option requiring zero discharge of all produced water j
greatly increases air emissions and fuel requirements; as compared to the flotation all option. This is due
primarily to the energy required to operate the injection pumps.
3.1.1 Energy Consumption ฃ
Fuel requirements were calculated for gas turbines assuming a heating value of 1,050 Btu/scf of ^
natural gas and an average fuel consumption of 10,000 Btu/hp-hr, or 9.5 (10,000/1,050) standard cubic |
feet (scf) of natural gas per horsepower-hour (hp-hr).13 The usage rate, in hours per year (hrs/yr), for
the design systems is assumed to be 365 days per year or 8,760 hours per year. For example, the fuel |
requirements to operate a 1,700 BPD gas flotation unit is: 12.25 hp x 8,760 hrs/yr x 9.5 scf/hp-hr = ซ
1.02 million standard cubic feet (scf) of natural gas. This section provides a detailed discussion on the
development of fuel requirements for each treatment technology.
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3.1.1.1 Gas Flotation
Energy requirements for gas flotation represent the power required to operate an induced gas |
flotation system designed for compliance with oil and grease limitations in produced water discharged to
surface waters. The following assumptions were made in calculating the energy and fuel requirements ||
for gas flotation:
The gas flotation equipment will be run by electricity. The electric power will be supplied
by existing natural gas driven generators on the platform. Fuel requirements and air |
emissions for gas flotation represent only the additional electricity that must be generated on |
the platform for operation of gas flotation systems.
Only those existing platforms which do not already have a gas flotation system and are
assumed to add-on a gas flotation system were included in estimating fuel requirements under
BAT. For those existing facilities which already have gas flotation units installed, any '
incremental increase in fuel usage incurred from complying with the BAT limitations for the
final rule would be negligible.
For new sources, only those new platforms without gas flotation systems included in the
facility (20 percent of new structures do not include gas flotation in the design) were included ป<
in estimating fuel requirements under NSPS. For new sources expected to install gas
flotation regardless of the rulemaking (80 percent of all new structures include gas flotation
in the design of the facility), any incremental increase in fuel requirements from complying
with the NSPS limits for the final rule would be negligible.
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Energy requirements for commercially available gas flotation systems were obtained from
equipment vendors for four different size systems ranging in treatment capacity from 1,700 to 77,000
barrels per day (BPD).14 Electricity requirements in kilowatts (kW) for each unit were calculated using
0.75 kW/hp as a conversion factor. Table XVIII-5 presents unit energy and fuel requirements for the
four gas flotation units evaluated.
TABLE XVIII-5
FUEL REQUIREMENTS FOR GAS FLOTATION UNITS14
Feed Rate (BPD)
Power Required (hp)
Electricity Required (kW)
Fuel Required (scf/yr)
1,700
12.25
9.2
1.02xl06
10,000
20.5
15.4
1.7xl06
25,000
40.5
30.4
3.37xl06
77,000
100.5
75.4
8.36xl06
3.1.1,2 Granular Filtration
Energy requirements for granular filtration represent the power required to operate the filter as
an add-on to BPT. Produced water treated by granular filtration is discharged directly to surface waiter.
The backwash stream from the granular filtration unit is concentrated and dewatered using a centrifuge.
The concentrated backwash stream that is dewatered is approximately 0.5 percent of the influent produced
water flow.15 The following assumptions were made in calculating the energy and fuel requirements for
granular filtration: -
The granular filtration equipment will be run by electricity. The electric power will be
supplied by existing natural gas driven generator on the platform. Fuel requirements and air
emissions have been calculated for this generator based on the additional electricity that must
be generated for this treatment technology.
There will only be one 26 hp centrifuge per structure with a capacity of 2000 barrels/day.
The centrifuge will only be operated when necessary (i.e. if the flow to the centrifuge is 100
barrels per day then the centrifuge will only be operated every 20 days when sufficient flow
has been accumulated).
If the flow to the centrifuge is less than one barrel per day then a centrifuge will not be used
at that structure.
XVIII-23
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Energy requirements for commercially available granular filtration systems were obtained from
equipment vendors for five different size systems ranging in treatment capacity from 1,000 to 40,000
barrels per day (BPD).16 Electricity requirements in kilowatts (kW) for each unit was calculated using
0.75 kW/hp as a conversion factor. Table XVIII-6 presents unit energy requirements for the five
granular filtration units evaluated.
TABLE XVIII-6
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FUEL REQUIREMENTS FOR GRANULAR FILTRATION UNITS16
Filter Feed Rate (BPD)
Power Required (hp)
Electricity Required (kW)
Fuel Required (scf/yr)
1,000
10
7.5
8.32X105
5,000
20
15
1.66X106
10,000
30
22.5
2.50xl06
20,000
40
30
3.33xl06
40,000
80
60
6.66xl06
Energy requirements to operate the centrifuge are based a backwash flow rate of 0.5 percent of
the produced water flow. Available data on the energy requirements for the centrifuge were obtained
from contacts with an equipment vendor.17 The smallest capacity centrifuge quoted was a 2000 BPD unit
that required a 26 HP motor. Electricity requirements in kilowatts (kW) for each unit was calculated
using 0.75 kW/hp as a conversion factor. Since the flow to the centrifuge for each design system was
well below 2,000 BPD, it was assumed that the backwash tank will have a storage capacity for 2,000
barrels and the centrifuge would only be operated when 2000 barrels have accumulated in the backwash
tank. The total usage in hours per year (hrs/yr) of the centrifuge was then calculated by dividing the
influent backwash flow by the centrifuge design capacity and taking the product of 24 hrs/day and 365
days/yr. For example, if the filter system treats 1,000 BPD of produced water, the flow to the centrifuge
is: 1,000 BPD x 0.005, or 5 BPD. Usage = (5/2,000) x 24 x 365 (hrs/yr), or 22 hrs/yr. Table XVIII-7
presents centrifuge unit energy and fuel requirements and usage for the five granular filtration units.
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TABLE XVIII-7
FUEL REQUIREMENTS AND USAGE FOR CENTRIFUGE15-17
Filter Feed Rate (BPD)
Centrifuge Feed Rate (BPD)
Power Required (hp)
Electricity Required (kW)
Usage (hrs/yr)
Fuel Required (scf/yr)
1,000
5
26
19.5
22
5.43xl03
5,000
25
26
19.5
110
2.72xl04
10,000
50
26
19.5
219
5.41xl04
20,000
100
26
19.5
438
l.OSxlO5
40,000
200
26
19.5
876
2.16xl05
3.1.1.3 Reinjection
Energy requirements for reinjection were estimated based on produced water being pretreated by
granular filtration and then injected into a well with a capacity of 6,000 BPD at an injection pressure of
1800 psig. The following assumptions were made in calculating the energy requirements for reinjection:
There will be one operating natural gas driven injection pump (turbine type) per structure.
