DEVELOPMENT DOCUMENT

                            for

PROPOSED EFFLUENT LIMITATIONS GUIDELINES & STANDARDS

                           for the

                  COASTAL SUBCATEGORY

                           of the

    OIL AND GAS EXTRACTION POINT SOURCE CATEGORY
                      Carol M. Browner
                        Administrator

                      Thomas O'Farrell
            Director, Engineering and Analysis Division

                        Marvin Rubin
                     Chief, Energy Branch

                     Allison P. Wiedeman
                       Project Officer
                      January 31, 1995
               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
SECTION I
INTRODUCTION
   1.0 LEGAL AUTHORITY	  1-1
       l.l  BACKGROUND	  1-1
            1.1.1  Clean Water Act	  1-1
            1.1.2  Section 304(m) Requirements and Litigation	  1-3
            1.1.3  Pollution Prevention Act 	  1-4
            1.1.4  Prior Regulation and Litigation for the Coastal Subcategory  	  1-4

SECTION H    SUMMARY OF THE PROPOSED REGULATIONS

   1.0 INTRODUCTION
       1.1  BPT LIMITATIONS . .  . :	-	n-l
       1.2  SUMMARY OF THE PROPOSED RULE	  Ii-2
       1.3  PREVENTING THE CIRCUMVENTION OF EFFLUENT LIMITATIONS
            GUIDELINES AND NEW SOURCE PERFORMANCE STANDARDS	n-4
       1.4  THE EPA REGION VI COASTAL OIL AND GAS PRODUCTION NPDES
            GENERAL PERMITS	  n-5

SECTION HI    INDUSTRY DEFINITION AND WASTESTREAMS

   1.0 INTRODUCTION  	   IH-1
   2.0 REGULATORY DEFINITION  	   IH-1
       2.1  NEW SOURCE DEFINITION	   ffl-2
       2.2  GEOGRAPHICAL LOCATIONS OF THE COASTAL INDUSTRY	   m-5
       2.3  MAJOR WASTES STREAMS	   m-6
            2.3.1  Drilling Fluid	   m-6
            2.3.2  Drill Cuttings	   III-6
            2.3.3  Produced Water	   HI-7
       2.4  MISCELLANEOUS WASTES 	   m-7
            2.4.1  Produced Sand  	   ffl-7
            2.4.2  Well Treatment Fluids	   HI-7
            2.4.3  Well Completion Fluids	   m-7
            2.4.4  Workover Fluids	   DI-7
            2.4.5  Deck Drainage  	   IH-8
            2.4.6  Domestic Waste	   m-8
            2.4.7  Sanitary Waste  	   m-8
       2.5  MINOR WASTES 	   m-8
   3.0 CURRENT NPDES PERMIT STATUS	   IH-9
       3.1  NPDES PERMITS	   IH-9
       3.2  STATE REQUIREMENTS  	  m-10
   4.0 REFERENCES  	  IH-13

SECTION IV    INDUSTRY DESCRIPTION

   1.0 INTRODUCTION	  IV-1
   2.0 DRILLING ACTIVITIES	   IV-1

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                   TABLE OF CONTENTS (Continued)
       2.1  EXPLORATORY DRILLING	   rv-1
           2.1.1  Drilling Rigs	   IV-2
           2.1.2  Formation Evaluation	   IV-3
       2.2  DEVELOPMENT DRILLING  	   IV-3
           2.2.1  Well Drilling 	   IV-4
   3.0  PRODUCTION ACTIVITIES  	   IV-8
       3.1  COMPLETION	   IV-8
       3.2  Fluid Extraction	  IV-10
           3.2.1  Enhanced Oil Recovery	  IV-11
       3.3  FLUID SEPARATION .-	  IV-12
       3.4  WELL TREATMENT 	  rv-17
       3.5  WORKOVER	  IV-20
   4.0  PRODUCTION AND DRILLING: CURRENT AND FUTURE	  IV-21
       4.1  INDUSTRY PROFILE 	  !V-21
       4.2  CURRENT PRODUCTION OPERATIONS 	  IV-22
           4.2.1  Gulf of Mexico	  IV-22
           4.2.2  Mississippi, Alabama, Florida	  IV-24
           4.2.3  California 	  IV-25
           4.2.4  Cook Inlet	  !V-25
           4.2.5  North Slope	  IV-28
       4.3  FUTURE COASTAL OIL AND GAS ACTIVITY  	  IV-29
           4.3.1  Drilling  	  !V-29
           4.3.2  New Production Activity	  IV-30
   5.0  REFERENCES 	  !V-31

SECTION V    DATA AND INFORMATION GATHERING

   1.0  INTRODUCTION  	  V'1
   2.0  INFORMATION TRANSFERRED FROM THE OFFSHORE RULE	  V-l
   3.0  INDUSTRY SURVEY	•	  V-3
   4.0  INVESTIGATION OF SOLIDS CONTROL TECHNOLOGIES
       FOR DRILLING FLUIDS	  V-6
   5.0  SAMPLING VISITS TO 10 GULF OF MEXICO COASTAL
       PRODUCTION FACILITIES  	  V-8
   6.0  STATE DISCHARGE MONITORING REPORTS	V-ll
   7.0  COMMERCIAL DISPOSAL OPERATIONS	V-13
       7.1  COMMERCIAL DRILLING WASTE DISPOSAL SITE VISIT	V-13
       7.2  SAMPLING VISITS TO Two COMMERCIAL PRODUCED WATER
            INJECTION FACILITIES	 V-13

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                   TABLE OF CONTENTS (Continued)
   8.0  NORM STUDY	  V-14
   9.0  ALASKA OPERATIONS	  V-14
       9.1  REGION X DISCHARGE MONITORING STUDY	V-14
       9.2  EPA SITE VISITS AND INFORMATION GATHERING EFFORTS	V-17
           9.2.1  Drilling Operations on the North Slope	V-18
           9.2.2  Production Operations on the North Slope  	V-19
           9.2.3  Drilling Operations in Cook Inlet	  V-19
           9.2.4  Production Operations in Cook Inlet	V-19
   10.0 REGION X DRILLING FLUID TOXICITY DATA STUDY	V-19
   11.0 CALIFORNIA OPERATIONS	  V-20
   12..0 OSW SAMPLING PROGRAM  	  V-21
   13.0 ESTIMATION OF INNER BOUNDARY OF THE TERRITORIAL SEAS 	V-21
   14.0 REFERENCES	  V-22

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-2
       2.3  TOXICITY 	   VI-7
       2.4  CADMIUM AND MERCURY	   VI-7
       2.5  POLLUTANTS NOT REGULATED	  VI-10
   3.0  PRODUCED WATER	  VI-10
       3.1  POLLUTANTS REGULATED 	  VI-10
       3.2  POLLUTANTS NOT REGULATED	  VI-11
   4.0  WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS	  VI-13
       4.1  POLLUTANTS NOT REGULATED	  VI-14
   5.0  PRODUCED SAND	  VI-14
   6.0  DECK DRAINAGE  	  VI-14
   7.0  REFERENCES 	  VI-16

SECTION VE   DRILLING WASTES CHARACTERIZATION, CONTROL AND TREATMENT
              TECHNOLOGIES

   1.0  INTRODUCTION  	   VH-1
   2.0  DRILLING WASTE SOURCES	   VH-1
       2.1  DRILLING FLUID SOURCES	   VIM
       2.2  DRILL CUTTINGS SOURCES	   vn-2
                                     m

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                  TABLE OF CONTENTS (Continued)
    2.3  DEWATERING LIQUID SOURCES	  VH-3
3.0 DRILLING WASTE VOLUMES  	  VH-3
    3.1  FACTORS AFFECTING DRILLING WASTE VOLUMES	  vn-4
    3.2  ESTIMATES OF DRILLING WASTE VOLUMES	  vn-5
    3.3  DEWATERING LIQUID VOLUMES   	  VH-8
4.0 DRILLING WASTE CHARACTERISTICS	  VH-8
    4.1  DRILLING FLUID CHARACTERISTIC	  VTL-8
    4.2  DRILL CUTTINGS CHARACTERISTICS	vn-13
    4.3  DEWATERING LIQUID CHARACTERISTICS 	VII-14
    4.4  COOK INLET DRILLING WASTE CHARACTERISTICS  	VH-15
5.0 CONTROL AND TREATMENT TECHNOLOGIES	VH-16
    5.1  BPT TECHNOLOGY  	 VQ-16
    5.2  PRODUCT SUBSTITUTION - ACUTE TOXICITY LIMITATIONS 	VH-16
    5.3  PRODUCT SUBSTITUTION - CLEAN BARTTE	VII-17
    5.4  PRODUCT SuBsnrunoN - MINERAL OIL	VII-17
    5.5  ENHANCED SOLIDS CONTROL: WASTE MINIMIZATION
         /POLLUTION PREVENTION  	 VH-18
         5.5.1 Shale Shakers	 VH-19
         5.5.2 Sand Traps	 VH-21
         5.5.3 Degassers  	 VH-21
         5.5.4 Hydrocyclones  	 VH-21
         5.5.5 Centrifuges	 VH-24
         5.5.6 Chemically Enhanced Centrifugation	 VH-26
         5.5.7 Closed-Loop Solids Control System Design	VH-29
         5.5.8 Solids Control System Efficiency	VH-32
    5.6  RESERVE Prrs	 vn-37
         5.6.1 Conventional Reserve Pits 	 W-38
         5.6.2 Managed Reserve Pits	 VH-38
         5.6.3 Pit Closure and Site Restoration	VII-40
         5.6.4 Reserve Pits on the North Slope	VII-41
    5.7  CONSERVATION AND REUSE/RECYCLING 	VH-41
    5.8  LAND TREATMENT AND DISPOSAL	 vn-41
         5.8.1 Onsite Landfarming  	 VH-41
         5.8.2 Centralized Commercial Land Treatment and Disposal Facilities	VH-42
         5.8.3 Cook Inlet Land Disposal	 VH-44
    5.9  SUBSURFACE INJECTION OF DRILLING  FLUIDS	VH-46
    5.10 GRINDING AND SUBSURFACE INJECTION OF DRILLING WASTE	VII-46
         5.10.1 Cuttings Processing System and Injection	VII-46
         5.10.2 Receiving Formation Evaluation—North Slope Operations	VII-49
                                      IV

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                    TABLE OF CONTENTS (Continued)
       5.11  AVAILABILITY OF INJECTION WELLS	VH-50
   6.0  REFERENCES	  VII-51

SECTION VIII  PRODUCED WATER—CHARACTERIZATION, CONTROL AND
              TREATMENT TECHNOLOGIES

   1.0  INTRODUCTION  .	   Vffl-1
   2.0  PRODUCED WATER SOURCES	   Vffl-1
   3.0  PRODUCED WATER VOLUMES	   VDI-1
       3.1   GULF OF MEXICO  	   vm-2
       3.2   ALASKA  	   Vffl-4
   4.0  PRODUCED WATER COMPOSITION	   Vffl-4
       4.1   COMPOSITION OF PRODUCED WATER FOR THE GULF OF MEXICO	   Vffl-5
       4.2   COMPOSITION OF PRODUCED WATER FOR COOK INLET	   vm-7
   5.0  CONTROL AND TREATMENT TECHNOLOGIES	   Vffl-7
       5.1   BPT TECHNOLOGY   	   Vffl-7
            5.1.1 Equalization	  Vffl-11
            5.1.2 Solids Removal	  Vffl-11
            5.1.3 Gravity Separation	  VIII-11
            5.1.4 Parallel Plate Coalescers	  VDI-12
            5.1.5 Gas Flotation  	  VHI-14
            5.1.6 Chemical Treatment	  Vffl-19
            5.1.7 Subsurface Injection and Filtration	  Vffl-19
       5.2   ADDITIONAL TECHNOLOGIES EVALUATED FOR BAT AND NSPS CONTROL  ..  Vffl-20
            5.2.1 Improved Performance of Gas Flotation Technology	  Vffl-20
            5.2.2 Subsurface Injection	  Vffl-23
            5.2.3 Filtration	  Vffl-40
            5.2.4 Activated Carbon Adsorption 	  Vffl-50
   6.0  REFERENCES 	  Vffl-51

SECTION IX    MISCELLANEOUS  WASTE—CHARACTERIZATION,  CONTROL  AND
              TREATMENT TECHNOLOGIES

   1.0  INTRODUCTION	   IX-1
   2.0  WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS	   LX-1
       2.1   WELL TREATMENT, WORKOVER, AND COMPLETION FLUID VOLUMES	   LX-2
       2.2   WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS
            CHARACTERISTICS	   LX-5
            2.2.1 Well Treatment Fluids	   IX-5

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                                 TABLE OF CONTENTS (Continued)

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                                                                                      /
                        2.2.2 Workover and Completion Fluids	   IX-6
                        2.2.3 Chemical Characterization of Well Treatment, Workover,
                           and Completion Fluids 	   IX-9
                   2.3  WELL TREATMENT, COMPLETION, AND WORKOVER FLUIDS
                        CONTROL AND TREATMENT TECHNOLOGIES	  LX-11
                        2.3.1 BPT Technology	  K-ll
                        2.3.2 Additional Technologies Considered	  IX-13
               3.0 DECK DRAINAGE 	  IX-13
                   3.1  DECK DRAINAGE SOURCES	  IX-13
                   3.2  DECK DRAINAGE VOLUMES	  IX-14
                        3.2.1 Total Volumes  	  IX-14
                        3.2.2 Gulf of Mexico-Production Operations	  IX-14
                        3.2.3 Gulf of Mexico-Drilling Operations  	  IX-15
                        3.2.4 Cook Inlet Alaska 	  LX-22
                   3.3  DECK DRAINAGE CHARACTERISTICS	  IX-23
                   3.4  DECK DRAINAGE CONTROL AND TREATMENT TECHNOLOGIES	  IX-25
                        3.4.1 BPT Technology	  IX~25
                        3.4.2 Additional Deck Drainage Technologies	  IX-31
               4.0 PRODUCED SAND	  IX-33
                   4.1  PRODUCED SAND SOURCES  	  IX-33
                   4.2  PRODUCED SAND VOLUMES	  IX-34
                        4.2.1 Gulf of Mexico	  IX-34
                        4.2.2 Cook Inlet	  LX-35
                   4.3  PRODUCED SAND CHARACTERIZATION 	  IX-36
                   4.4  PRODUCED SAND CONTROL AND TREATMENT TECHNOLOGIES	  IX-36
                        4.4.1 BPT Technology	  IX-40
                        4.4.2 Additional Technologies	  IX-41
               5.0 DOMESTIC WASTES	  IX-42
                   5.1  DOMESTIC WASTE SOURCES	  IX-42
                   5.2  DOMESTIC WASTE VOLUME AND CHARACTERISTICS	  LX-42
                   5.3  DOMESTIC WASTE CONTROL AND TREATMENT TECHNOLOGIES	  IX-42
                        5.3.1 Additional Technologies	  LX-43
                6.0  SANITARY WASTES	  LX-44
                    6.1  SANITARY WASTE SOURCES, VOLUMES AND CHARACTERISTICS	  IX-44
                    6.2  SANITARY WASTE CONTROL AND TREATMENT TECHNOLOGIES  	  IX-46
                7.0  MINOR DISCHARGES	  K-47
                    7.1  BLOWOUT PREVENTER (BOP) FLUID	  IX-47
                    7.2  DESALINATION UNIT DISCHARGE	  IX-47
                    7.3   FERE CONTROL SYSTEM TEST WATER	  IX-47
_

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                    TABLE OF CONTENTS (Continued)
       7.4   NON-CONTACT COOLING WATER	  IX-47
       7.5   BALLAST AND STORAGE DISPLACEMENT WATER	  IX-48
       7.6   BILGE WATER  	  IX-48
       7.7   BOILER SLOWDOWN	  IX-48
       7.8   TEST FLUIDS  	  IX-48
       7.9   DlATOMACEOUS EARTH FILTER MEDIA	  IX-48
       7.10  BULK TRANSFER OPERATIONS	  IX-49
       7.11  PAINTING OPERATIONS	  IX-49
       7.12  UNCONTAMINATED FRESHWATER	  IX-49
       7.13  WATER FLOODING DISCHARGES  	  IX-49
       7.14  LABORATORY WASTES 	  LX-49
       7.15  CARTRIDGE FILTERS	  IX-50
       7.16  NATURAL GAS GLYCOL DEHYDRATION WASTES 	  IX-50
       7.17  MINOR WASTES VOLUMES AND CHARACTERISTICS	  IX-50
   8.0 REFERENCES 	  IX-52

SECTION X     COST AND POLLUTANT LOADING  DETERMINATION OF  DRILLING
              FLUIDS AND DRILL CUTTINGS

   1.0 INTRODUCTION	   X-l
   2.0 OPTIONS CONSIDERED AND TOTAL COSTS	   X-l
   3.0 OVERVIEW OF METHODOLOGY	   X-4
       3.1   CURRENT PRACTICE	   X-6
   4.0 BASIS FOR ANALYSIS AND ASSUMPTIONS	   X-7
       4.1   DRILLING ACTIVITY	   X-8
       4.2   DRILLING WASTE VOLUMES	   X-9
       4.3   DRILLING FLUID CHARACTERISTICS	X-10
       4.4   DRILL CUTTINGS CHARACTERISTICS	X-ll
       4.5   MINERAL OIL CONTENT 	  X-ll
       4.6   BARTTE CHARACTERISTICS	  X-ll
       4.7   TOXICITY TEST FAILURE RATES	X-13
       4.8   GRINDING AND INJECTION	  X-14
       4.9   TRANSPORTATION AND ONSHORE DISPOSAL COSTS OF DRILLING WASTES ....  X-15
   5.0 COMPLIANCE COSTS AND POLLUTANT REMOVALS	X-18
       5.1   LAND DISPOSAL WITHOUT CLOSED-LOOP SYSTEMS  	X-21
       5.2   LAND DISPOSAL WITH CLOSED-LOOP SYSTEMS	X-22
       5.3   SUBSURFACE INJECTION THROUGH DEDICATED WELLS	X-23
       5.4   COMBINED DISPOSAL METHOD	  X-25
       5.5   INCREMENTAL POLLUTANT REMOVALS	X-26
                                      VU

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r
                                  TABLE OF CONTENTS (Continued)
                 6.0  BCT COMPLIANCE COSTS AND POLLUTANT REMOVALS DEVELOPMENT .  X-29
                     6.1  BCT METHODOLOGY	  X-29
                     6.2  BPT BASELINE	  X-30
                     6.3  BCT OPTIONS	  X-34
                         6.3.1 BCT Compliance Costs and Pollutant Removals	X-36
                     6.4  BCT COST TEST CALCULATIONS	  X-38
                 7.0  REFERENCES  	  X-40

              SECTION XI    COMPLIANCE COST AND POLLUTANT LOADING DETERMINATION-
                            PRODUCED WATER

                 1.0  INTRODUCTION	   XI-1
                 2.0  OPTIONS CONSIDERED AND SUMMARY COSTS	   XI-1
                 3.0  COMPLIANCE COST METHODOLOGY FOR EXISTING FACILITIES
                     IN THE GULF OF MEXICO	   XI-4
                     3.1  DESIGN CAPITAL AND O&M COSTS FOR SMALL-VOLUME FACILITIES	   XI-8
                         3.1.1 Design Capital Cost	   XI-9
                         3.1.2 Design O&M Cost	   XI-10
                     3.2  DESIGN CAPITAL AND O&M COSTS FOR MEDIUM/LARGE-VOLUME
                         FACILITIES	   XI-12
                         3.2.1 Injection  	   XI-12
                         3.2.2 Gas Flotation	   XI-18
                     3.3  MODEL COST EQUATIONS	   XI-20
                         3.3.1 Injection  	   XI-20
                         3.3.2 Gas Flotation	   XI-22
                     3.4  DETERMINATION OF CUT-OFF FLOW FOR SMALL- vs.
                         MEDIUM/LARGE-VOLUME FACILITIES	   XI-23
                     3.5  GRANULAR MEDIA vs. CARTRIDGE FILTRATION 	   XI-25
                     3.6  CENTRALIZED TREATMENT SYSTEMS  	   XI-27
                     3.7  GULF OF MEXICO COMPLIANCE COSTS AND POLLUTANT REDUCTIONS  	   XI-28
                         3.7.1 Compliance Costs for Existing Facilities 	   XI-28
                         3.7.2 Compliance Costs for New Source Facilities	   XI-29
                         3.7.3 Total Gulf of Mexico Compliance Costs and Pollutant Reductions ....   XI-29
                 4.0  COMPLIANCE COST METHODOLOGY  FOR COOK INLET	   XI-30
                     4.1  INJECTION	   XI-33
                         4.1.1 Capital Costs  	   XI-33
                         4.1.2 O&M Costs	   XI-38
                     4.2  IMPROVED GAS FLOTATION	   XI-39
                         4.2.1 Capital Cost	   XI-39
                                                    VHl

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                   TABLE OF CONTENTS (Continued)
           4.2.2  O&M Cost	.-	   XI-42
       4.3  TOTAL COOK INLET COMPLIANCE COSTS AND POLLUTANT
           REDUCTIONS 	   XI-42
   5.0  OPTION TOTAL COSTS AND POLLUTANT REMOVALS  	   XI-43
       5.1  BAT AND NSPS INCREMENTAL COMPLIANCE COSTS  	   XI-44
       5.2  BAT AND NSPS POLLUTANT REMOVALS	   XI-44
   6.0  BCT COST TEST	. .	   XI-45
   7.0  REFERENCES  	•	   XI-47

SECTION XH   COMPLIANCE COST  AND POLLUTANT LOADING DETERMINATION-
             WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS

   1.0  INTRODUCTION 	   XH-1
   2.0  OPTIONS CONSIDERED AND SUMMARY COSTS	   XH-1
   3.0  COMPLIANCE COST METHODOLOGY 	   XH-2
       3.1  GENERAL ASSUMPTIONS AND INPUT DATA	   XH-2
           3.1.1  Assumptions and Input Data Derived from the Results of the 1993
                 Coastal Questionnaire	   XH-3
           3.1.2  Assumptions Adopted  from the Produced Water Cost Estimate
                 Methodology	   XH-5
           3.1.3  Additional Assumptions and Data	   XH-5
       3.2  COMPLIANCE COST METHODOLOGY	   XEE-6
   4.0  POLLUTANT REDUCTIONS	   XH-7
       4.1  GENERAL ASSUMPTIONS AND INPUT DATA	   XII-7
       4.2  METHODOLOGY	   xn-7
   5.0  BCT COST TEST	   XH-8
   6.0  REFERENCES  	  XH-11

SECTION KOI  COST AND POLLUTANT LOADING DETERMINATION -
             DECK DRAINAGE

1.0 INTRODUCTION	    XHI-1
   2.0  OPTIONS CONSIDERED AND COSTS  	    XIH-1
   3.0  COMPLIANCE COST CALCULATIONS FOR PRODUCTION OPERATIONS -
       GULF OF MEXICO	    XHI-2
       3.1  NUMBER OF FACILITIES IN EACH COSTING CATEGORY  	    XUJ-5
       3.2  ASSUMPTIONS FOR PRODUCTION FACILITIES	    XEH-5
       3.3  ESTIMATION OF  THE FIRST FLUSH CAPTURE VOLUME	:	    Xffl-7
       3.4  CAPITAL COST ESTIMATE  	    xm-8
                                     IX

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                   TABLE OF CONTENTS (Continued)

                                                                      Page

       3.5  DETERMINATION OF ONSETS INJECTION VERSUS COMMERCIAL DISPOSAL . . .   xni-8
   4.0  COMPLIANCE COST CALCULATIONS FOR DRILLING OPERATIONS -
       GULF OF MEXICO	   Xffl-9
       4.1  ESTIMATING THE VOLUME OF DECK DRAINAGE CAPTURED  	   xm-9
       4.2  ASSUMPTIONS FOR LAND-BASED DRILLING OPERATIONS  	   XEQ-11
       4.3  ASSUMPTIONS FOR WATER-BASED DRILLING OPERATIONS  	   Xffl-11
   5.0  COOKINLET	   Xffl-12
   6.0  POLLUTANT REMOVAL CALCULATION METHODOLOGY	   Xffl-13
   7.0  BCT COST TEST	   XIII-18
   8.0  REFERENCES  	   XHI-20

SECTION XIV  OPTIONS SELECTION: RATIONALE AND TOTAL COSTS

   1.0  INTRODUCTION  	   XIV-1
   2.0  SUMMARY OF OPTIONS SELECTED AND COSTS	   XIV-1
   3.0  OPTION SELECTION RATIONALE  	   XIV-3
       3.1  DRILLING FLUIDS AND CUTTINGS  	   XTV-3
           3.1.1 BAT and NSPS	   XIV-3
           3.1.2 BCT	   XIV-10
           3.1.3 Pretreatment Standards  	   XTV-11
       3.2  PRODUCED WATER  	- • •   XTV-11
           3.2.1 BAT and NSPS	   XIV-11
           3.2.2 BCT	   XIV-13
           3.2.3 Pretreatment Standards  	   XIV-13
       3.3  TREATMENT, WORKOVER, AND COMPLETION FLUIDS	   XIV-14
       3.4  DECK DRAINAGE	   XIV-17
       3.5  PRODUCED SAND	   XIV-18
       3.6  DOMESTIC WASTES  	   XTV-19
       3.7  SANITARY WASTES  	   XTV-20
   4.0  REFERENCES	   XIV-22

SECTION XV  PRETREATMENT STANDARDS

   1.0  INTRODUCTION  	  XV-1
   2.0  INTERFERENCE	  XV-2
   3.0  PASS-THROUGH	  XV-3
   4.0  REMOVAL CREDITS	  XV-4
   5.0  REFERENCES  	  XV-9
                                     x

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                   TABLE OF CONTENTS (Continued)
                                                                       Page

SECTION XVI  NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND OTHER FACTORS

   1.0  INTRODUCTION  	   XVI-1
   2.0  DRILLING WASTES - COOK INLET	   XVI-1
       2.1  ENERGY REQUIREMENTS AND Am EMISSIONS	   XVI-1
           2.1.1  Energy Requirements  	   XVI-3
           2.1.2  Air Emissions	 . . .   XVI-9
       2.2  SOLID WASTE GENERATION AND MANAGEMENT 	  XVI-11
       2.3  CONSUMPTIVE WATER USE 	  XVI-12
       2.4  OTHER FACTORS . .  .•	  XVI-12
           2.4.1  Impact of Marine Traffic on Coastal Waterways in Cook Inlet	  XVI-12
           2.4.2  Safety	  XVI-13
   3.0  PRODUCED WATER	  XVI-16
       3.1  ENERGY REQUIREMENTS AND AIR EMISSIONS	  XVI-16
           3.1.1  Energy Requirements	  XVI-16
           3.1.2  Air Emissions	  XVI-25
       3.2  OTHER FACTORS	  XVI-27
           3.2.1  Impact of Marine Traffic on Coastal Waterways	  XVI-27
       3.3  UNDERGROUND INJECTION OF PRODUCED WATER	  XVI-28
   4.0  WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS	  XVI-29
       4.1  ENERGY REQUIREMENTS	  XVI-29
       4.2  AIR EMISSIONS	  XVI-30
   5.0  REFERENCES  	  XVI-32

SECTION XVH BEST MANAGEMENT PRACTICES	  XVE-1

GLOSSARY	   G-l

APPENDIX VH-1   DRILLING   FLUID  COMPONENTS   AND
                APPLICATIONS	   A-l

APPENDIX X-l    DRILLING  WASTE  COMPLIANCE  COST
                CALCULATIONS, WORKSHEETS 1-5 AND 1T-5T	   A-6

APPENDIX X-2    CALCULATIONS OF UNIT ONSHORE DISPOSAL COST
                FOR OPERATOR B	   A-27

APPENDIX X-3    DRILLING   WASTE  POLLUTANT  REDUCTION
                CALCULATIONS, WORKSHEETS 10 AND 11	   A-32
                                     XI

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                  TABLE OF CONTENTS (Continued)
                                                                 Page

APPENDIX X-4   COOK INLET DRILLING FLUID TOXICITY DATASETS	  A-39

APPENDIX X-5   COOK INLET DRILLING FLUIDS BCT  (VERSION 2)
              COST TESTS	  A-42

APPENDIX XI-1  CALCULATIONS FOR COST OF PRODUCED WATER
              DISPOSAL BY BARGE AND TRUCK	  A-44

APPENDIX XI-2  CALCULATIONS  FOR  COST  OF  CENTRALIZED
              INJECTION SYSTEMS	  A-49

APPENDIX XI-3  CAPITAL AND O&M COSTS  FOR DISCHARGING
              FACILITIES IN THE GULF OF MEXICO  	  A-51

APPENDIX XI-4  DISCHARGING FACILITIES IN NUECES BAY, TEXAS  	  A-67

APPENDIX XI-5  FACILITY-SPECIFIC CAPITAL AND O&M COSTS FOR
              TWO TREATMENT OPTIONS IN COOK INLET	  A-69

APPENDIX XH-1  TWC COMPLIANCE COST CALCULATIONS  	  A-87

APPENDIX XH-2  TWC POLLUTANT REDUCTION CALCULATIONS	  A-96

APPENDIX Xm-1 DECK   DRAINAGE  'COMPLIANCE COST
              CALCULATIONS	   A-105
             \
APPENDIX Xm-2 DECK DRAINAGE VOLUMES FOR LAND-BASED
              PRODUCTION OPERATIONS BASED ON 1993 DAILY
              RAINFALL DATA FOR NEW ORLEANS, LOUISIANA,
              OPTION 2A: CAPTURE OF FIRST FLUSH  	   A-112