The granular filtration and centrifuge equipment will be run by electricity. The electric
power will be supplied by existing natural gas driven generator on the platform. Fuel
requirements and air emissions have been calculated for this generator based on the additional
electricity that must be generated for this treatment technology.
Energy requirements for commercially available injection pumps were obtained from equipment
vendors for three different size pumps ranging in capacity from 2,000 to 20,000 BPD.18 Table XVHI-8
presents unit energy and fuel requirements for the three injection pumps evaluated.
TABLE XVIII-8
FUEL REQUIREMENTS FOR INJECTION PUMPS18
Pump Capacity (BPD)
Energy Required (hp)
Fuel Required (scf/yr)
2,000
75
6.24xl06
6,000
200
1.66xl07
20,000
742
6.17xl07
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For those model platforms with average produced water flow rates less than 2,000 BPD, an
annual usage in hrs/yr was calculated as a function of the ratio of the model flow versus 2,000 BPD.
3.1.2 Air Emissions
The air emissions were calculated for each model platform by taking the product of brake specific
emission factors, the usage in hours (that is, hours per year), and the horsepower requirements. Air
emissions for each treatment technology were calculated on the basis of "brake specific" emission factors
for natural gas-fired turbines.6 Table XVIII-9 presents the emission factors used in calculating air
emissions for all three treatment technologies.
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TABLE XVffl-9
EMISSION FACTORS FOR NATURAL GAS-FIRED TURBINES19
Units
g/hp-hr
CO
0.05
NOX
1.7
SO2
0.002*
HC
0.055
This factor depends on the sulfur content of the fuel used. For natural gas-fired turbines, AP-42
(Table 3.2-1) gives this emission factor based on assumed sulfur content of pipeline gas of 2000
g/106 scf.13
3.1.2.1 Gas Flotation
Air emissions for the four gas flotation design systems were calculated based on horsepower,
usage, and emission factors. For example, CO emissions resulting from operating the 1,700 BPD system
for 8,760 hrs/yr are: 12.25 hp x 8,760 hrs/yr x 0.05 g/hp-hr x ia6 tons/g = 0.005 tons/yr. Table
XVin-10 presents air emissions in tons/yr for the four gas flotation units evaluated.
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TABLE XVIII-10
AIR EMISSIONS FOR GAS FLOTATION UNITS
*d Rate (BPD)
1,700
10,000
25,000
77,000
HP
12.25
20.5
40.5
100.5
Air Emissions (tons/yr)
CO
0.005
0.009
0.018
0.044
NO,
0.18
0.31
0.60
1.50
S02
0.0002
0.0004
0.0007
0.0017
HC
0.005
0.009
0.018
0.044
Total
0.190
0.328
0.637
1.590
3.1.2,2 Granular Filtration
Air emissions for the granular filtration design systems including the centrifuge were calculated
based on horsepower, usage, and emission factors. For example, CO emissions resulting from operating
the 1,000 BPD filter for 8,760 hrs/yr are: 10 hp x 8,760 hrs/yr x 0.05 g/hp-hr x Itf6 tons/g = 0.004
tons/yr. The CO emissions resulting from operating the 26 hp centrifuge for 22 hrs/yr is: 26 hp x 22
hrs/yr x 0.05 g/hp-hr x IQr6 tons/g = 0.00003 tons/yr. Total CO emissions for the granular filtration
system treating 1000 BPD of produced water is: 0.004 + 0.00003, or 0.004 tons/yr. Table XVffl-11
presents air emissions for the five granular filtration systems evaluated, including the centrifuge.
TABLE XVIII-11
AIR EMISSIONS FOR GRANULAR FILTRATION SYSTEMS
Total For Granular Filtration System
j <. ..
Produced Water Flow (BPD)
1,000
5,000
10,000
20,000
40,000
Air Emissions (tons/yr)
CO
0.004
0.009
0.013
0.019
0.036
NO,
0.150
0.303
0.457
0.615
1.230
soz
0.000
0.000
0.001
0.001
0.001
EC
0.004
0.009
0.013
0.019
0.036
Total
0.158
0.321
0.484
0.654
1.303
3.1.2.3 Reinjection
Air emissions for the three reinjection design pumps were calculated based on horsepower, usage,
and emission factors. For example, CO emissions resulting from operating the 2,000 BPD system for
XVHI-27
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8,760 hrs/yr are: 75 hp x 8,760 hrs/yr x 0.05 g/hp-hr x la6 tons/g = 0.033 tons/yr. Table XVIII-12
presents air emissions in tons/yr for the three injection pumps units evaluated.
TABLE XVIII-12
AIR EMISSIONS FOR REINJECTION PUMPS
Feed Rate
(BPD)
2,000
6,000
20,000
-
ty
75
200
742
Air Emissions (tons/yr)
CO
0.033
0.088
0.325
NO,
1.117
2.978
11.050
SOZ
0.001
0.004
0.013
HC
0.033
0.088
0.325
Total
1.184
3.158
11.713
3.2 UNDERGROUND INJECTION OF PRODUCED WATER
In the 1987 Report to Congress (EPA/530-SW-88-003), EPA analyzed the impact of the disposal
of produced \vater in injection wells. The study found that injection wells used for the disposal of
produced water have the potential to degrade fresh groundwater in the vicinity if they are inadequately
designed, constructed, or operated. Highly mobile chloride ions can migrate into freshwater aquifers
through corrosion hoes in injection tubing, casing and cement. The federal Underground Injection
Control (UIC) program (administered by EPA and states pursuant to the Safe Drinking Water Act,
sections 1421-1425) 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. The
authority of the UIC program extends to all offshore injection wells located in state territorial waters, but
does not apply to injection wells located in federal waters.
Many states have primacy of 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 an because current state programs vary
significantly. State requirements for new injection wells prior to enactment of the UIC program have
evolved over time, and construction ranges for 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.
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4.0 WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
The non-water quality environmental impacts associated with disposal of TWC fluids are the fuel
requirements and air emissions from onshore injection of these fluids. Based on two trips to disposal
faciliti.es in Louisiana, EPA concluded that in general, centralized onshore injection facilities use diesel
powered injection pumps.19-20
One facility injects 10,000 bbl/day of fluids using two 235 horsepower (hp) diesel powered
positive displacement piston pumps. Average injection pressure for two wells is 1,000 psig. Total diesel
usage is an average of 200 gal/day.19 The second facility injects 8,000 bbl/day of fluids using one 165
hp diesel powered triplex pumps. Average injection pressure is 260 psig. Total diesel usage is on (he
average 40 gal/day.20
Diesel internal combustion engines cover a wide variety of industrial applications, including fork
lift trucks, mobile refrigeration units, generators, pumps, and portable drilling equipment. Because the
rated power of these engines covers a wide range, from 45 to 600 hp, substantial differences in both
annual usage (hrs/yr) and engine duty cycles exist. Because of these variables and to calculate fuel
requirements for both BAT and NSPS for onshore injection of TWC "fluids, EPA concluded that an
average diesel usage based on the data from the two facilities represents a reasonable assumption. Air
emissions were calculated by taking the product of the specific emission factors (Ib/gal) and the average
diesel usage.13 Table XVIII-13 presents the specific emission factors used in air emission calculations,
TABLE XVIII-13
EMISSION FACTORS FOR DIESEL POWERED INDUSTRIAL EQUIPMENT"
Pollutant
^^ป
Carbon monoxide (CO)
Hydrocarbons (HC)
Nitrogen oxides (NOJ
Sulfur oxides (SOJ
Particulates
Emission Factor Ob/gal)
^^^* '^"^'^^'^^^^i
0.102
0.0375
0.469
0.0312
0.0335
XVIII-29
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4.1 BAT FUEL REQUIREMENTS AND AIR EMISSIONS
The average diesel fuel requirements for onshore injection of workover and treatment fluids
subjected to BAT limitations were calculated based on the total volume of 140,999 bbl/yr of workover
and treatment fluids requiring onshore disposal. Completion fluids are not included in the BAT estimates
because completion fluids are considered wastes frorti new sources only. An average total diesel usage
of 1,762.5 gal/yr was calculated from the two facilities data, as shown in Table XVIII-14.
TABLE XVIII-14
BAT DIESEL FUEL REQUIREMENTS
Total BAT Injection Fluid Volume
Number of Operating Days
Diesel Usage per Day
Total Diesel Usage
Houma Saltwater Co.
140,999 bbl/yr
18 (based on 8,000 bbl/day)
40 gal
705 gal/yr
Campbell Wells Land
Treatment
140,999 bbl/yr
14 (based on 10,000 bbl/day)
200 gal
2,820 gal/yr
Average Diesel Usage: (705 + 2,820)/2 = 1,762.5 gal/yr
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average diesel usage in gal/yr and the emission factors in Ib/gal shown in Table XVIII-14. The values
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of air emission rates calculated by this method are shown in Table XVIII-15.
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TABLE XVIII-15
BAT AIR EMISSION RATES FOR WORKOVER AND TREATMENT FLUIDS
Pollutant
Carbon monoxide (CO)
Hydrocarbons (HC)
Nitrogen oxides (NO*)
Sulfur oxides (SO,.)
Particulates
Total:
Air Emissions (Ib/yr)
179.77
66.09
826,60
54.99
59J04
1,186.49
Air Emissions (tOn$/yr)
0.090
0.033
0.413
0.027
0.030
0.59
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4.2 NSPS FUEL REQUIREMENTS AND AIR EMISSIONS
The average diesel fuel requirements for onshore injection of TWC fluids subjected to NSPS
limitations were calculated based on the total volume of 741,750 bbl over 15 years, or 49,450 bbl/yr of
TWC fluids requiring onshore disposal. An average total diesel usage of 618 gal/yr was calculated from
the two facilities data, as shown in Table XVIII-16.
TABLE XVIII-16
NSPS DIESEL FUEL REQUIREMENTS
- .
Total NSPS Injection Volume
Number of Operating Days
Diesel Usage per Day
Total Diesel Usage
Houma
Saltwater Co.
49,450
6 (based on 8,000 bbl/day)
40 gal
247 gal/yr
Campbell Wells Land
Treatment
49,450
5 (based on 10,000 bbl/day)
200
989 gal/yr
Average Diesel Usage: (247 + 989)/2 = 618 gal/yr
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Incremental air emissions due to NSPS limitations, were calculated by taking the product of the
average diesel usage in gal/yr and the emission factors in Ib/gal shown in Table XVIII-16. The values
of air emission rates calculated by this method are shown in Table XVIH-17.
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NSPS AIR EMISSION RATES FOR TWC FLUIDS
Pollutant
Carbon monoxide (CO)
Hydrocarbons (HC)
Nitrogen oxides (NOJ
Sulfur oxides (SOJ
Particulates
Total:
Air Emissions (Ib/yr)
63.05
23.18
289.90
19.29
20.71
416.13
Air Emissions (tons/yr)
0.032
0.012
0.145
0.010
0.010
0.21
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5.0 REFERENCES
i
1. "Non-Water Quality Environmental Impacts Resulting from the Onshore Disposal of Drilling '
Fluids and Drill Cuttings from Offshore Oil and Gas Drilling Activities," prepared by |
Engineering and Analysis Division, U.S. Environmental Protection Agency, January 13, 1993.
2 Walk, Haydel & Associates, Inc., "Water-Based Drilling Fluids and Cuttings Disposal Study |
Update," January 1989. Submitted as comments to 53 FR 41356 by the American Petroleum ^
Institute, January 18, 1989. V
3. Jacobs Engineering Group, 1989. "Air Quality Impact of Proposed Lease Sale No. 95," prepared
for U.S. Department of the Interior, Minerals Management Service, June 1989, Unpublished _
Report. . 1
4. ERC Environmental and Energy Services Co., "Estimate of Fuel Requirements and Air Emissions
Associated with BAT/NSPS Options," prepared for U.S. Environmental Protection Agency, g
December 18, 1990.
5 SAIC, "Offshore Oil and Gas Industry: Analysis of the Cost and Pollutant Removal Estimates
for the BCT, BAT and NSPS Treatment Options for the Drill Cuttings and Drilling Fluids '
Streams," prepared for Engineering and Analysis Division, U.S. Environmental Protection
Agency, January 13, 1993.
6. E.H. Pechan and Associates, Inc., "Emission Factors for Sources Associated with Offshore Oil
and Gas Development," prepared for U.S. Environmental Protection Agency, August 14, 1992. <
7. "Onshore Disposal of Drilling Wastes: Capacity and Cost of Onshore Disposal Facilities,"
prepared for EPA by ERCE, March 1991.
8. Minerals Management Service, New Orleans Field Office, "An Analysis of Oil-Field Waste
Commercial Facility Capacity for Receipt of QCS-Generated Wastes," June 3, 1992. ซ<
9. SAIC, "California Landfill Capacity", prepared for EPA, November 1992.
10. Minerals Management Service, "Gulf of Mexico Sales 142 and 143: Central and Western |
Planning Areas, Final Environmental Impact Statement, Volume I: Sections I through IV.C," ^
November 1992.