APPENDIX Xm-3 DECK DRAINAGE POLLUTANT  LOADING  AND
              REDUCTION CALCULATIONS	   A-116

APPENDIX XVI-1 NWQI SPREADSHEETS FOR COOK INLET DRILLING
              WASTES	   A-122
                                  XII

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                 TABLE OF CONTENTS (Continued)
APPENDIX XVI-2 NWQI SPREADSHEETS FOR EXISTING SOURCES OF
              PRODUCED WATER DISCHARGES IN THE GULF OF
              MEXICO	
A-135
APPENDIX XVI-3 NSPS PRODUCED  WATER  NON-WATER  QUALITY
              IMPACTS IN THE GULF OF MEXICO	
A-145
APPENDIX XVI-4 BASELINE AIR EMISSIONS DATA FOR AN AVERAGE
              PRODUCTION FACILITY IN THE GULF OF MEXICO .
A-148
APPENDIX XVI-5 NWQI SPREADSHEETS FOR TWC FLUIDS IN THE
              GULF OF MEXICO	
A-152
LIST OF FIGURES
  xiv
LIST OF TABLES	  xv
                                 xui

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                                  LIST OF FIGURES
IV-l    Typical Drilling Fluids Circulation System  	  IV-6
IV-2    Typical Completion Methods	  IV-9
IV-3    Produced Water Treatment System  	IV-14
IV-4    Two-Phase Separator	JV'15
IV-5    Three-Phase Separator	rV"16
IV-6    Vertical Heater - Treater	fV-18
IV-7    Gun Barrel	JV'19
V-l     Sample Locations and Treatment System Sequences at the 10 Coastal Production
        Facilities	•	  v'12
Vn-1   Hydrocyclone Flow Patterns  	  VH-23
VE-2   Decanting Centrifuge	  VH-25
VH-3   Rotary Mud Separator (RMS) Centrifuge  	  VH-27
Vn-4   Example Closed-Loop Solids Control System
        (Unweighted Drilling Fluid Application)	  VH-31
Vn-5   GAP Energy Mud Recirculation and Solids Control System	VII-33
Vn-6   ARCO Mud Recirculation and Solids Control System	VH-34
VH-7   UNOCAL Mud Recirculation and Solids Control for 11,700 ft to 13,500 ft	VH-35
VU-8   Layout of a Drilling Location Utilizing a Conventional Reserve Pit  	VII-39
VH-9   Annular Injection During Drilling	•	  VH-47
Vm-1  Typical Skim Pile	Vffl-13
Vm-2  Source: Paragon Engineering Services Dispersed Gas Floatation Unit  	VQI-17
Vm-3  Typical Subsurface Injection Well	VID-29
VIH-4  Cartridge  Filter  	.	VJH-41
Vm-5  Multi-Media Granular Filter   	VIH-45
Vm-6  Flow Dynamics of a Crossflow Filter	Vm-47
IX-1    Deck Drainage Treatment System	IX-27
K-2    Deck Drainage Treatment System	IX-29
IX-3    Closed Hole Perforated Completion (With Gravel Pack)  	IX-39
XI-1    Cut-off Flow Analysis for Injection at Coastal Production Facilities in Louisiana  .... XI-26
XI-2    Cut-off Flow Analysis for Injection at Coastal Production Facilities with
        Land Access  	XI-26
                                            xiv

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LIST OF TABLES

HI-1
IV-1
IV-2

IV-3

IV-4
V-l

V-2

V-3
V-4

V-5

V-6

VI-1
VI-2
VI-3
VI-4
VI-5
VI-6
vn-i
vn-2
vn-s

NPDES PERMIT REQUIREMENTS 	
PROFILE OF COASTAL OIL AND GAS INDUSTRY 	
OIL AND GAS PRODUCTION FACILITY INFORMATION FOR THE
COASTAL TEXAS AND LOUISIANA 	
OIL AND GAS PRODUCTION FACILITIES IN COOK INLET REGION AS OF
AUGUST 1993 	
OIL AND GAS PRODUCTION FACILITIES ON THE NORTH SLOPE 	
TOTAL WELL COUNT SURVEYED FOR COASTAL OIL & GAS WELLS BY
CATEGORY 	
TECHNICAL DATA FOR THE THREE WELL DRILLING OPERATIONS
VISITED 	
PRODUCTION FACILITIES SAMPLED 	
SUMMARY STATISTICS OF RADIUM-226 (pCi/1) FROM COASTAL OIL
AND GAS SITES 	
SUMMARY STATISTICS OF RADIUM-228 (pCi/1) FROM COASTAL OIL
AND GAS SITES 	 	
SUMMARY STATISTICS OF LEAD-210 (pCi/1) FROM COASTAL OIL AND
GAS SITES 	 	
ORGANIC CONSTITUENTS OF DIESEL AND MINERAL OILS 	
POLLUTANT ANALYSIS OF GENERIC DRILLING FLUIDS 	
ORGANIC POLLUTANTS DETECTED IN GENERIC DRILLING FLUIDS ....
ANALYSIS OF TRACE METALS IN BARITE SAMPLES 	
METALS CONCENTRATION IN BARITE 	
POLLUTANT LOADING CHARACTERIZATION - PRODUCED WATER 	
PERCENT WASHOUT FACTORS 	
WASTE DRILL CUTTINGS AND DRILLING MUD VOLUMES 	
COOK INLET DRILLING WASTE VOLUMES 	
Page
m-ii
IV-23

IV-24

IV-27
IV-28

V-5

V-7
V-10

V-15

V-16

V-17
VI-3
VI-5
VI-6
VI-8
VI-9
VI-12
VH-6
vn-7
vn-9

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                    LIST OF TABLES (Continued)
VH-4  COOK INLET DRILLING WASTE CHARACTERISTICS	VH-12

Vn-5  COMPARISON OF ANALYTICAL CHARACTERISTICS OF CENTRIFUGE
      WATER EFFLUENT FROM THE GAP ENERGY AND ARCO DRILLING
      SAMPLING EPISODES TO THE EPA REGION VI GENERAL PERMIT
      POLLUTANT LIMITATIONS FOR DRILLING OPERATIONS 	VH-15

W-6  SOLIDS SEPARATION EQUIPMENT APPLICATIONS IN COOK INLET	VII-30

Vtt-7  CLOSED-LOOP SOLIDS CONTROL SYSTEM EFFICIENCIES	VH-36

Vn-8  SUMMARY OF WASTE DISPOSAL OPTIONS FOR OPERATORS IN COOK
      INLET	:	 Vn-45

Vm-1  CHARACTERISTICS OF THE 10 PRODUCTION FACILITIES SAMPLED BY
      EPA  	 vm-s

VEI-2  PRODUCED WATER VOLUMES FOR OIL AND GAS PRODUCTION
      FACILITIES IN COOK INLET REGION  	 VIH-5

Vm-3  PERCENT OCCURRENCE OF ORGANICS FOR SETTLING TANK
      EFFLUENT SAMPLES FROM THE 1992 EPA 10 PRODUCTION FACILITY
      STUDY	 Vm-6

Vm-4  SUMMARY POLLUTANT CONCENTRATIONS FOR SETTLING EFFLUENT
      FROM THE 1992 EPA 10 PRODUCTION FACILITY STUDY	 VHI-8

Vm-5  PRODUCED WATER POLLUTANT CHARACTERIZATION FOR COOK
      INLET, ALASKA	 Vffl-9

Vm-6  PRODUCED WATER EFFLUENT CONCENTRATIONS GULF OF MEXICO . .  VDI-21

Vm-7  INFLUENT AND EFFLUENT POLLUTANT CONCENTRATION MEANS
      FROM CARTRIDGE FILTRATION	  VHI-43

Vm-8  GRANULAR MEDIA FILTRATION PERFORMANCE	  VIH-46

Vm-9  MEMBRANE FILTRATION PERFORMANCE DATA FROM THE
      MEMBRANE FILTRATION STUDY	  VHI-49

DC-1   DATA USED IN TWC FLUID COMPLIANCE COST ANALYSIS 	   K-2

K-2   TYPICAL VOLUMES FROM WELL TREATMENT, WORKOVER, AND
      COMPLETION OPERATIONS  	   K-3
                                 xvi

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                    LIST OF TABLES (Continued)


                                                                 Page

IX-3   VOLUMES DISCHARGED PER JOB DURING WORKOVER, COMPLETION,
      AND WELL TREATMENT OPERATIONS FROM THE COOK INLET DMR
      STUDY	   IX-4

IX-4   WELL TREATMENT CHEMICALS	   IX-6

IX-5   COMMON BRINE SOLUTIONS USED IN WORKOVER AND COMPLETION
      OPERATIONS  	   IX-8

EX-6   ADDITIVES TO COMPLETION AND WORKOVER FLUIDS .	   IX-9

IX-7   POLLUTANT CONCENTRATIONS IN TREATMENT, WORKOVER, AND
    .  COMPLETION FLUIDS 	  IX-10

IX-8   ANALYTICAL RESULTS FROM THE COOK INLET DISCHARGE
      MONITORING STUDY	  IX-12

IX-9   ANNUAL VOLUME OF DECK DRAINAGE DISPOSED	  IX-14

IX-10  ANNUAL DECK DRAINAGE VOLUMES CURRENTLY DISCHARGED FROM
      WATER-BASED DRILLING OPERATIONS IN THE COASTAL GULF OF
      MEXICO REGION	  IX-16

IX-11  LAND-BASED DRILLING OPERATIONS DECK DRAINAGE PER WELL
      VOLUMES	  IX-16

IX-12  LAND-BASED DRILLING OPERATIONS DECK DRAINAGE TOTAL
      VOLUMES ALL WELLS	  IX-17

IX-13  PROPORTION  OF LAND-BASED VERSUS BARGE-BASED OPERATIONS
      REPORTED IN THE COASTAL SURVEY  	  IX-18

IX-14  ESTIMATED NUMBER OF WELLS DRILLED IN 1992 IN COASTAL GULF
      OF MEXICO AND DURATION OF DRILLING	  IX-19

IX-15  NUMBER OF WELLS BY LOCATION AND WELL TYPE CATEGORIES	  IX-19

IX-16  SUMMARY OF DECK DRAINAGE INFORMATION FROM THE THREE
      COASTAL DRILLING SAMPLING SITE VISITS IN LOUISIANA	  IX-21

IX-17  ANNUAL DECK DRAINAGE VOLUMES DISPOSED IN COOK INLET,
      ALASKA	  IX-23

IX-18  CHARACTERISTICS OF DECK DRAINAGE FROM OFFSHORE GULF OF
      MEXICO PLATFORMS	  IX-24

IX-19  POLLUTANT CONCENTRATIONS IN UNTREATED DECK DRAINAGE	  IX-26
                                 xvn

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                    LIST OF TABLES (Continued)
DC-20

DC-21
PRODUCED SAND VOLUMES GENERATED
RANGE OF POLLUTANT CONCENTRATIONS IN PRODUCED SAND FROM
THE 1992 COASTAL PRODUCTION SAMPLING PROGRAM  	
IX-22  TYPICAL UNTREATMENT COMBINED SANITARY AND DOMESTIC
 Page

IX-34


IX-37


IX-43
EX-23

IX-24
IX-25
X-l
X-2

X-3
X-4
X-5

X-6
X-7
X-8
X-9

X-10

X-ll
X-12
X-13

TYPICAL OFFSHORE SANITARY AND DOMESTIC WASTE
CHARACTERISTICS 	
GARBAGE DISCHARGE RESTRICTIONS 	
MINOR WASTE DISCHARGE VOLUMES 	
COST OF DRILLING FLUIDS AND CUTTINGS CONTROL OPTIONS 	
SUMMARY SCHEDULE OF DRILLING ACTIVITIES BY OPERATORS IN
COOK INLET, ALASKA FOR 7 YEARS AFTER PROMULGATION 	
ORGANIC CONSTITUENTS IN MINERAL OIL 	
METALS CONCENTRATIONS IN BARITE 	
SUMMARY RESULTS OF DRILLING WASTE COMPLIANCE COSTS AND
POLLUTANT REMOVALS FOR COOK INLET 	
INDUSTRY-WIDE COMPLIANCE COST ESTIMATES (1992 $) 	
DRILLING WASTE POLLUTANT LOADINGS IN COOK INLET 	
DRILLING WASTES POLLUTANT LOADINGS IN COOK INLET 	
VOLUME OF DRILLING FLUIDS AND CUTTINGS GENERATED FROM
THE COASTAL MODEL WELL 	
VOLUME OF DRILLING FLUIDS AND CUTTINGS GENERATED FROM
THE SOLIDS CONTROL SYSTEM OF THE COASTAL MODEL WELL 	
BPT DRILLING ASSUMPTIONS 	
BCT DRILLING ASSUMPTIONS 	
BCT COST TEST RESULTS FOR DRILLING FLUIDS AND CUTTINGS -
COOK INLET 	

IX-43
IX-45
IX-51
X-5

X-9
X-12
X-13

X-19
X-22
X-27
X-28

X-32

X-33
X-35
X-37

. X-39
                                xvm

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                     LIST OF TABLES (Continued)


                                                                  Page

XI-1   SUMMARY OF INCREMENTAL BAT AND NSPS COMPLIANCE COST
      ESTIMATES (1992 $)	   XI-2

XI-2   COMPARISON OF COSTS FOR ZERO DISCHARGE OF PRODUCED WATER
      IN THE COASTAL GULF OF MEXICO	   XI-7

XI-3   DESIGN CAPITAL AND O&M COSTS FOR SMALL-VOLUME FACILITIES . .  XI-11

XI-4   DESIGN COST DATA FOR INJECTION AT PRODUCTION FACILITIES
      WITH WATER ACCESS	  XI-16

XI-5   DESIGN COST DATA FOR INJECTION AT PRODUCTION FACILITIES
      WITH LAND ACCESS	  XI-17

XI-6   DESIGN COST DATA FOR GAS FLOTATION AT PRODUCTION FACILITIES
      WITH WATER ACCESS	  XI-19

XI-7   DESIGN COST DATA FOR GAS FLOTATION AT PRODUCTION FACILITIES
      WITH WATER ACCESS	  XI-19

XI-8   CAPITAL AND O&M COSTS EQUATION FOR INJECTION OF PRODUCED
      WATER AT MEDIUM/LARGE-VOLUME FACILITIES	  XI-21

XI-9   CAPITAL AND O&M COSTS EQUATION FOR GAS FLOTATION	  XI-24

XI-10  POLLUTANT LOADING CHARACTERIZATION - PRODUCED WATER,
      GULF OF MEXICO	  XI-30

XI-11  INJECTION COSTS AND POLLUTANT REMOVALS - GULF OF MEXICO ...  XI-31

XI-12  GAS FLOTATION COSTS AND POLLUTANT REMOVALS - GULF OF
      MEXICO	  XI-32

XI-13  PRODUCED WATER TREATMENT EQUIPMENT AVAILABLE AT EACH
      DISCHARGING FACILITY IN COOK INLET	  XI-34

XI-14  CAPITAL AND O&M COSTS (1992 Dollars) FOR INJECTION OF PRODUCED
      WATER IN COOK INLET	  XI-35

XI-15  ESTIMATED O&M COSTS (1992 Dollars) FOR INJECTION OF PRODUCED
      WATER IN COOK INLET	  XI-40

XI-16  CAPITAL AND O&M COSTS (1992 Dollars) FOR GAS FLOTATION IN COOK
      INLET	  XI-41

XI-17  POLLUTANT LOADING CHARACTERIZATION - PRODUCED WATER
      COOK INLET	  XI-43
                                  XIX