11. SAIC, "Evaluation of Personnel Injury/Casualty Data Associated with Drilling Activity for the
Offshore Oil and Gas Industry," prepared for Engineering and Analysis Division, U.S.
Environmental Protection Agency, October 8,1992. (Offshore Rulemaldng Record Volume 150?) J
12. Collinge, J. Alan, "Auditing Reduces Accidents by Eliminating Unsafe Practices," Oil & Gas
Journal. August 24, 1992. |
13. Environmental Protection Agency, "Compilation of Air Pollution Emission Factors," AP-42,
Supplement, January 15, 1984. : B,
xvni-32
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14. Telecommunication with John Hainsworth, John H. Carter Company, Baton Rouge, LA., and
Joe Dawley, SAIC, regarding, "Horsepower Requirements of Gas Flotation Units." February
25, 1992.
15. Walk, Haydel & Associates, "Estimated Costs of Removal and Disposal of Produced Water
Solids from New Facilities - Summary Report No. 7," prepared for American Petroleum Institute,
submitted with API comments to the 1985 Proposal, March 14, 1986.
16. Brown and Root Inc., "Potential Impact of EPA Guidelines for Produced Water Discharges from
the Offshore and Coastal Oil and Gas Extraction Industry." Prepared for Sheen Technical
Subcommittee of Jhe Offshore Operators Committee. October 1975.
17. Letter from Jess E. Florez, ALFA-LAVAL Separation, to Joe Dawley, SAIC, containing
literature on centrifuge units entitled "Oily Water Treatment in the Oil Field Industry," October
23, 1991.
18. Telecommunication from J. Asta of BRISC to George Rankin of Aqua-Dyne Engineering Inc.,
"W.O. 4903-03 (EPA) High Pressure Reinjection Pumps - Budget Costs," contained in
Memorandum to Dennis Ruddy, Effluent Guidelines Division, U.S. Environmental Protection
Agency, from Tom Fieldsend, Burns and Roe Industrial Services Corp., "Cost Estimates for
High Pressure, Brine Reinjection Pumps, Offshore Oil and Gas Extraction Industry." June 12,
1984.
19. U.S. Environmental Protection Agency. "Trip Report to Campbell Wells Land Treatment,
Bourge, LA, March 12, 1992", May 29, 1992. - .
20. U.S. Environmental Protection Agency. "Trip Report to Houma Saltwater, Co., LA, March 12,
1992", May 29, 1992.
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SECTION XIX
BEST MANAGEMENT PRACTICES
Section 304(e) of the Clean Water Act authorizes the Administrator to prescribe best management
practices (BMPs) to control "plant site runoff, spillage or leaks, sludge or waste disposal, and drainage
from raw material storage." Section 402(a)(l) and NPDES regulation (40 CFR 122) also provide for best
management practices to control or abate the discharge of pollutants when numeric effluent limitations
are infeasible. 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.
The final rule for the offshore subcategory of the oil and gas extraction point source category
does not establish "best management practices" (BMP's). EPA determined that effective BMP's could
more accordingly be developed by the regional offices and be established in the regional NPDES permits.
Although BMP's were not developed for this rule, EPA identified several general areas where BMP's
may be applicable. The following paragraphs describe the some examples of BMP's that could be
established and be effective through the issuance of NPDES permits.
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 potential for contamination of deck drainage is related to the degree segregation 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.
2. Minimization of wastewater treatment system upsets by the controlled usage of deck washdown
detergents.
XIX-1
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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.
6. Careful application of drill pipe dope to minimize contamina-tion of receiving water and drilling
muds. Pipe dope can contribute high amounts of lead and probably other metals to discharged
muds.
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. >
XIX-2
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SECTION XX
GLOSSARY AND ABBREVIATIONS
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Act: The Clean Water Act.
Agency: U.S. Environmental Protection Agency.
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.
Barite: Barium sulfate. An additive use 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.
BCT: The best conventional pollutant control technology.
Bentonite: A clay additive used to increase viscosity of drilling mud.
Blov/out: A wild and uncontrolled flow of subsurface formation fluids at the earth's surface.
Blowout Preventer (BOP1: 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)(l) 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.
XX-1
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Casing: Large steel pipe used to "seal off1 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. ,
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.
Clean Water Act: The Federal Water Pollution Control Act Amendments of 172 (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).
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 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.
Deck Drainage: Any waste resulting from deck washings, spillage, rainwater, and runoff from gutters
and rams including drip pans and work areas within facilities addressed by this document.
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.
Differential Pressure Sticking: Sticking which occurs because part of the drill string (usually the drill
collars) becomes embedded hi 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 inearly 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.
XX-2
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Drill Cuttings: Particles generated by drilling into subsurface geologic formations and carried to the
surface with the drilling fluid.
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Drilling Fluid: The circulating fluid (mud) used in the rotary drilling of wells to clean and condition the
hole and to counterbalance formation pressure. A water-based drilling fluid is the conventional
drilling 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.
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.
Flocculation: The combination or aggregation of suspended solid particles in such a way that they form
small clumps or tufts resembling wool.
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.
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.
GC: Gas chromatography.
Gun Barrel: An oil-water separation vessel.
Heater-Treater: A vessel used to break oil water emulsion with heat.
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).
XX-3
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Inhibitor: An additive which prevents or retards undesirable changes in the product. Particularly,
oxidation 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.
96-hr LC50: 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.
NRPC: Natural Resources Defense Council.
NSPS: New source performance standards under Section 306 of the Act.
OOC: Offshore Operators Committee.
PESA: Petroleum Equipment Suppliers Association.
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 toxic pollutants listed in 40 CFR Part 423, Appendix A.
Production Facility: Any fixed or mobile facility that is used for active recovery of hydrocarbons from
producing formations. The production facility begins operations with the completion phase.
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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 and the accumulated formation sands and
scale particles generated during production. This includes desander discharge from the produced
water waste stream and blowdown of the water phase from the produced water treating system.
RCRA: Resource Conservation and Recovery Act (Pub. L. 94-580) of 1976. Amendments to Solid
Waste Disposal Act.
Reservoir: Each separate, unconnected body of producing formation.
Rotary Drilling: The method of drilling wells that depends on the rotation of a column of drill pipe with
a bit at the bottom. A fluid is circulated to remove the cuttings.
Sanitary Waste: Human body waste discharged from toilets and urinals located with facilities addressed
by this document.
Separator: A vessel used to separate oil and gas by gravity.
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.
Skim Pile:
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.