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                    LIST OF TABLES (Continued)
XI-18  COMPLIANCE COSTS AND POLLUTANT REDUCTIONS IN COOK INLET . .  XI-43

XI-19  ANNUAL REGIONALIZED POLLUTANT REMOVALS FOR EXISTING AND
      NEW SOURCE FACILITIES 	  XI-45

XI-20  PRODUCED WATER BCT COST TEST ANALYSIS	  XI-46

XH-1  TOTAL ANNUAL COMPLIANCE COST ESTIMATES FOR TREATMENT,
      WORKOVER, AND COMPLETION FLUIDS (1992$)  	  XH-2

Xn-2  NUMBER OF WELLS LOCATED IN FRESH VS SALINE WATERS IN THE
      COASTAL GULF OF MEXICO REGION 	  XII-4

XII-3  TOTAL ANNUAL POLLUTANT LOADINGS AND REDUCTIONS FOR
      TREATMENT, WORKOVER, AND COMPLETION FLUIDS  	  XII-9

XH-4  BCT COST TEST FOR TREATMENT, WORKOVER, AND COMPLETIONS
      FLUIDS	  xn-io

Xm-1  SUMMARY OF COMPLIANCE COSTS FOR DECK DRAINAGE OPTIONS
      FOR PRODUCTION AND DRILLING OPERATIONS IN THE GULF OF
      MEXICO AND COOK INLET, ALASKA 	  XEI-3

Xm-2  ANNUAL COST FOR GULF OF MEXICO PRODUCTION OPERATIONS
      DECK DRAINAGE OPTION 2B: DISCHARGE OF FIRST FLUSH BY
      MPROVED GAS FLOTATION  	  XIH-4

Xm-3  ANNUAL COST FOR GULF OF MEXICO PRODUCTION OPERATIONS
      DECK DRAINAGE OPTION 2B: DISCHARGE OF FIRST FLUSH BY
      IMPROVED GAS FLOTATION  	  XIH-4

XIH-4  ESTIMATED NUMBER OF COASTAL GULF OF MEXICO PRODUCTION
      FACILITIES BY DISPOSAL CATEGORY	  Xffl-6

Xm-5  SUMMARY OF DECK DRAINAGE VOLUMES AND COSTS FOR DRILLING
      OPERATIONS OPTION 2A: ZERO DISCHARGE OF 500 BBL FIRST FLUSH .  XIH-10

Xm-6  COOK INLET DECK DRAINAGE CAPITAL AND O&M COSTS OPTION 2A,
      ZERO DISCHARGE	  XEI-14

XIH-7  COOK INLET DECK DRAINAGE CAPITAL AND O&M COSTS OPTION 2B,
      IMPROVED GAS FLOTATION  	  XHI-15

Xm-8  DECK DRAINAGE TOTAL ANNUAL POLLUTANT LOADINGS	  XHI-16

Xm-9  DECK DRAINAGE TOTAL ANNUAL POLLUTANT REDUCTIONS	  Xffl-17

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                     LIST OF TABLES (Continued)


                                                                  Page

Xm-10 BCT COST TEST DATA FOR DECK DRAINAGE POTW TEST  	  XHI-19

XTV-1  COSTS OF PREFERRED BAT OPTIONS (1992$)	  XIV-4

XIV-2  PROPOSED BPT EFFLUENT LIMITATIONS  	  XTV-4

XIV-3  BAT EFFLUENT LIMITATIONS 	  XTV-5

XIV-4  PROPOSED BCT EFFLUENT LIMITATIONS	  XTV-6

XTV-5  NSPS EFFLUENT LIMITATIONS	  XTV-7
              •
XIV-6  PROPOSED PSES EFFLUENT LIMITATIONS	  XIV-8

XTV-7  PROPOSED PSNS EFFLUENT LIMITATIONS	  XIV-8

XVI-1  AIR EMISSIONS AND ENERGY REQUIREMENTS FOR THE PROPOSED
      OPTIONS BY WASTESTREAMS	 XVI-2

XVI-2  ADR. EMISSIONS AND ENERGY REQUIREMENTS FOR DISPOSAL OF
      DRILLING FLUIDS AND DRILL CUTTINGS IN COOK INLET	 XVI-3

XVI-3  FUEL REQUIREMENTS FOR LAND DISPOSAL OF DRILLING WASTES IN
      COOK INLET  	 XVI-5

XVI-4  FUEL REQUIREMENTS FOR GRINDING AND INJECTION	 XVI-9

XVI-5  UNCONTROLLED EMISSION FACTORS	  XVI-10

XVI-6  AIR EMISSIONS ASSOCIATED WITH PROPOSED OPTIONS FOR EXISTING
      SOURCES FOR DRILLING WASTES IN COOK INLET	  XVI-11

XVI-7  PRIMARY CAUSES AND CLASSIFICATION OF ACCIDENTS ON MODUS
      AND OSVS  	  XVI-15

XVI-8  NON-WATER QUALITY ENVIRONMENTAL IMPACTS PRODUCED WATER
        	  XVI-17

XVI-9  ENERGY REQUIREMENTS FOR COMMERCIAL DISPOSAL OF PRODUCED
      WATER FROM EXISTING SMALL-VOLUME WATER ACCESS FACILITIES
      IN THE GULF OF MEXICO  	.'	  XVI-19

XVI-10 ENERGY REQUIREMENTS FOR COMMERCIAL DISPOSAL OF PRODUCED
      WATER FROM EXISTING SMALL-VOLUME LAND ACCESS FACILITIES IN
      THE GULF OF MEXICO  	  XVI-20

XVI-11 FUEL REQUIREMENTS FOR GAS FLOTATION UNITS	  XVI-21
                                  XXI

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                    LIST OF TABLES (Continued)
                                                                 Page
XVI-12 FUEL REQUIREMENTS FOR DESIGN GAS FLOTATION SYSTEMS FOR
      EXISTING SOURCES  	  XVI-22

XVI-13 POWER UTILIZATION AND FUEL REQUIREMENTS FOR PRODUCED
      WATER TREATMENT OPTIONS	  XVI-23

XVI-14 ENERGY REQUIREMENTS FOR DESIGN INJECTION SYSTEMS FOR
      EXISTING SOURCES IN THE GULF OF MEXICO	  XVI-24

XVI-15 AIR EMISSIONS FOR PRODUCED WATER TREATMENT OPTIONS	  XVI-26

XVI-16 NON-WATER QUALITY IMPACTS FOR TWC FLUIDS -BAT AND NSPS
      OPTIONS	  XVI-30

XVI-17 NON-WATER QUALITY IMPACTS FOR TWC FLUIDS FOR BAT BY
      FACILITY TYPE	  XVT-31

XVI-18 NON-WATER QUALITY IMPACTS FOR TWC FLUIDS FOR NSPS BY
      FACILITY TYPE	  XVI-31
                                 xxii

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                                        SECTION  I
                                    INTRODUCTION
1.0   LEGAL AUTHORITY
       The. Environmental Protection Agency (EPA) is establishing these proposed Effluent Limitations
Guidelines, New Source Performance and Pretreatment Standards for the Coastal Subcategory of the Oil
and Gas Extraction Point Source Category under the authority of Sections 301, 304 (b), (c), and (e), 306,
307, 308, 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).  The proposed regulation and supporting technical
information is presented in the proceeding sections of this document. This section describes EPA's legal
authority for issuing them, as well as background information on prior regulations and litigations leading
up to this proposal.

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 and indirect dischargers are summarized
briefly below.

1.   Best Practicable Control Technology Currently Available (BPT)
       BPT effluent  limitations  guidelines are generally based on the average of the best  existing
performance by plants of various  sizes, ages,  and unit processes within the industrial category or
subcategory.
                                             1-1

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       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
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)
                    h
       BAT effluent limitations  guidelines, in general,  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 toxic pollutants and nonconventional
pollutants to navigable waters.  The factors considered in assessing BAT include the following: (1) the
age of the equipment and facilities involved, (2) the processes employed, (3) the engineering aspects of
the control technologies, (4) potential process changes,  (5) the costs and economic impact of achieving
such effluent reduction, (6) non-water quality environmental impacts  (including energy  requirements)
and (7) other factors as the EPA Adnunistrator deems appropriate (Section 304(b)(2)(B)  of the CWA).
EPA retains considerable discretion hi 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  (BOD), total suspended solids (TSS), fecal coliform, pH, and any additional pollutants defined
by the Administrator as conventional.  The Administrator designated oil and grease  as an additional
conventional pollutant on July 30, 1979 (44 FR 44501).

        BCT is not an additional limitation, but replaces BAT for the control of conventional pollutants.
In addition to other factors specified in section 304(b)(4)(B), the CWA requires that BCT effluent
limitations  guidelines be established hi light of a two-part  "cost-reasonableness" test (American Paper
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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 PR 24974, My 9,  1986).

4.   New Source Performance Standards (NSPS)
       NSPS are based on the performance of the best available demonstrated control technology
(BADCT).  Since new plants  have the opportunity to install the best and most efficient production
processes  and  wastewater  treatment technologies, Congress directed  EPA  to consider  the best
demonstrated process changes,  in-plant controls, and end-of-process control and treatment technologies
that reduce pollution to the maximum extent feasible. As a result, NSPS should generally represent the
most stringent numerical values attainable through the application of best available demonstrated control
technology for all pollutants (i.e., conventional, nonconventional, and priority pollutants). In establishing
NSPS, EPA is directed to take into consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements.

5.   Pretreatment Standards for Existing Sources (PSES)
       Under Section  307(b)  of the CWA, pretreatment standards for  existing  sources (PSES) are
developed to prevent the discharge of pollutants that may interfere with or pass through to publicly-owned
treatment works (POTWs).   These types of discharges  are known as indirect discharges. Pretreatment
standards are technology-based and analogous to BAT effluent limitations  guidelines.

6.   Pretreatment Standards for New Sources (PSNS)
       Section 307(c) of the CWA authorizes EPA to promulgate pretreatment standards for new sources
(PSNS) at the same tune it promulgates (NSPS).  PSNS are analogous to PSES in that PSNS limitations
are developed to prevent discharges of pollutants to pass through or interfere with POTWs. New indirect
dischargers have the opportunity to  install the best available demonstrated technologies into their new
plants similar to that of NSPS since the same factors  are considered when  promulgating both PSNS and
NSPS limitations; and therefore EPA sets PSNS after considering the same criteria considered for NSPS.

1.1.2  Section 304(m)  Requirements and Litigation
       Section 304(m) of the CWA (33  U.S.C.  1314(m)), added by the Water Quality Act of 1987,
requires EPA to establish schedules for (1) reviewing and revising existing  effluent limitations guidelines
and standards (effluent  guidelines), and (2) promulgating new effluent guidelines. On January 2, 1990,
EPA published  an Effluent Guidelines  Plan (55 FR  80), in  which schedules were established for
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developing new and revised effluent guidelines for several industrial categories. One of the industries
for which the Agency established a schedule was the Coastal Oil & Gas Extraction subcategory.  Natural
Resources Defense Council, Inc. (NRDC) and Public Citizen, Inc., challenged the Effluent Guidelines
Plan in a suit filed in U.S. District Court for the District of Columbia (NRDC et al v. Reillv, Civ. No.
89-2980).  The plaintiffs charged that EPA's plan did not meet the requirements of section 304(m).  A
Consent Decree  in this  litigation was  entered by the Court on January 31, 1992.  The terms of the
Consent Decree  are reflected  in the Effluent Guidelines Plan published on September 8, 1992 (57 PR
41000). This plan requires, among other things, that EPA propose effluent guidelines for the Coastal Oil
and Gas Extraction Point Source Subcategory by January  1995 and take final action on these effluent
guidelines by July 1996. EPA's latest Effluent Guidelines Plan was published in 1994 (59 PR 44234,
August 26, 1994).

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.  The PPA
declares that pollution should be prevented or reduced whenever feasible; pollution that  cannot be
prevented should be recycled  or reused in an environmentally safe manner wherever  feasible; pollution
that cannot be recycled should be treated; and disposal or release into the environment should be chosen
only as a last resort.

1.1.4   Prior Regulation and Litigation for the Coastal Subcategory
        Coastal subcategory  effluent limitations were proposed on October 13, 1976 (41 FR 44943).
On April 13, 1979 (44 FR  22069)  BPT  effluent  limitations guidelines  were promulgated for all
subcategories under the oil and gas category, but action on the BAT and NSPS regulations was deferred.
Table 1-1 presents the 1979 BPT limitations.

       On November 8, 1989, a notice of information and request for comments on the Coastal Oil and
Gas subcategory effluent limitations guidelines development was published (54 FR 46919). The notice
presented the Agency's approach to effluent  limitations guidelines development for BAT,  BCT,  and
NSPS. It also requested data available to develop such limitations.
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                                         TABLE 1-1
                COASTAL SUBCATEGORY BPT EFFLUENT LIMITATIONS*
Waste Stream
Produced Water
Drill Cuttings
Drilling Fluids
Well Treatment Fluids
Deck Drainage
Sanitary-MlO
Sanitary-M9IM
Domestic Wastes
Parameter
Oil and Grease
Free Oil*
Free Oil*
Free Oil*
Free Oil*
Residual Chlorine
Floating Solids
Floating Solids
BPT Effluent Limitation
72 mg/1 Daily Maximum
48 mg/1 30-Day Average
No Discharge
No Discharge
No Discharge
No Discharge
1 mg/1 (minimum)
No Discharge
No Discharge
*The free oil "no discharge" limitation is implemented by requiring no oil sheen to be present upon discharge.
Source: 40 CFR Part 435, Subpart D
       In addition to the 1989 Notice of Information, regulatory and litigation activity since 1979 has
occurred with respect to the definition of the coastal oil and gas industrial subcategory.   The 1976
regulations had previously defined "coastal" on a geographic basis which specified boundaries hi terms
of longitude and latitude.  Since then several changes were made or suggested regarding the definition
of the coastal subcategory.  These actions are summarized below:

                                   COASTAL DEFINITIONS
       1976:
Land and water areas landward of the inner boundary of the territorial seas and
bounded inland by a series of longitude and latitude points in Louisiana and
Texas (the Chapman line).
        1979:
The final rule defined coastal at 40 CFR, 435 as:  (1) Any  body of water
landward of the inner boundary of the territorial (current) seas as defined hi 40
CRF 125.1 (gg) or (2) any wetlands adjacent to such waters.
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       1981:
Wetlands are defined as surface areas which are saturated by surface or ground
water at a frequency and duration sufficient to support a prevalence of vegetation
typically adapted for life in saturated soil conditions. Wetlands generally include
swamps, marshes, bogs, and similar areas. (40 CFR Part 435.41 (f))

In addition, EPA attempted to reclassify approximately 1200  wells from the
coastal subcategory to the onshore subcategory because these wells were located
onshore but discharged to coastal  waters.   The American Petroleum Institute
challenged this reclassification.

American Petroleum Institute v. EPA. 661 F.2d 340, 354-57 (5th Cir. 1981), the
Court held that EPA had failed to consider adequately the cost to the reclassified
facilities of the 1979  regulatory change. As a result of the Court's decision,
EPA suspended the applicability of the onshore subcategory guidelines to the
reclassified wells and to any wells  that came into existence in the affected area
after the issuance of the 1979 redefinition.  See 47 FR 31554 (July 21, 1982).
        1989:
EPA proposed to modify the 1979 definition to include only those facilities in
saline water (greater than 0.5 parts per thousand) landward of the inner boundary
of the territorial seas.  (This would reclassify facilities located inland over saline
and fresh water areas  to the onshore or another subcategory).
       As "described in Section m of this document, EPA is proposing a modification to the current
(1979) coastal definition for this rulemaking.

       Additional related rulemakings included a series of general NPDES permits issued by EPA that
set BPT, BCT and BAT limitations applicable to sources in the coastal subcategory on a Best Professional
Judgment (BPJ) basis under Section 402(a)(l) of the CWA.  These permits are described hi Section ffl
of this development document.
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                                       SECTION II
               SUMMARY OF THE  PROPOSED REGULATIONS
1.0   INTRODUCTION
       The processes and operations which comprise the coastal oil and gas extraction subcategory
(Standard Industrial Classification (SIC) Major Group 13) are currently regulated under 40 CFR 435,
Subpart D. The existing effluent limitations guidelines, which were issued on April 13, 1979 (44 PR
22069), are based on the achievement of BPT.  This section summarizes the proposed effluent limitations
guidelines and NSPS for this subcategory based on BPT, BCT, BAT, BADCT. Pretreatment standards
are also being proposed and are described in this section.

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 coastal subcategory accomplishes
the following: (1) limits the discharge of oil and grease  in produced water to a daily maximum of 72 mg/1
and a monthly average of 48 mg/1; (2) prohibits the discharge of free oil in deck drainage, drilling fluids,
drill cuttings, and well treatment fluids; (3)  requires a minimum residual chlorine content of 1 mg/1 hi
sanitary discharges; and (4) prohibits the discharge of floating solids in 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 hi Chapter I Section 1.1.4.

       Produced sand is the only wastestream considered in today's proposal for which BPT limits are
being proposed, as it is the only wastestream considered by this proposal for which BPT limits have not
been previously promulgated.

       EPA  believes while it could revise  BPT for all of the wastestreams, administrative burden of
establishing such limitations which would then require revision in NPDES permits is not warranted.
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1.2   SUMMARY OF THE PROPOSED RULE
       EPA proposes to establish regulations based on "best practicable control technology currently
available" (BPT) for one specific wastestream for which BPT does  riot currently apply,  and "best
conventional pollutant control technology" (BCT), "pretreatment standards for existing sources" (PSES),
"best available  technology economically achievable" (BAT),  best  available  demonstrated control
technology (BADGT) for new sources, and "pretreatment standards for new sources" (PSNS) for all the
waste streams.

       Under this rule, EPA is co-proposing three options for the control of drilling fluids and cuttings
(including any effluent from dewatering pit closures activities) for BAT effluent limitations guidelines,
and NSPS.  The three options considered contain zero discharge for all areas, except two of the options
contain allowable discharges for Cook Inlet.  One of these options, which would allow discharges meeting
a more stringent toxicity limitation if selected for the final rule, would require an additional notice for
public comment since the specific toxicity limitation has not been determined at this tune.  The three
options are: Option 1 - zero discharge of all areas except Cook Inlet where discharge limitations require
toxicity of no less than 30,000 pm (SPP), no discharge of free oil and diesel oil and no more than 1 mg/1
mercury and 3 mg/1 cadmium in the stock barite, Option 2 - zero discharge for all areas except for Cook
Inlet where discharge limitations would  be the same as Option 1, except toxicity would be set to meet
a limitation between 100,000 ppm (SPP) and 1 million pm (SPP), and Option 3 - zero discharge for all
areas.  EPA is proposing PSES and PSNS prohibiting all discharges of drilling fluids and drill cuttings.
BCT for drilling fluids and cuttings is being proposed as zero discharge for the entire subcategory except
for Cook Inlet, Alaska.  BCT limitations for drilling fluids and cuttings for Cook Inlet would  require no
discharge of free oil (as determined by the static sheen test).

       EPA is proposing to prohibit discharges of produced water from all coastal subcategory operations
except those located hi Cook Inlet, Alaska, under BAT. Proposed BAT for coastal facilities in  Cook Inlet
would limit the discharge of oil and grease hi produced water to a daily maximum of 42 mg/1 and a thirty
day average of 29 mg/1.  EPA is proposing to prohibit discharges  of produced water from  all coastal
subcategory operations under NSPS, PSNS,  and PSES.  BCT limits for produced waters hi all coastal
regions (including Cook Inlet) would be set equal to the current BPT limitations, which limit the
discharge of oil and grease to a daily maximum of 72 mg/1 and a thirty day average of 48 mg/1.
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       BCT for treatment, workover and completion fluids is proposed to be set equal to current BPT
limits prohibiting discharges of free oil, with compliance to be determined by use of the static sheen test.
EPA is co-proposing two options for BAT and NSPS limitations for treatment, workover and completion
finds.  Option 1  would require no discharge of free oil and prohibit discharges  to freshwaters of Texas
and Louisiana. This option reflects current practice.  Option 2 would require the same limitations as the
preferred option for produced water. This option would require for BAT that discharges of treatment,
workover and completion fluids would be prohibited in all coastal areas except Cook Inlet. In Cook Inlet,
these  discharges  would be  required to meet a daily maximum oil and grease  limitation of 42 mg/1 and a
30 day average of 29 mg/1.  Option 2 would require zero discharge of these fluids everywhere for NSPS.
EPA proposes zero discharge as PSES, and PSNS  for treatment, workover and  completion fluids.

       BPT, BCT, BAT, NSPS, PSES and PSNS are being proposed for produced sand and would
prohibit all discharges of this wastestream.  The only BPT effluent limitations guidelines being proposed
today are for produced sand which is the only wastestream for which BPT limits have not been previously
promulgated.

       BCT, BAT, and NSPS limits being proposed for deck drainage would be  set equal to current BPT
limits prohibiting discharges of free oil, with compliance to be determined by use of the visual sheen test.
 EPA is proposing zero discharge for PSES and PSNS for deck drainage because collection and capture
of this wastestream is technically unpractical in many situations (as discussed later in Section VI.D.) such
that its direction to POTW's  would  rarely if ever occur.   EPA also believes that combining this
wastestream with  municipal treatment facilities that may already be at full  capacity  should not  be
encouraged.

       BCT is being proposed for domestic wastes as equal to  BPT (which is  no discharge of floating
solids) with an additional requirement prohibiting the discharge of garbage.  BAT is being proposed for
domestic wastes  to prohibit discharge of foam.  NSPS is being proposed for domestic wastes as equal to
BCT  and  no discharge of foam and no discharge of garbage.  No pretreatmeht standards  are being
established for domestic wastes.

       BCT and NSPS limitations for sanitary wastes are being proposed as equal to the current BPT
effluent limitations guidelines.  Sanitary waste effluents from facilities continuously manned by ten (10)
or more persons would contain a minimum residual chlorine content of 1 mg/1, with the chlorine level
maintained as  close to this concentration as possible. Coastal facilities continuously manned by nine or
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fewer persons or only intermittently manned by any number of persons must comply with a prohibition
on the discharge of floating solids. BAT is not being developed for sanitary wastes because no toxic or
nonconventional pollutants of concern have been identified in this waste stream.   No pretreatment
standards are being established  for sanitary wastes.

       Compliance with these proposed limitations  would result in a yearly decrease of 4.3 billion
pounds of toxic, nonconventional and conventional pollutants in produced water, from zero to 23 million
pounds of toxic nonconventional and conventional pollutants in drilling fluids and drill cuttings (depending
on the option considered), and zero to 3.9 million pounds of toxic, nonconventional,  and conventional
pollutants in treatment, workover, and completion fluids (depending on the  option considered).  The
tables summarizing the requirements of this proposal are presented in Section XIV of this  document,
"Options Selection: Rationale and Total Costs," Tables XTV-2 through XIV-7.

       As discussed in more detail in 1.4 of this section, this proposal does not take into account the
regulatory effects of the recently published final EPA Region VINPDES General Permits for production
facilities (January 9,  1995).  With these permits hi effect, the costs of this proposal will be reduced and
the actual reduction of pollutant loadings to coastal waters would be approximately 71 percent less, or
1.25 billion pounds per year, due to today's proposal. EPA will more fully incorporate the regulatory
effects of the Region VI General Permits upon promulgation of the final rule.

1.3   PREVENTING  THE CIRCUMVENTION OF EFFLUENT LIMITATIONS GUIDELINES AND NEW SOURCE
       PERFORMANCE STANDARDS
       This rule also proposes a provision intended to prevent oil and gas facilities subject to Part 435
of this Title from circumventing the effluent limitations guidelines, new source performance standards
and pretreatment standards applicable to those facilities by moving effluent from one subcategory to
another subcategory.  When EPA establishes its effluent limitations guidelines and standards, it does so
based on a determination, supported by analyses contained in the rulemaking record, that facilities in that
subcategory, among other factors also considered under the CWA, can technologically and economically
achieve the requirements of the rule. The purpose of the rule is not accomplished if facilities move
effluent from a subcategory with more stringent requirements to a subcategory with less stringent
requirements or if facilities move effluent from  a subcategory with less stringent requirements to a
subcategory with more stringent requirements and discharge effluent at the  less stringent limitations.
Until now, EPA has  attempted to prevent this  circumvention in  the  National Pollution Discharge
Elimination System (NPDES) permits issued for this industry.  EPA believes, however, that it would
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enhance the enforcement of these provisions to include them as part of the effluent limitations guidelines,
new source performance standards and pretreatment standards.

       Therefore, this rule proposes to prohibit oil and gas facilities from moving effluent from a
subcategory with more stringent requirements to a subcategory with less stringent requirements, unless
that effluent is discharged hi compliance with the limitations imposed by the more stringent subcategory.
For example, facilities could not move produced water generated from the onshore subcategory of the
oil and gas industry (which is subject to zero discharge requirements) to the offshore subcategory of the
oil and gas industry and dispose of the effluent at the offshore limitations and standards.  Similarly, this
rule proposes to prohibit facilities from moving produced water generated from the offshore subcategory
to the coastal or onshore subcategory and discharging the produced water at the offshore limitations. (An
offshore oil and gas facility could, however, pipe produced water to shore for treatment and return it to
offshore waters for disposal at the offshore limits.  Disposal of such produced water onshore however,
would be subject to zero discharge.)  EPA intends that these provisions would be applied prospectively
in future NPDES permits.

1.4   THE EPA REGION VI COASTAL OIL AND GAS PRODUCTION NPDES GENERAL PERMITS
       EPA's Region VI has recently published final NPDES General permits regulating produced water
and produced sand discharges to coastal waters in Louisiana and Texas (60 FR 2387, January 9, 1995).
The permits prohibit the  discharge  of produced  water and  produced sand derived from the coastal
subcategory to any water subject to EPA jurisdiction under the Clean Water Act.

       Much of the industry covered by this proposed rulemaking is also covered by these  General
permits.  However, a significant difference between the permits  and this proposal it that the permits do
not cover produced water discharges derived from the Offshore subcategory wells into the main deltaic
passes of the Mississippi  River, or to the Atchafalaya River below Morgan City including Wax  Lake
Outlet. The rulemaking being proposed  would cover these discharges (see the discussion in 1.3 above
entitled "Preventing the Circumvention of Effluent Limitations Guidelines and New Source Performance
Standards").

       Due to the close proximity of the timing of the publication of the Region 6 permits  and this
proposal, this document presents the costs and impacts of the proposed rulemaking as if the Region VI
General permits were not final.  As presented hi later sections of this document,  this proposal (including
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the facilities covered by the Region VI permit) would remove 4.3 billion pounds of pollutants in produced
water from being discharged per year.  The Region VI permit covers approximately 71 percent of the
produced water volume being discharged in the coastal subcategory. The remaining 29 percent is derived
from coastal facilities treating offshore produced waters and currently discharging them into main deltaic
river passes in Louisiana, as well as from other coastal operations in the U.S.  Thus, with the Region VI
General permits final, this rule would actually result in the removal of 1.25 billion pounds (29 percent
of 4.3 billion pounds) of pollutants per year from being discharged into coastal waters.

       As also presented in later sections of this document, compliance costs of this proposed rulemaking
(including the facilities covered by the Region VI permit) total approximately $40.4 million annually.
With the Region VT General permits final, the costs of this rule would be reduced to approximately $19.9
million annually.

       EPA  will more fully incorporate regulatory  effects of the Region VI General permits upon
promulgation of the final rule.
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                                       SECTION
                INDUSTRY DEFINITION AND WASTESTREAMS
1.0   INTRODUCTION
       This section describes the coastal subcategory by (1) regulatory definition,  (2) geographic
locations, and (3) classification of the major, miscellaneous, and minor waste streams.

2.0   REGULATORY DEFINITION
       The coastal subcategory of the oil and gas extraction point source category, as defined in 40 CFR
435.40, is comprised of those facilities involved in exploration, development, and production operations
in water bodies landward of the inner boundary of the territorial seas (shoreline). The inner boundary
of the territorial seas is defined in Section 502(8) of the CWA as "the line of ordinary low water along
that portion of the coast which is hi direct contact with the open sea and the line marking the seaward
limit of inland waters".  This  includes inland bays and wetlands. The  inner boundary of the territorial
seas has been identified by EPA for areas where coastal oil and gas activity exists.1

       This rulemaking applies to coastal facilities included hi the following SIC's: 1311-Crude
Petroleum and  Natural Gas, 1381-Drilling Oil and Gas Wells, 1382-Oil and  Gas Field Exploration
Services, and 1389-Oil and Gas Field Services, not classified elsewhere.