Surfactant: A substance that affects the properties of the surface of a liquid or solid by concentrating on
the surface layer.
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.
TSS: Total Suspended Solids.
USCG: United States Coast Guard.
XX-5
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USGS -United States Geological Survey.
\
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 bribes, 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.
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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.
XX-6
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APPENDIX 1
BAT AND NSPS PROFILES OF MODEL PRODUCTION PLATFORMS
-------
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TABLE Al-1
BAT "MODEL" PROFILE OF EXISTING PRODUCTION PLATFORMS
3-MILE DELINEATION
t
s;
Structure Type
Oil Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Subtotals;
Oil and Gas Facilities
Gulf of Mexico: Gulf 1 a
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Sub-Totals;
Gas Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totals?:
Totals For Within 3 Miles
Facilities:
Total
Number Of
Structures
This Type
^nm_ซ__
76
10
3
1
0
0
0
0
0
0
0
90
0
3
6
0
1
0
0
0
5
0
5
20
89
6
4
2
0
0
0
101
211
Total
Number Of
Structures
This Size Now
Injecting
^"""TflWIBBBI
Within 3 Miles
0
2
2
0
2
Total Number
Producing
Wells/Struct.
1
1
4
6
10
18
32
50
14
33
60
-
1
1
4
6
10
18
32
50
14
32
60
-
1
1
4
6
10
18
14
-.
-
Avg. Flow
Prod. Water
BWPD/
Structure
BBBBBSUBIBUU
247
293
1,214
1,822
2,723
5,312
9,603
15,030
6,460
14,282
25,545
*
260
304
1,249
1,877
2,833
5,479
9,874
15,427
6,460
14,282
25,545
_
16
14
55
77
148
244
307
ปs
Max. Mow
Prod,
Water
BWPD/
Structure
-"" -ป
421
461
1,871
2,807
4,500i
8,382
15,162
23,969
11,506
27,272
50,718
^
434
468
1,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
68
68
272
408
680
1,224
1,190
Al-1
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TABLE Al-1 (Continued)
BAT "MODEL" PROFILE OF EXISTING PRODUCTION PLATFORMS
3-MILE DELINEATION
Structure Type
Total
Number Of
Structures
This Type
Total
Number Of,
Structures
Tbfe Size Now
Injecting
Total Number
Producing
Wells/Struct.
'
Avg. Mow
Prod- Water
BWPD/
Structure
Max.
Mow
Prod,
Wafer
BWPB/
Structure
Beyond 3 Miles
Oil Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Sub-Totals: , '
Oil and Gas Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Sub-Totals:
Gas Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totals:
Totals For Beyond 3 Miles
Facilities:
Totals for All Facilities:
69
11
41
18
22
5
1
0
0
0
0
167
222
95
114
127
218
196
2
0
0
5
13
995
438
264
172
158
104
39
1
1,176
2,338
2,549
!
1
1
1
3
1
! 5
; 8
; 2
i
'16
j
1
1
2
21
23
1
1
4
6
10
18
32
50
14
33
60
-
1
1
4
6
10
18
32
50
14
32
60
^
1
1
4
6
10
18
14
--
-
-
247
293
1,214
1,822
2,723
5,312
9,603
15,030
6,460
14,282
25,545
^
260
304
1,249
1,877
2,833
5,479
9,874
15,427
6,460
14,282
25,545
-
16
14
55
77
148
244
307
-
-
-
421
461
1,871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
*
434
468
1,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
:
68
68
272
408
680
1,224
1,190
"
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TABLE Al-2
BAT "MODEL" PROFILE OF EXISTING PRODUCTION PLATFORMS
4-MILE DELINEATION
^
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Structure Type
Oil Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Sub-Totals:
Oil and Gas Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Sub-Totals:
Gas Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totals:
Totals For Within 4 Miles
Facilities:
Total
Number Of
Structures
This Type
-
102
11
26
1
0
0
0
0
0
0
0
140
27
16
16
2
4
8
0
0
7
0
7
87
151
30
13
3
0
0
0
197
424
Total
Number Qf
Structures
Thi& Size Now
Injecting
Within 4 Miles
0
2
2
0
2
Total Number
Producing
Wells/Struct.
1
1
4
6
10
18
32
50
14
33
60
M-
-
1
1
4
6
10
18
32
50
14
32
60
-
1
1
4
6
10
18
14
-
-
Avg, Flow
Prod. Water
BWPD/
Structure
247
293
1,214
1,822
2,723
5,312
9,603
15,030
6,460
14,282
25,545
S+
260
304
1,249
1,877
2,833
5,479,
9,874
15,427
6,460
14,282
25,545
_,
16
14
55
77
148
244
307
.
Max. Flow
Prod,,
Wateir
BWPD/
Structure
421
461
1,871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
j*
434
468
1,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
,
68
68
272
408
680
1,224
1,190
_
Al-3
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TABLE Al-2 (Continued)
BAT "MODEL" PROFILE OF EXISTING PRODUCTION PLATFORMS
4-MILE DELINEATION
Structure Type
Oil Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Sub-Totals;
Oil and Gas Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific Coast: Pacific 16
Pacific 40
Pacific 70
Sub-Totals:
Gas Facilities
Gulf of Mexico: Gulf la
Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totals;
Totals For Beyond 4 Miles
Facilities:
Totals All Facilities:
Total
Number Of
Structures
Ibis Type
43
10
18
18
22
5
1
0
0
0
0
117
195
82
104
125
215
188
2
0
1
5
11
928
376
240
163
157
104
39
.1
1,080
2,125
2,549
Total
Number Of
Structures
This Size Now
Injecting
Beyond 4 Miles
1
1
1
3
1
5
8
2
16
1
1
2
21
23
Total Number
Producing
Wells/Struct,
1
1
4
6
10
18
32
50
14
33
60
+4
1
1
4
6
10
18
32
50
14
32
60
-
1
1
4
6
10
18
14
-
-
-
Avg, Flow
Prod. Water
BWPD/
Structure
247
293
1,214
1,822
2,723
5,312
9,603
15,030
6,460
14,282
25,545
-H
260
304
1,249
1,877
2,833
5,479
9,874
15,427
6,460
14,282
25,545
-
16
14
55
77
148
244
307
-
-
-
Max. flow
Prodi,
Water
BWPD/
Structure
421
461
1,871
2,807
4,500
8,382
15,162
23,969
11,506
27,272
50,718
H-
434
468
1,894
2,841
4,582
8,489
15,312
24,161
11,506
27,272
50,718
-
68
68
272
408
680
1,224
1,190
-
-
-
Al-4
-------
TABLE Al-3
"MODEL" PROFILE OF NEW PRODUCTION PLATFORMS
3-MILE DELINEATION
-, > - i
Structure Type
Total
Structures for
the IS Year
Period
Total
Number
Producing
Wells/Struc.
Total
Producing
Wells
Avg. Flow
Prod. Water
BWPD/
Structure
Max. Flow
Prod. Water
BWPD/
Structure
Within 3 Miles
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
Alaska:
Beaufort Sea Gravel
Island 48
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
Sub-Tatals:
Gas Facilities
Gulf of Mexico: Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totals:
Totals For Within 3 Miles
Facilities:
0
0
0
0
0
0
0
0
0
0
2
2
0
15
15
14
0
0
0
0
0
0
44
11
19
28
0
0
0
58
104
1
4
6
10
18
32
50
14
33
60
40
-
1
4
6
10
18
32
50
14
32
60
-
1
4
6
10
18
14
-
-
0
0
0
0
0
0
0
0
0
0
80
80
0
108
90
140
0
0
0
0
0
0
338
23
132
168
0
0
0
323
741
312
1,285
1,926
2,934
5,633
10,126
15,800
7,066
15,671
27,748
48,674
-
1
321
1,315
1,973
3,027
5,778
10,362
16,145
7,066
15,671
27,748
-
14
49
74
134
222
268
-
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
74,503
-
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28,171
51,979
-
68
272
408
680
1,224
1,190
-
Al-5
-------
TABLE Al-3 (Continued)
"MODEL" PROFILE OF NEW PRODUCTION PLATFORMS
3-MILE DELINEATION
Structure Type
Total
Number
or
Structures
This Type
Total
Number
Of ,
Producing
Wells per
Structure
Total
Producing
Wells
Avg. Flow
Prod. Water
BWPD/
Structure
Max. Flow
Prod.
Water
BWPJ07
Structure
Beyond 3 Miles
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
Sub-Totals:
Oil and GasJFacilities
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
Sub-Totals:
Gas Facilities
Gulf of Mexico: Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totals:
Totals for Beyond 3 Miles
Facilities:
Totals All Facilities:
0
0
0
0
0
0
0
0
0
0
0
12
74
19
70
62
27
0
0
0
0
'264
53
127
61
96
52
0
- 389
653
757
1
4
6
10
18
32
50
14
33
60
-'
1
4
6
10
18
32:
50
14
32
60
-
1
4
6
10
18!
14
-'
-
-.
0
0
0
0
0
0
0
0
0
0
0
12
248
114
700
1,116
864
0
0
96
24
3,390
41
452
366
960
936
0
2,755
6,145
6,886
312
1,285
1,926
2,934
5,633
10,126
15,800
7,066
15,671
27,748
-
321
1,315
1,973
3,027
5,778
10,362
16,145
7,066
15,671
27,748
-
14
49
74
134
222
268
-
-
.
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
-
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28,171
51,979
-
68
272
408
680
1,224
1,190
-.
-
- -
Al-6
-------
TABLE Al-4
"MODEL" PROFILE OF NEW PRODUCTION PLATFORMS
4-MILE DELINEATION
_
.ป J JJ ,
Structure Type
Total
Structures for
the 15 Year
Period
Total
Number
Producing
Wells/Struc.
Total
Producing
Wells
Avg, Flow
Prod. Wafer
BWPD/
Structure
Max. Flow
Prod. Water
BWPD/
Structure
Within 4 Mies
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
Alaska:
Beaufort Sea Gravel
Island 48
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
$ub-TotaIs;
Gas Facilities
Gulf of Mexico: Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totals:
Totals For Within 4 Miles
Facilities:
0
0
0
0
0
0
0
0
0
0
2
2
0
27
15
14
0
0
0
0
0
0
56
23
33
28
0
0
0
84
142
1
4
6
10
18
32
50
14
33
60
40
-
1
4
6
10
18
32
50
14
32
60
-
1
4
6
10
18
14
-
0
0
0
0
0
0
0
0
0
0
80
80
0
108
90
140
. 0
0
0
0
0
0
338
23
132
168
0
0
0
323
741
312
1,285
1,926
2,934
5,633
10,126
15,800
7,066
15,671
27,748
48,674
-
321
1,315
1,973
3,027
5,778
10,362
16,145
7,066
15,671
27,748
-
14
49
74
134
222
268
-
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
74,503
-
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28,171
51,979
>*
68
272
408
680
1,224
1,190
-
Al-7
-------
TABLE Al-4 (Continued)
"MODEL" PROFILE OF NEW PRODUCTION PLATFORMS
4-MILE DELINEATION
'
f
Structure Type
-
Total
Number Of
Structures
Tufc Type
Total
Number Of
Producing
Weils per
Structure
Total
Producing
Wells
Avgr Flow
Prod.
Water
BWPP/
Structure
Max. Mow
Prod.
Water
BWfป/
Structure
Beyond 4 Miles
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
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
Sub-Totals:
Gas Facilities
Gulf of Mexico: Gulf Ib
Gulf 4
Gulf 6
Gulf 12
Gulf 24
Pacific Coast: Pacific 16
Sub-Totalst
Totals For Beyond 4 Miles
Facilities:
Totals All Facilities:
0
0
0
0
0
0
0
0
0
0
0
12
62
19
70
62
27
0
0
0
0
252
41
113
61
96
52
0
363
615
757
1
4
6
10
; is
32
50
14
33
60
;
1
4
6
10
18
32
; 50
14
32
, 60
-
1
4
6
10
18
14
-
;
'
0
0
0
0
0
0
0
0
0
0
0
12
248
114
700
1,116
864
0
0
96
24
3,990
41
452
366
960
936
0
2,755
6,145
6,896
312
1,285
1,926
2,934
5,633
10,126
15,800
7,066
15,671
27,748
+4
321
1,315
1,973
3,027
5,778
10,362
16,145
7,066
15,671
27,748
-
14
49
74
134
222
268
-
-
-
473
1,913
2,869
4,653
8,579
15,439
24,325
11,909
28,171
51,979
*
478
1,929
2,893
4,712
8,655
15,547
24,463
11,909
28,171
51,979
.
68
272
408
680
1,224
1,190
-
-
-
Al-8
-------
APPENDIX 2
1
RAW DATA FOR ESTIMATING POLLUTANT LOADINGS
FOR PRODUCED WATER
I
I
.1
I
I
I
1
-------
I*!