       The regulations currently define the coastal subcategory as  follows:
       "(1) any body of water landward of the territorial seas as defined hi 40 CFR 125. l(gg) or (2) any
wetlands  adjacent to such waters."  40 CFR Section 435.41(e).   Part 125 was revised at 44 FR 32948,
June 7, 1979.

       EPA proposes  to clarify the coastal definition hi this rule.  First, EPA intends to  revise  the
regulation to state that the coastal subcategory would consist of "any oil and gas facility located in or on
a water of the United States landward of the territorial seas."  As suggested by the preamble to the 1979
guidelines stating that the coastal definition was intended to encompass "all facilities located over waters
landward of the territorial seas, including wetlands adjacent to  such waters," 44 FR 22017 April  13,
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1979, EPA intended the subcategory to cover all facilities located over waters under CWA jurisdiction,
including adjacent wetlands.  Since 1979, courts  have made it clear that isolated  wetlands with an
interstate commerce connection are waters of the United State subject to CWA jurisdiction.  See, e.g.,
Hoffman Homes. Inc. v. Administrator 999 F.2d 256 (7th Cir. 1993).  The revised definition would
make it clear that facilities located in or on isolated wetlands would be considered to be coastal.  This
application of the coastal definition is consistent with Region 6 final general permit for coastal drilling
operations (58 FR 49126, 49127 - September 21, 1993).  Also, the revised definition would no longer
refer to 40 CFR 125.1(gg) which no longer exists in the CFR. That provision, however,  merely cited
section 502(8) of the CWA which defines territorial seas as "the belt of seas measured from the line of
ordinary low water along that portion of the coast which is in direct contact with the open sea and the
line marking the seaward limit of inland waters, and extending seaward a distance of three miles."  40
CFR 125.1(gg) (July 1,  1978).  That statutory definition is still in effect.

       In addition, EPA would explicitly include hi the definition of coastal certain wells located in the
area between the Chapmann line and the inner boundary of the territorial seas that were determined to
be coastal as a result of decision of the U.S. Court of Appeals for the Fifth Circuit. American Petroleum
Institute v. EPA. 661 F.2d 340 (5th Cir. 1981).  To Reflect this fact, the definition of coastal in 40 CFR
453.41(e) would be revised to include these wells.

2.1   NEW SOURCE DEFINITION
       EPA proposes to apply the definition of new source promulgated in the Offshore Guidelines to
the Coastal Guidelines.   As discussed in the Offshore Guidelines the definition of "new  source"  was
discussed at length in EPA's 1985 proposal for the  Offshore Subcategory of the Oil and Gas Extraction
Point Source Category,  (50 FR 34617-34619, August 26,  1985).  As discussed in that 1985  proposal,
provisions in the NPDES regulations define new source (40 CFR 122.2) and establish criteria  for a  new
source determination (40 CFR 122.29(b)).  EPA  is proposing special definitions which are consistent with
40  CFR 122.29 and which provide that 40 CFR 122.2 and 122.29(b) shall apply "except  as  otherwise
provided in an applicable new source performance  standard" (see 49 FR 38046, September 26, 1984).

       The  Coastal  Guidelines  would 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.
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       As discussed in 1985, Section 306(a)(2) of the Act defines "new source" to mean "any source,
the construction of which is commenced after publication of the proposed NSPS if such standards are
promulgated consistent with Section 306."  The CWA defines "source" to mean any "facility . . . from
which there is or may be  a discharge of pollutants" and "construction" to mean  "any placement,
assembly, or installation of facilities or equipment ... at the premises where such equipment will be
used."

       The regulations implementing this provision state, in part:

       "New  Source means any building structure, facility, or installation from which there is or may
be a 'discharge of pollutants,' the construction of which is commenced:
       (a) After promulgation of standards of performance under section 306 of the Act which are
applicable to such source, or
       (b) After proposal of standards of performance hi 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 § 122.2.
       "(4) Construction of a new source as  defined under § 122.2 has commenced if the owner or
operator has:
       (i) Begun, or caused to begin as part of a continuous on-site construction program;
       (A)  Any placement assembly, or installation of facilities or equipment; or
       (B)  Significant  site preparation work including clearing, excavation or  removal  of existing
buildings, structures or facilities which is necessary for the placement, assembly, or installation of new
source facilities or equipment; or
       (ii) Entered into a binding contractual obligation for the purchase of facilities or  equipment which
are intended to be used in its operation within a reasonable time. Options to purchase or contracts which
can be terminated or modified without substantial loss, and contracts for feasibility engineering and design
studies do not  constitute a contractual obligation under the paragraph." 40 CFR § 122.29(b)(4) (emphasis
added).

       In  1985, EPA proposed to define,  for purposes  of the  Offshore Guidelines, "significant site
preparation work" as "the process of clearing and preparing an area of the ocean floor for purposes of
constructing or placing a development or production facility on  or  over the site." (emphasis added).
Thus, development and production wells would be new sources under the Offshore Guidelines. Further,
with  regard to 40 CFR 122.29(b)(4)(ii), EPA stated that although it was  not "proposing a special
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definition of this provision believing it should appropriately be a decision for the permit writer," EPA
suggested that the definition of new source include development or production sites even if the discharger
entered into a contract for purchase of facilities or equipment prior to publication, if no specific site was
specified  in the contract.  Conversely,  EPA suggested that the  definition  of new source exclude
development or production sites if the discharger entered into a contract prior to publication and a specific
site was specified in the contract.

       As a consequence of the proposed definition of "significant site preparation work," if "clearing
or preparation of an area for development or production has occurred at a site prior to  the publication
of the NSPS, then subsequent development and production activities at the site would not be considered
a new source" (50 FR 34618).  Also, exploration activities at a site would not be considered significant
site preparation work, and therefore exploratory wells would not be new sources (50  FR 34618).  The
purposes of these distinctions were to "grandfather" as an existing source, any source if "significant site
preparation work . .  . evidencing an intent to establish full scale operations at a site, had been performed
prior to NSPS becoming effective" (50 FR 34618). At the  same time, if only exploratory drilling had
occurred prior to  NSPS becoming effective, then subsequent drilling and production wells would be
considered to be new sources.

       EPA also proposed a special definition for "site" hi  the phrase significant site preparation work
used in 40 CFR 122.2 and 40 CFR 122.29(b).  "Site" is defined in 40 CFR 122.2 as "the land or water
area where any 'facility or activity' is physically located or conducted, including adjacent land used in
connection with the  facility or activity."  EPA proposes 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, August 26, 1985).

        EPA intends to use the  same definition of "new source" in the Coastal Guidelines as was used
in the Offshore Guidelines.

        As  a consequence of these distinctions, exploratory  facilities would always be existing sources.
Production and development facilities where significant site preparation has occurred prior to the effective
                                              ra-4

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date of the Coastal 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 hi 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 rule would temporarily exclude from the
definition of "new source" those facilities that as of the effective  date of the Coastal Guidelines would
be subject to an existing general permit pending EPA's issuance of a new source NPDES general permit.
EPA believes this approach is reasonable because when Congress enacted Section 306 of the CWA it did
not specifically address mobile activities of the sort common in this industry, as  distinguished from
activities at stationary facilities on land that had not yet been constructed prior to the effective date of
applicable NSPS.  Moreover, EPA believes that  Congress did not intend that the promulgation of NSPS
would result  in stopping all oil  and gas activities which would  have been authorized under existing
NPDES permits as soon as the NSPS are promulgated.  Once NSPS are promulgated, EPA would 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 Coastal Subcategory.  EPA intends
to issue as final,  after opportunity for notice and comment, new source  NPDES permits as soon as
possible.

       In summary,  a drilling  operation  would be a  new  source  if the drilling rig  is drilling a
development well (not an exploratory well) in a new water area.  Exploratory drilling or drilling from
an existing platform or rig that has not moved since it drilled a previously existing well would not be a
new source. For production, a new source  would be a facility discharging from a new site.

2.2   GEOGRAPHICAL  LOCATIONS  OF THE COASTAL INDUSTRY
       As previously stated, coastal oil and gas activities are located on water bodies inland of the inner
boundary of the territorial seas.  These water bodies include inland lakes,  bays and sounds, as well as
saline, brackish, and freshwater wetlands. Although the definition includes inland waterbodies hi all U.S.
states, EPA knows of no existing coastal operations other  than those in certain states bordering the coast.
Thus, although the rule would apply to all areas defined as  coastal, at this tune the coastal industry is
located only hi coastal states.
                                             III-5

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       Current coastal oil  and gas activity exists along the Gulf Coast states of Texas,  Louisiana,
Alabama and Florida.  The great majority of Gulf Coast activity resides in Texas and Louisiana. There,
coastal oil and gas operations exist in a number of topographical situations including bays, sounds, lakes,
or wetlands.  Coastal oil and gas activity hi Alabama is located hi Mobile Bay.  A small number of wells
are also located on wetlands along the West Coast of Florida.

       Coastal oil and gas activity hi California exists hi Long Beach Harbor. There, four man-made
islands have been constructed solely for the  purpose of oil and gas extraction.

       Roughly half of the coastal oil and gas activity exists hi Alaska. Deep water platforms exist in
the northern part of Cook Inlet. In addition,  operations resembling onshore activities (as opposed to deep
water platforms) are located on the tundra wetlands of Alaska's North Slope.

       See Section IV for more details  regarding the number of production wells, drilling activity, and
production volumes located hi these areas.

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.

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, to counter balance formation pressure, and to  transport drill cuttings to
the surface. A water-based drilling fluid is the conventional drilling mud hi 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.
                                              in-6

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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, the
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 phase
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.

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.
                                             ra-7

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2.4.5   Deck Drainage

       The term "deck drainage" refers to any waste resulting from deck washing spillage, ram water,
and runoff from gutters and drams including drip pans and work areas within facilities subject to this
subpart.  Deck drainage can occur during production as well as drilling.


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, coastal exploration
and production facilities discharge other wastewaters.  These wastes were investigated but are considered
to be minor and, more appropriately controlled by NPDES permit limitations. Therefore, no controls
for these wastes are proposed by this rule.  These wastes are categorized into the following 14 minor

wastes categories:


      1)        Desalination unit discharge - wastewater associated with the process  of creating  fresh
               water from seawater.

      2)        Blow  out preventer fluid - fluid used to actuate the hydraulic equipment on the blowout
               preventer.

      3)        Laboratory wastes from drams.

      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 and
               well abandonment and plugging.

      6)        Uncontaminated sea  water including fire control and utility lift pumps excess water,
               excess sea water from pressure maintenance, water used in training and testing of fire
               protection personnel, pressure test water, and non-contact cooling water.
                                              III-8

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     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.
     11)        Uncontaminated fresh water such as air conditioning condensate and potable water.
     12)        Material that may accidentally discharge during bulk transfer, such as cement materials,
               and drilling materials such as barite.
     13)        Waterflooding discharges - discharges associated with the treatment of seawater prior to
               its injection into a hydrocarbon-bearing formation to improve the flow of hydrocarbons
               from production wells. These discharges include strainer and filter backwash water, and
               treated water in excess of that required for injection.
     14)        Test fluids - the discharge  that would occur should  hydrocarbons  be located during
               exploratory drilling and tested for formation pressure and content.
3.0   CURRENT NPDES PERMIT STATUS
3.1    NPDES PERMITS
       EPA  has  regulated discharges from coastal oil and  gas  operations in the  Gulf of Mexico,
California, and Alaska by general and individual National Pollutant Discharge Elimination System
(NPDES) permits, issued under Section 402 of the CWA, based on BPT, State Water Quality Standards,
and on Best Professional Judgment (BPT) of BCT and BAT levels of control.

       EPA's Region VI has developed general NPDES permits for each phase of oil and gas operations
(drilling and production). The drilling permit was proposed in 1990 and promulgated on September 21,
1993 (58 PR 49126). The production permit was proposed on December  22, 1992 (57 FR 60926), and
promulgated on January 9, 1995 (60 FR 2387).

       EPA's Region X issued a BPT and BPJ general NPDES permit for oil and gas operations in the
Upper Cook Inlet. However, although expired, conditions of this general permit are still fully effective
and enforceable until the permit is reissued. Region X is currently in the process of reissuing the BPT
and BPJ/BAT general permit for this area with proposal expected in early 1995.  In addition to the
general permit, the Region issued an  individual permit regulating discharges from exploratory drilling
                                            m-9

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operations in Upper Cook Inlet in May 1993.  The  individual permit was also based on BPT and
BPJ/BAT.

       The State of Alabama which has been authorized to administer the NPDES program, has also
issued a final NPDES general permit covering facilities in State waters, including offshore and coastal
facilities (including Mobil Bay) (Permit #ALG280000, May 25, 1994). This permit specifically prohibits
the discharge of drilling fluids and cuttings, and produced water.  The permit also does not allow the
discharge of produced sands or treatment, workover and completion fluids.

       In addition to technology pollutant removal performance, regional permit requirements are based
on other  factors, including water quality criteria.  Table ffl-1 presents a summary of the requirements
in these permits.

3.2   STATE REQUIREMENTS
       Regulations affecting the discharges from coastal oil and gas facilities in California include the
California State Water Resources Control Board's 1990 "Water Quality Control Plan for Ocean Waters
of California."  This "Plan" requires effluent limitations be met for oil and grease of 25 mg/1 (30-day
average), 75 mg/1 (maximum at any time), settleable solids of 1 mg/1 (30-day average), 3 mg/1 (Maximum
at any time), turbidity 75 NTU (30-day average), and pH of 6-9, for all discharges from POTW's and
industrial point sources.3  Total suspended solids are regulated by requiring that discharges shall, as a 30
day average, remove 75% of suspended solids from the wastestreams before discharging.  In addition,
discharge effluent  limitations are  specified  for acute  toxicity,  metals,  phenolic compounds and
radioactivity.

       Florida's coastal oil and gas discharges  are primarily regulated by Florida's Department of
Environmental Protection (DEP).  Regulations recently issued by the DEP prohibit the discharge of oil
and gas wastestreams.2
                                            HI-10

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         TABLE III-l




NPDES PERMIT REQUIREMENTS*

Wastestream



Produced
Water




Produced
Sand
Drilling
Fluids
and Cuttings




,








"Dewatering
Effluent"







Treatment,
Completion,
Workover
Fluids





Domestic
Wastes



REG1
Region X (Cl 1986 BPT
permit)


Monitor daily flow rate Oil &
Grease: Phillips A Platform
20 mg/1 daily max
15 mg/1 mo. ave. Other
facilities: 48/72 mg/1 pH= 6-
9
No free oil (Static Sheen)

1) Toxicity: Discharge only
approved generic muds
2) No free oil - static sheen
3) No discharge oil-based
muds
4) 10 percent oil content for
cuttings
5) No diesel oil
6) 1/3 mg/kg Hg/Cd in dry
barite
7) Flow rate
>40m = 1000 bbl/hr
>20-40m = 750 bbl/hr
> 5-20m = 500 bbl/hr
< 5m = No discharge

Not separately regulated








No free oil (Static Sheen)
No oil-based fluids
Ph = 6-9
Oil and grease limits apply to
combined discharge of any
TWC Commingled with
produced water


No free oil (no visible sheen)
No Floating solids
Monitor flow rate


K>NAL PERMTTREQtMl
Region X Exploration
Permit (1993)


Not applicable





Not applicable

1) Flowrate = 750
bbl/hr
2) Use authorized muds
only
3) Toxicity: 30,000
ppm in SPP
4) No free oil
5) No discharge of oil-
based fluids
6) 5 percent (wt) oil
content in cuttings
7) No discharge of
diesel oil
8) 1 mg/kg Hg and 3
mg/kg Cd in stock
barite
Not separately
regulated







No discharge of free oil
or oil-based fluids
Monitor frequency of
discharge and volume
pH = 6.5-8.5
Oil & grease = 72
daily max. & 48 mo.
avg.

Monitor flow rate
No free oil (No visible
sheen)
No floating solids
No visible foam
EMENTS
Region VI
Drilling Permit
(1993)

Covered in
Production Permit




Not applicable

No Discharge















No free oil
50 mg/1 TSS
125 mg/1 COD
pH=6-9
500 mg/1
chlorides
0.5 mg/1 total Cr
5.0 mg/1 Zn
Monitor Volume
Freshwater: No
discharge



Saline Water: No
toxics, No free
oil (visual sheen),
pH = 6-9
No discharge of
solids ("garbage")




Region VI
Production
Permit
(1995)
No Discharge





No Discharge

Not
applicable














Not
Applicable







Not
Applicable







Not
Applicable




Region IV
Permit
(1994)

No
Discharge




No
Discharge
No
Discharge














Not
separately
regulated






No
Discharge







See note
below**



           in-ii

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::'.'., REfGIONALPERMTT.lffiQtoffi^ife^
Wastestream



Deck
Drainage



Sanitary
Wastes










Region X (Cl 1986 BPT
permit)


No Fee oil (Visual Sheen)
Monitor flow rate (mo. ave.)



No floating solids
As close as possible to, but no
less than 1.0 mg/1
BOD & SS***
24 hr = 60 mg/1
7 day = 45 mg/1
30 day = 30 mg/1





Region X Exploration
Permit (1993)


Monitor flow rate (mo.
avg.)
No free oil (visual
sheen)

No free oil (No visible
sheen)
No floating solids
No visible foam
As close as possible but
no less than 1 mg/1
BOD:30day=30mg/l
24 hr =60 mg/1
TSS: 30 day=TSS
intake + 30 mg/1
24 hr = TSS
intake + 60 mg/1
Region VI
Drilling Permit
(1993)

No free oil
(visual sheen)
Monitor volume


No floating solids
BOD = 45 mg/1
TSS = 45 mg/1
fecal coliforms =
200/100 mis
Monitor flow






,
Region VI
Production
Permit
(1995)
Not
Applicable



Not
Applicable










'
Region IV
Permit
(1994)

Monitor
daily flow
No free oil
(visual
sheen)
See note
below**










* For a Compete presentation of the effluent limitations and their bases in the permits see the following: Region X Proposed General
Permit for Cook Inlet (50 FR 28974, 7/17/85); Region X Final Permit for Cook Inlet (51 FR 35460, 10/3/86); Region VI Final
General Permit for Drilling Operations (58 FR 49126, 9/21/93); Region VI Proposed General Permit for Production Operations
(57 FR 60926,  12/22/92). The Region X Exploration Permit and the Region IV Permit are in the records for this rulemaking.

**NOTE: The Region IV permit includes limitations for sanitary and domestic wastes as presented below:

          1) Treated sanitary, galley and domestic wastewater (< 10,000 gpd) from continuously manned facilities
                  Flow                               10,000 gpd (daily maximum)
                  BODS                              45 mg/1 (daily max)                  30 mg/1 (mo ave)
                  TSS                                45 mg/1 (daily max)                  30 mg/1 (mo ave)
                  Total residual chlorine               1.0 mg/1 (daily min.) maintained as close to this value as possible
                  Fecal Coliform                      100/100 mis (daily max. and mo ave)
                  Solids                              No floating solids

          2) Treated domestic wastewater (< 10,000 gpd) not commingled  and cotreated with sanitary and/or galley wastewater
                  Flow                               10,000 gpd (daily max)               monitor (mo. ave)
                  BOD5                              45 mg/1 (daily max)                  30 mg/l(mo ave)
                  TSS                                45 mg/1 (daily max)                  30 mg/1 (mo ave)
                  Solids                              No floating solids

          3) Treated sanitary and domestic wastewater (< 10,000 gpd) from intermittently manned facility
                  Flow                               10,000 gpd                         monitor (mo ave)
                  Solids                              No floating solids

          4)  Sanitary, galley, and domestic wastewater (< 10,000 gpd) from floating construction and/or maintenance facilities
                  Flow                               10,000 gpd (daily max)       monitor (mo ave)
                  Solids                              No floating solids

 *** Limits apply only to discharges to state waters and separately for BOD and SS.
                                                        ra-12

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4.0   REFERENCES
1.      Avanti Corp, "Delineation of the Seaward Boundary of the Coastal Subcategory of the Oil & Gas
       Extraction Industry," May 3, 1993.

2.      Rules of the State of Florida Department of Environmental Protection, Florida Geological Survey,
       Oil and Gas Section, Conservation of Oil and Gas Chapters 16C-25 through 16C-30.   Florida
       Administrative Code, Chapter 16C-28, Section 28.003.

3.      Wiedman, A., Memorandum to file regarding "Coastal Oil and Gas Activity in CA, AL, MS,
       and EL," September 6, 1994.
                                          111-13

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                                       SECTION  IV
                               INDUSTRY DESCRIPTION
1.0   INTRODUCTION
       This  section describes  the major processes  associated with the oil  and gas extraction  and
production industry located in the coastal regions of the United States, and presents the current and future
production and drilling activities for this industry.

2.0   DRILLING ACTIVITIES
       There are two types of operations associated with drilling for oil and gas:  exploratory  and
development. Exploratory drilling includes those operations that involve the drilling of wells to determine
potential hydrocarbon reserves.  Development drilling includes those operations that involve the drilling
of production wells, once a hydrocarbon reserve has been discovered and delineated. Although the rigs
used in exploratory and development drilling sometimes differ, the drilling process is generally the same
for both types of drilling operations.  Drilling in coastal areas occurs on land (or wetland areas that are
dry during certain parts of the year) as well as over water or wetlands.  As described later in this section,
the drill site location (over water or land) as well as water depth are influential when determining the type
of drilling rig used.

2.1    EXPLORATORY DRILLING
       Exploration for hydrocarbon-bearing  strata consists of several indirect and direct methods.
Indirect methods, such as geological  and geophysical  surveys,  identify  the physical and  chemical
properties of formations through surface  instrumentation.  Geological surveys determine subsurface
stratigraphy to identify rock formations that are typically associated with hydrocarbon bearing formations.
Geophysical  surveys  establish the depth and nature   of  subsurface  rock formations  and  identify
underground conditions favorable to oil and gas deposits. There are three types of geophysical surveys:
magnetic, gravity, and seismic.  These surveys are conducted from the surface with equipment specially
designed for this purpose.   Direct exploratory drilling, however, is the only method to confirm the
presence of hydrocarbons and to determine the quantity of hydrocarbons after the indirect methods have
indicated hydrocarbon potential. Exploratory  wells are also referred to as "wildcats."
                                             rv-i

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        Shallow exploratory wells are usually drilled in the initial phases of exploration to discover the
presence of oil and gas reservoirs.  Deep exploratory wells are usually drilled to establish the extent of
the oil  or gas reservoirs, once they have been discovered.  These types of exploration activities are
usually of short duration, involve a small number of wells, and are conducted from mobile drilling rigs.

2.1.1   Drilling Rigs
        Mobile drilling rigs are used to drill exploratory wells because they can be easily moved from
one drilling location to another.  These units are self contained and include all equipment necessary to
conduct the drilling operation plus living quarters for the crew.  The two basic types of mobile drilling
units for drilling hi w.ater 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.'

        Bottom-supported drilling units are  typically used hi the Gulf of Mexico region when drilling
occurs in shallow waters.  Submersibles are barge-mounted drilling rigs that are towed to the drill site
and sunk to the bottom.  There are two common types of submersible rigs: posted barge and bottle-type.
In shallow and inland waters, these units may be surrounded by barges to store and to transport materials
and wastes to and from the site.

        Jackups are barge-mounted drilling  rigs designed with extendable legs.  During transport, the
extendable legs are retracted. At the drill site, the legs are extended to the bottom.  As the legs continue
to extend, the barge hull  is lifted above the water. Jackup rigs can be used in waters up to 300 feet deep.
There are two basic types of design for jackup rigs: columnar leg and open-truss leg.  Jackup rigs are
used in the Cook Inlet of Alaska for exploratory drilling.

        Land-based drilling rigs are also used in the coastal  region of the  Gulf of Mexico and on the
North Slope.   Land-based drilling rigs  are different from water-based  drilling rigs in that they  are
disassembled and transported from location to location by trucks. Land-based drilling rigs also take up
more surface area than water-based drilling rigs.  Land-based drilling  rigs are usually surrounded by an
earthen levee with a ditch to  capture any runoff from the site.  Materials and wastes are transported to
and from the drill site by truck.   Onsite living quarters are usually only provided for the supervisory
personnel.
                                              IV-2

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2.1.2   Formation Evaluation
        The operator is constantly evaluating the  characteristics of the formation during the drilling
process. The evaluation involves measuring properties of the reservoir rock and obtaining samples of
the rock and fluids from the formation.  Three common evaluation methods are well logging, coring, and
drill stem  testing.   Well logging uses instrumentation that  is placed in the wellbore and  measures
electrical, radioactive, and acoustic properties of the rocks. Coring consists of extracting rock samples
from the formation and characterizing the rocks. Drill stem testing brings fluids from the formation to
the surface for analysis.1

2.2    DEVELOPMENT DRILLING
        Development of the oil and gas reservoirs involves drilling of wells into the reservoirs to initiate
hydrocarbon extraction, increase production or replace wells that are not producing on existing production
sites.  Development wells tend to be  smaller hi diameter than exploratory wells because,  since the
geological and geophysical properties of the producing formation are known, drilling difficulties can be
anticipated and the  number of workovers during drilling minimized.   In the Gulf of Mexico coastal
region, development wells average 8,500 feet in depth.  In Alaska, development wells average 12,000
feet in depth.2

        Different types of drilling rigs are used during development drilling, depending on the location
of the producing reservoir. In the Gulf of Mexico region, mobile drilling units are used for development
drilling as well as exploratory drilling. In the Cook Inlet region of Alaska, the two most commonly used
types of drilling rigs are the platform rig and the mobile drilling units. Development wells  are often
drilled from fixed platforms hi Cook  Inlet because once the exploratory drilling has confirmed the
existence of extractable quantities of hydrocarbons, a platform is constructed at that site for drilling and
production operations. On the North Slope, development drilling is done from both dedicated and mobile
drilling rigs. The drilling rig and all the associated equipment are housed and insulated to protect them
from the harsh weather conditions.

        To extract hydrocarbons from the reservoir effectively, several wells may be drilled into different
parts of the formation.  A special drilling technique, termed "directional drilling", has been developed
to penetrate different portions of a reservoir from a fixed location directly below the rig. Directional
drilling involves drilling the top part of the well straight and then directing the wellbore to the desired
location in nonvertical directions.   This requires special drilling  tools and devices  that measure the
                                              IV-3

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direction and angle of the hole. Directional drilling also requires the use of special drilling fluids that
prevent temperature build up and stuck pipe incidents due to the increased stress on the drill bit and drill
string.  Directional drilling is commonly practiced hi the Cook Inlet and on the North Slope. Although
not commonly practiced in the Gulf of Mexico, some operators employ this drilling method to minimize
environmental impacts (e. g., hi protected wetlands) and to speed up the well permitting process by using
existing drilling pads.3

        Horizontal drilling is a specialized directional drilling technique that maximizes the length of
penetration in the pay zone (hydrocarbon reservoir) by horizontally drilling through the pay zone, thus
maximizing the fluid extraction from a single production string.4 Horizontal drilling is also referred to
as drilling under balance as there is no pressure equilibrium between the formation and the bore hole as
in conventional drilling.  The formation pressure is greater than  the bore hole pressure  (a blow out
condition) but special surface equipment controls the down hole pressure differentials preventing a  blow
out.

        Horizontal drilling is occasionally  practiced in coastal environments when the geometry of the
reservoir makes horizontal drilling the most economical method of extracting the hydrocarbon reserves.4
It should be noted that horizontal drilling is  not practiced as a means of minimizing impacts to the surface
environment.  Also, horizontal drilling is associated with greater volumes of waste than vertical drilling
because the length of the borehole is greater and the drilling tune is longer.

2.2.1   Well  Drilling
        The process of drilling the first few hundred feet of a well is referred to as "spudding."  This
process consists of extending a large diameter pipe, known as the conductor casing, from the drilling rig
to a few hundred feet below the surface.   The conductor casing,  which is approximately two feet hi
diameter,  is either hammered, jetted,  or placed into the ground depending on the  composition of the
ground. If the composition of the ground  is soft, the conductor casing can be hammered into place or
lowered into a hole created by a high-pressure jet of water. In areas where the ground is composed of
harder material, the casing is placed hi a hole created by a large-diameter rotating drill bit.

        Rotary drilling is  the drilling process used to drill the well. The rotary drilling process consists
of a drill bit attached to the end of a drill pipe, referred to as the "drill string," which makes a hole in
the ground when rotated.  Once the well is spudded and the conductor casing is in place, the drill string
                                              IV-4

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is lowered through the inside of the casing to the bottom of the hole.  The bit rotates and is slowly
lowered as the hole is formed.  As the hole deepens, the walls of the hole tend to cave in and widen, so
periodically the drill string is lifted out of the hole and casing is placed into the newly formed portion
of the hole to protect the wellbore.  Cement is pumped into the space between the casing and the hole
wall to secure the casing in place.  Each new casing string must be smaller in diameter than the previous
string to allow for installation.  This process of drilling and adding sections of casing is continued until
final well depth is reached.