I
r
i
i
i
i
-------
.1
I
J
I
1
I
1
I
I
I
I
I
><
M
P
I
&
H
^
T-<
S
H
1
J
0
*B
s
*|
g
~-
O
M
ซ
s
1
1
2-Butanone
8
o
04
S
04
O
O
o
l>
o
o
o
>n
04
VO
3
8
VO
a
s
04
8
O
04
8
CO
o
o
ง
1 2-4-Dimethylphenol
1 Anthracene
8
o
OV
CO
VO
t-
s
04
8
o
s
8
CO
ฃ
co
8
T-H
8
co
00
s
1
o
o
P
8
S
8
00
00
1 Benzene
8
O
1-H
8
o
8
o
8
o
o
o
0
T-H
8
o
T <
8
o
o
o
o
s
o
T-H
8
o
o
a,
3
1
8
o
8
o
8
o
8
o
8
0
V 1
o
o
0
8
o
8
o
o
o
o
8
04
1 Chlorobenzene
8
o
8
o
T 1
8
04
O
O
o
8
o
s
o
8
o
8
O
i-H
S
o
t C
O
o
o
1 Di-N-butylphthlate
S
o
ง
8
55
8
S
o
o
04
8
I
S
00
T-4
o
o
a
s
CO
8
g
f-
vo
CO
s
Ethylbenzene
1 N-Alkanes
o
o
t-
o
o
V>
CO
CO
s
0
T-H
VO
8
10
CO
oo
1 I
oo
T 1
8
o\
a
8
p
o
o
TI-
CS
8
vo
04
CO
CO
g
T 1
| Napthalene
8
9
o
o
o
8
0
8
o
o
o
0
8
0
T t
S
O
T-H
8
o
8
o
T 4
o
o
o
1 P-chloro-M-cresol
8
o
CO
o\
8
ปn
8
04
00
S
o
CO
Ov
0
g
8
S
o
S
CO
s
T 1
8
oo
o
o
1
r-
04
3
1
1 Steranes
8
1
o
o
1
o
o
o
55
s
S
T C
O
O
T (
8
CO
o
o
CO
04
o
o
oo
VO
CO
8
o
t 1
o
55
ง
| Toluene
1
H
1
1
Aluminum
1 Arsenic
1
&
1
8
o\
04
R
CO
CO
s
oo
04
8
00
04
o
s
s
8
VO
O4
8
8
Wl
04
R
a
| Cadmium
o
o
oo
00
R
ฃ
S
8
R
R
S3
o
o
S3
R
00
R
o
00
8
S3
R
1
o
1
8
s
CO
ป 1
04
R
o
04
o
o
VO
Ov
r-H
s
CO
00
8
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2
s
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R
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00
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04
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1 I
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1 Manganese j
R
04
R
* <
3
r-
co
ซ 1
o
ง
o
s
R
1 (
I/I
* 1
3
s?
i-H
3
CO
R
3
01
CO
V-H
1
iz
| Titanium j
s
8
a
3
10
3
2
3
53
R
si
R
CO
04
R
R
04
R
R
co
i
1
ember 20,
V3
VI
.2
43
Ofl
I
1
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1
o
1
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1
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1
a
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I
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o
i
A2-I
-------
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H
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5
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i
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o
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8
o
8
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8
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8
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8
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ffl
8
o
8
d
8
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8
0
T-H
g
o
8
o
T-H
8
O
V 1
s
o
s
o
8
O
T-H
J
8
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d
g
O
8
0
s
o
T I
8
o
8
o
S
0
T-H
8
O
T 1
8
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T-H
Di-N-butylphthlate
r,
vo
Ov
8
8
8
cs
8
00
CO
CO
S
8
g
8
p-^
00
8
S
8
3
o
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jg
N-Alkanes
55
2
8
00
cs
8
s
o
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vo
CO
s
vH
n
55
VO
8
0
T-H
r t
8
I
0
00
CO
8
VO
8
T-H
Toluene
C
Total Xylenes
Aluminum
,
i
1
8
S
S
8
CO
CO
8
cH
o
>n
CJ
S
cs
o
o
0
a
8
s
*
Cadmium
0
ss
8
8
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8
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8
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8
T-H
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8
8
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>n
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8
00
00
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1
U
I
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o
g
2867.00
8
s
8
ง
0
2
8
T t
8
CO
cs
8
14
S
00
00
1
1
1 Manganese
CO
CO
T-H
CO
o
o
T-H
8
00
>n
8
00
CO
T-l
8
VO
CO
r-H
8
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co
T-H
8
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CO
T-H
o
in
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CO
T-H
8
t-H
T-H
1
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M
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CO
P5
28900.00
8
T-H
8
S
S
o\
8
00
T-H
s
00
8
00
00
s
CO
oo'
T-l
1
1
1
J
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r) H
1 '
1
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1
t 1
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1
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c: |
i? ^k
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1
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Of
O ^1
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j|
4 I
o
1
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CO mm
A2-2
i
-------
- - *- -*- -' - A mm mm -*- _*- ".* -
TABLE A2-3 THIRTY PLATFORM STUDY
Pollutant tygfl}
*Jtlmฐa'llll^llllilllllliliBlllilll
2-Butanone
2-4-Dimethylphenol
Anthracene
Benzene
Benzo(a)pyrene
Chlorobenzene
Di-N-butylphthlate
Ethylbenzene
Napthalene
P-chloro-M-cresol
Phenol
Steranes
Toluene
Triterpanes
Aluminum
Barium
Boron
Cadmium
Iron
Lead,
Manganese
Nickel
Zinc
21
BDCCF5
mmmammmmm
250.00
961.00
10.00
10.00
10.00
74.17
192.92
10.00
2253.00
714.58
25.67
83.25
185.67
132.58
2189.67
$T$5
" -- mir
250.00
1214.17
10.00
10.00
10.00
38.33
44.00
10.00
839.50
1022.50
29.00
88.00
203.00
210.00
211.50
23
WD90A
man
250.00
1370.00
10.00
10.00
51.00
99.00
137.00
10.00
1138.00
990.00
25.00
1455.00
167.00
132.00
202.00
24
, W045B
"""i "-"
250.00
141.42
10.00
10.00
11.50
19.17
26.42
10.00
588.50
104.08
27.50
84.42
181.83
131.42
41.58
Location
25
WD70I
fllillr 1,3585
250.00
1777.50
10.00
10.00
10.00
356.00
164.50
10.00
1106.50
2305.00
27.50
75.50
179.50
126.00
16.00
26
GIB DB600
mammmmm
250.00
400.00
10.00
10.00
10.00
110.00
140.00
10.00
108.00
590.00
23.00
96.00
2?
WJ> I05C
Blinnnn.il umiiiii
250.00
450.00
10.00
10.00
10.00
44.50
119.50
10.00
638.00
342.50
33.00
90.00
184.00
147.50
48.50
2*
SP62A
nUBBOmBBBDI
250.00
10.00
10.00
10.00
111.75
51.75
10.00
204.00
1440.00
27.50
248.00
208.00
216.00
342.00
2ฃ
SP 24/27
maamuamm
250.00
1200.00
10.00
10.00
10.00
86.00
127.00
10.00
270.00
920.00
25.00
163.00
30
SP65B
mmmmmumm
250.00
400.00
15.00
10.00
157.00
95.00
" 327.50
10.00
355.00
495.00
24.50
169.50
199.00
68.50
Source. White, c.fc., Long-lerm Averages for Analyte Concentrations in the Proposed Offshore OU and Gas Regulations." September 20, 1989.
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TABLE A2-4 MISCELLANEOUS STUDIES
Pollutant (jig/1)
Benzene
Phenol
Steranes
Toluene
Boron
Cadmium
Copper
Iron
Lead
Nickel
Titanium
Zinc
. Location . . - . , ,
T&ra Facility Stnfly
Shell
1254.80
136.29
10.00
991.58
10.00
47.50
10.00
267.88
71.70
125.70
158.29
1294.64
155.58
76.06
17.00
65853.79
32139.65
4.00
6.00
730.42
50.00
139.90
30.00
3.66
46.14
Thums
275.00
10.00
10.00
52.48
10.00
47.50
10.00
23.80
18.60
10.00
10.00
80.83
12.51
122.98
17.00
42695.01
38230.13
4.00
90.46
8260.75
50.00
230.90
30.00
5.27
72.32
Conoco
275.00
146.70
10.00
9008.41
10.00
47.50
10.00
1009.27
42.32
364.17
379.83
5305.44
439.37
35.00
308.56
49.67
6850.96
4.00
135.50
672.29
50.00
90.68
30.00
12.06
23.23
MUdfetwb
BUC29W5
5325.00
1.20
850.00
170.00
6030.00
2780.00
3500.00
4.00
6.00
10000.00
500.00
2.00
500.00
2.00
Saner
Neff 87
Armstrong
3300.00
300.00
3500.00
2400.00
JWf 88
LakซPdto ;
1210.00
1519.00
10.00
50.00
606.00
13.90
291.00
92.00
675.00
80.00
203.50
11500.00
0.12
0.40
1.50
1.27
125.00
EI105A
2130.00
6374.50
10.00
35.50
2677.00
9.64
1430.00
63.00
2148.00
76.00
481.00
37400.00
0.32
6.36
17.90
0.40
1220.00
Co* Inlet Study
Baker
480.40
19.20
10570.00
18.80
12.90
416.00
433.70
1244.70
4986.00
2059.00
Bruce
394.00
29.20
20417.00
21.70
171.00
787.00
1754.20
2358.30
9355.00
3697.00
Hat A
3.20
21.70
54.00
19.20
0.50
3.00
13.80
2.80
13.00
19.00
Granite
Mi
228.80
16.70
5427.00
17.50
26.30
299.00
1103.00
474.20
2022.00
1573.00
Tradbay
!
529.70
25.00
3308.00
17.50
4.40
155.00
873.00
429.00
1477.00
522.00
^1
118.20
33.30
4968.00
25.80
108.50
208.00
2721.30
438.60
2100.00
960.00
Three Facility Study: SAIC, "Produced Water Pollutant Variability Factors and Filtration Efficacy Assessments From the Three Facility Oil and Gas Study," March 1991.
Neff 87: Neff, Rabalais, and Boesch. 1987. "Offshore Oil and Gas Development Activities Potentially Causing Long-Term Environmental Effects.
Neff 88: Neff, Sauer and Maciolek. "Fate and Effects of Produced Water Discharges in Nearshore Marine Waters," August 22, 1988.
Middleditch: Middleditch, B.S., "Ecological Effects of Produced Water Discharges from Offshore Oil and Gas Production Platforms," March 1984.
Cook Inlet Study: Envirosphere Company, "Summary Report: Cook Inlet Discharge Monitoring Study: Produced Water," September 1988 - August 1989.
Sauer: Sauer, T.C., "Volatile Liquid Hydrocarbon Characterization of Underwater Hydrocarbon Vents and Formation Waters from Offshore Production Operations, August iyปl.
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mm mm mm mm mm m mm mm mm *mm mm* ' mJt"~
TABLE A2-5 RABALAIS STUDY
Pollutant {/ซg/l)
2-Butanone
2-4-Dimethlyphenol
Anthracene
Benzene
Benzo(a)pyrene
Chlorobenzene
Di-n-butylpthalate
Ethylbenzene
N-alkanes
Napthalene
P-chloro-m-cresol
Phenol
Steranes
Toluene
Triterpanes
Total xylenes
Aluminum
Arsenic
Barium
Boron
Cadmium
Copper
Iron
Lead
Manganese
Nickel
Titanium
Zinc
El
10.00
4500.00
10.00
27.50
82.00
605.00
1050.00
210.00
190000.00
39.00
1500.00
6.50
7150.00
3150.00
PF-1
3225.00
37.75
83.00
1765.00
957.50
332.50
6200.00
16.75
1325.00
6.75
6475.00
1762.50
Location
PF-2OCS
119.00
4.60
8.40
720.00
56.50
24.70
15675.00
5.00
1200.00
42.00
4625.00
375.00
PF-2 STAT
462.50
31.40
26.25
455.00
159.50
57.00
34625.00
8.75
1750.00
12.75
7625.00
1087.00
Exxon
2000.00
104.00
45.50
511.00
642.50
167.50
18500.00
10.00
1122.50
2.25
4925.00
430.00
Conoco
3000.00
57.50
69.50
1470.00
1250.00
400.00
54250.00
7.50
1105.00
42.00
4400.00
690.00
EP
730.00
21.50
50.50
120.00
225.00
111.00
24500.00
5.50
830.00
1.50
4450.00
480.00
T4
3600.00
22.00
79.00
1900.00
810.00
180.00
280000.00
9.00
1500.00
5.00
7400.00
4700.00
T-2
1000.00
7.40
47.00
640.00
210.00
51.00
180000.00
33.00
1800.00
4.00
7700.00
2500.00
RP-l
580.00
13.00
23.00
490.00
230.00
100.00
23000.00
5.00
1100.00
1.00
5100.00
420.00
RP-2
760.00
21.00
29.00
570.00
400.00
300.00
5400.00
4.00
1200.00
42.00
5100.00
260.00
EW
910.00
20.00
20.00
190.00
340.00
140.00
7000.00
40.00
1700.00
13.00
8800.00
440.00
I
Source: Rabalais, McKee and Reed: "Fate and Effects of Nearshore Discharges of OCS Produced Waters," June 1991.
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