        Rotary drilling utilizes a system of circulating drilling fluid to move drill cuttings away from the
bit and out of the borehole. The drilling fluid, or mud, is a mixture of water, special clays, and certain
minerals and chemicals. The drilling fluid is pumped downhole through the drill string and is ejected
through the nozzles in the  drill bit with great speed and pressure. The jets of fluid lift the cuttings off
the bottom of the hole and away from the bit so that the cuttings do not interfere with the effectiveness
of the drill bit.  The drilling fluid is circulated to the surface through the space between the drill string
and the casing, called the annulus, where cuttings, silt, sand, and  any gases are removed before returning
the fluid down-hole to the bit.   The cuttings, sand, and silt are separated  from the drilling fluid by a
solids separation process which typically includes a shaleshaker, desilter, and desander and sometimes
centrifuges. Figure IV-1 presents a schematic flow diagram of the fluid circulation system. Some of the
drilling fluid remains with  the cuttings after solids separation.5-6

        Drilling fluids function, to cool and lubricate the bit, stabilize the walls of the borehole, and
maintain equilibrium between the borehole and the formation pressure.  The drilling fluid must exert a
higher pressure  in the wellbore than exists in the surrounding  formation,  to  prevent formation fluids
(water,  oil,  and gas) from  entering the wellbore which will otherwise migrate from the formation into
the wellbore, and potentially create a blowout.  A blowout occurs when drilling fluids are ejected from
the well by subsurface pressure and the well flows uncontrolled. To prevent well blowouts, high pressure
safety valves called blowout preventers (BOPs) are attached at the top of the well.

        Since the formation pressure varies at different depths, the density of the drilling fluid must be
constantly monitored and adjusted to the downhole conditions during each phase of the drilling project.
One purpose of setting casing strings is to accommodate different fluid pressure requirements at different
well depths.  Other properties of the drilling fluid, such as lubricity, gel strength, and viscosity, must also
be controlled to satisfy changing drilling conditions.  The fluid must be replaced if the drilling fluid
cannot be adjusted to meet the downhole drilling conditions.  This is referred to as a "changeover."
                                              IV-5

-------
                    Cuttings
                    (Waste)
Fluid Slowdown
   (Waste)
                                                     New Make-up
                                                      filing Fluids
I
Fluids +
Sepa
Sys
^
Cuttings
ration _
tern
1
Retire
->• Fli
r >
ulated
lid
r
                                                        To Disposal
               Figure IV-1
Typical Drilling Fluids Circulation System
                   IV-6

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        The solids control system is necessary to maintain constant fluid properties and/or change them
as required by the drilling conditions. The ability to remove drill solids from the drilling fluid, referred
to as "solids removal efficiency," is dependent on the equipment used and the formation characteristics.
High solids content in the drilling fluid, or a low solids removal efficiency, results in increased drilling
torque and drag, increased tendency for stuck pipe, increased fluid costs, and reduced wellbore stability.
More detailed discussion on solids control systems can be found in Section VH.

        Operators control the solids content of the drilling fluid by adding fresh fluid to the circulating
fluid system to  reduce the percentage of solids and to rebuild the desired Theological properties of the
fluid.   A disadvantage  of dilution is that the  portion of the  fluid removed,  or displaced, from the
circulating system must be stored or disposed.  Also, greater quantities of fluid additives are required to
formulate the replacement fluid.  Both of these add expenses to the drilling project.

        Most drilling fluid fluids are water-based, although oil-based systems are used for specialized
drilling projects and more recently synthetic based drilling fluid systems  are becoming more popular.
In the 1970's, drilling fluids were mostly oil-based. The trend  away from oil-based fluids is due to: 1)
the BPT limitations which prohibit the discharge of drilling wastes if "free oil" is detected; and 2)
advancements in water-based  fluids technology.  Until recently, only oil-based fluids could achieve the
temperature stability and lubricity properties required by special drilling conditions such as directional
and deep well drilling.   However, advancements in drilling fluid technology have enabled operators to
formulate water-based fluids with similar properties to that of oil-based fluids through the use of small
quantities of oil and/or synthetic additives. Small quantities of oil and/or synthetic additives are used to
enhance the lubricity of a water-based fluid system and to aid hi freeing stuck drill pipe.  In the past,
diesel oil  was solely used to  enhance lubricity and to free stuck pipe because of its properties and its
availability at a drilling site. More recently, mineral oil and synthetic lubricants have replaced diesel oil.
When oil  or a synthetic  spotting fluid is used as an aid hi 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 hi the annulus area
where the pipe  is stuck.  Most of the pill can be removed from the bulk fluid 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 fluid system.7

        The most significant waste streams, in terms of volume  and constituents associated with drilling
activities, are drilling fluids and drill cuttings. Drill cuttings are generated throughout the drilling project,
                                               rv-7

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 although higher quantities of cuttings are generated during drilling of the first few thousand feet of the
 well because the borehole is the widest during this stage. The largest quantities of excess drilling fluids
 are generated as the project approaches final well depth. Fluids are generated during the drilling process
 because of displacement due to solids control, fluid changeover, and displacement by cement and casing.
 Fluid generation is the greatest at well  completion because the entire fluid system must be removed from
 the hole and the  fluid tanks.   Some  of the constituents in the drilling fluid can be recovered after
 completion of the drilling program, either at the rig or by the supplier of the  drilling fluid.  Where
 drilling is  continuous, such as on multiple-well platforms, the fluid can be conditioned and reused from
 one well to another.8

 3.0    PRODUCTION ACTIVITIES
         This section describes the activities and processes associated with producing hydrocarbons from
 the formation and processing the production fluids. The activities and processes described hi this section
 are well completion, fluid extraction, fluid separation, well treatment, and workover.

 3.1     COMPLETION
         After confirmation  of  a successfully  producing formation,  the  well  must  be prepared  for
 hydrocarbon extraction, or "completion."  Completion operations include  the setting and cementing of
 the production casing,  packing the well and installing the production tubing.  During the completion
 process equipment is installed in the well which allows hydrocarbons to be extracted from the reservoir.
 Completion methods are determined based on the type of producing formation, such as hard sand, loose
 sand, fine gram loose sand,  and loose  fine and coarse gram sands.  Bridging agents are used to prevent
 fluid loss from the well to the formation.9-10

         There are two  types of completions:  open hole and cased hole.   Open hole completions are
 performed on consolidated formations.   Cased hole completions are performed on unconsolidated
 formations.  Figure IV-2 presents schematic diagrams of the four most common completion methods used
' for different formation types. All completion methods consist of four steps: wellbore flush, production
 tubing installation, casing perforation, and wellhead installation.

         Completion fluids are used during the completion phase to clean  the wellbore or for pressure
 maintenance until production is initiated.  The initial wellbore flush consists of  a slug of water that is
 injected into the casing.  These fluids are considered cleaning or pre-flush fluids and can be circulated
                                              rv-8

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A. FOR HARD SAND FORMATION
   •OPEN HOLE COMPLETED-
                          PRODUCTION
                            TUBING
B. FOR LOOSE SAND FORMATION
  -CLOSED HOLE COMPLETION-
                                                                            PRODUCTION
                                                                              TUBING
                                                                                 CEMENT
                                             HANGER
                                                                                  CASING
                                                                                       UNER
                                                                                      CEMENTED
                                                                           *a.iy.4««i    AND




                                                                                       PACK
C.  FOR FINE GRAIN LOOSE SANDS
                           PRODUCTION
                             TUBING

                                               D. FOR LOOSE FINE AND COARSE GRAIN SANDS
                          PRODUCTION
                            TUBING
                                     SCREEN
                                       Figure IV-2
                              Typical Completion Methods
                                           IV-9

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and filtered many times to remove solids from the well and to minimize the potential of damage to the
formation.11  When the well has been cleaned, a second completion fluid termed a "weighing fluid" is
injected. This fluid maintains sufficient pressure to prevent the formation fluids from migrating into the
hole until the well completion is finished.

        During the second step of well completion, production tubing is installed inside the casing using
a packer which is placed at or near the end of the tubing.  The packer which consists of pipe, gripping
elements, and sealing elements, is made of rubber.  The purpose of the packer is to keep the tubing in
place by expanding to form a pressure-tight seal between the production tubing and the well casing.1'12
The packer seals off the annular space and forces the reservoir fluids to flow up through the tubing and
not into the well annulus. Packer fluids are completion fluids that are trapped between the casing and
the production tubing by the packer.  These fluids are used to provide long-term protection against
corrosion.  Packer fluids are typically mixtures of a polymer viscosifier, a corrosion inhibitor, and a high
concentration salt solution.13  Packer fluids remain hi place and may be removed  during workover
operations.14

        After the production tubing is secured in place with packers, it must be perforated  to allow the
hydrocarbons to flow from the reservoir into the wellbore.   Perforation may be accomplished with a
special gun (usually lowered into the  well by wireline) that fires steel bullets or  shaped charges which
penetrate the casing and cement.  An  additional means of perforation is achieved by suspending a small
perforated pipe from the bottom of the casing.1-12

        The final step hi well completion is the installation of the "Christmas tree," a device  that controls
the flow of hydrocarbons from the well. When the valves of the Christmas tree are initially opened, the
completion fluids remaining in the tubing are removed and flow of fluids from the formation begins.

3.2    FLUID EXTRACTION
        The fluid produced from oil reservoirs consists of oil, natural gas (referred to hereafter as gas),
and produced water.  Gas wells may produce dry gas, but usually also produce varying quantities of light
hydrocarbon liquids (known as natural gas liquids or condensate) and produced water. Produced water
contains dissolved and suspended solids,  hydrocarbons,  metals, and may contain small amounts of
radionuclides. Suspended solids consist of sands, clays, or other fines from the reservoir.
                                              IV-10

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        Crude oil can vary widely in its physical and chemical properties. Two important properties are
its density and viscosity.  Density usually is measured by the "API gravity" method which assigns a
number to the oil according to its specific gravity.  Oil can range from very light gasoline-like materials
(called natural gasolines) to heavy,  viscous asphalt-like materials.

        Production fluids flow to the surface through tubing inserted within the cased borehole.  For oil
wells, the energy required to lift  the fluids up the well is supplied by  the natural  pressure in the
formation, known as natural drive.  There are four kinds of natural drive mechanisms found with oil and
gas production:   dissolved-gas drive, gas-cap drive, water drive, and combination gas and water drive.
                    *
        As hydrocarbons are produced, the natural pressure in the reservoir decreases and additional
pressure must be added to the reservoir to continue production of the fluids. Additional pressure can be
provided artificially to the reservoir by various mechanisms at the surface.  The most common methods
of artificial lift, or secondary recovery, are the following three: (1) gas lift, which is the injection of gas
into the well in order to lighten the column of fluid in the borehole and assist in lifting the fluid from the
reservoir as the gas expands while rising to the surface; (2) waterflooding, which is the injection of water
into the  reservoir to maintain formation pressure that would otherwise drop as  the withdrawal of the
formation fluids continue; and (3) employment of various types of pumps in the well itself. As the fluids
in the well rise to the surface, they flow through a series  of valves and flow control  devices that make
up the wellhead.

3.2.1   Enhanced Oil Recovery
       When an oil field is depleted by primary and secondary methods (e.g., natural flow, artificial lift,
waterflooding), as much as 50 percent of the original oil  may remain in the formation. Enhanced oil
recovery (EOR) processes  have been developed to recover a portion of this remaining oil.  The EOR
processes can be divided  into  three general classes:  (1) thermal,  (2) chemical,  and (3) miscible
displacement.

       Thermal: Thermal processes include steam stimulation, steam flooding, and in situ combustion.
Steam stimulation and flooding  processes differ primarily in the number of wells involved in a field.
Steam stimulation uses an injection-wait-pump cycle in a single well, whereas the steam flooding process
uses a continuous steam injection into a pattern of wells and continuous pumping from other wells within
                                             IV-11

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the same pattern.  The in situ combustion process uses no other chemicals than the oxygen required to
maintain the fire.

        Chemical:  Chemical EOR processes include surfactant-polymer injection, polymer flooding, and
caustic flooding.  In the first process, a slug of surfactant solution is pumped down the injection well
followed by a slug of polymer solution to act as a drive fluid.  The surfactant "washes" the oil from the
formation, and the oil/surfactant emulsion is pushed toward the producing well by the polymer solution.
In polymer flooding, a polymer solution is pumped continuously down the injection well to act as both
a displacing  compound and a drive fluid.  Surfactant and polymer injection may require  extensive
treatment of the water used in solution make-up before the surfactant or polymer is  added. Caustic
flooding is used to drive oil through a formation toward producing wells. The caustic is delivered to the
injection wells via a manifold system; the injection head is similar to that used in steam flooding.

       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.

3.3    FLUID SEPARATION
        As they surface, the gas, oil, and water are separated for further processing and sale, and for
treatment. The gas, oil, and water are separated hi a single vessel or, more commonly practiced,  in a
series of vessels.  Gas dissolved hi 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 hi the reservoir
or can be caused by the extraction process which tends to vigorously mix the  oil and the water.  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 pumps hi the system, tends to increase
emulsification.  Moderate heat, chemical addition, quiescent settling, and/or electrical charges aid in the
separation of emulsified liquids.  The produced fluid separation system is a series of separation vessels
arranged hi a multistage separation process.  Figure IV-3 presents a flow diagram of a typical produced
fluid separation system.
                                             IV-12

-------
        The first stage of the produced fluids separation system consists of two-phase separators, or in
some cases of three-phase separators.  High-, intermediate-, and low-pressure separators are the most
common arrangement, with the high-pressure liquids passing through each stage in series and gas being
taken off at each stage.  For gas wells the two-phase separators may generate light hydrocarbons that
condense out as the pressure and temperature drop.  These light hydrocarbons (known as gas liquids or
condensate) can be processed and sold separately at a higher price than oil, or most commonly combined
and processed with the oil. In a two-phase separator, the gas is separated from the liquid products.  The
separated gas is dehydrated in a glycol dehydrator and then used for electrical power generation, gas lift
operations, or sold via pipeline. The liquid products free of gas are further treated in the oil treatment
unit.  A schematic of a two-phase separator is presented in Figure IV-4.

        A three-phase separator, often referred to as bulk separator, is sometimes used instead of a two-
phase separator to separate the produced fluids into gas, oil and water.  The gas stream is drawn off the
top of the vessel and further treated in a glycol dehydrator. The oil stream is drawn off the middle and
piped to the oil treatment system for further processing. The water stream is drawn off the bottom and
is piped to the  water treatment system for further treatment.  A schematic diagram of a bulk separator
in presented in Figure IV-5.

        Following the  gas  separation, the oil-water mixture is directed to the oil treatment system for
separation.  The oil treatment system consists of free-water knock out (FWKO)  tanks, heater-treaters,
and/or gun barrels.  These types of oil-water separation systems may be used singly  or  in various
combinations.  FWKOs  are often used to remove free water (water that is not in emulsion) from the
influent to heater-treaters in order to reduce the amount of fluids to be heated, thus reducing the energy
needed to heat the fluids.

        Whether or not a phase separator is used, if oil-water emulsions are present heater-treaters  are
required.  Heat and/or emulsion-breaking chemicals are almost  always necessary to break the oil-water
emulsions to assure low  water content hi the oil product (most pipelines have water content limitations
on the oil that  can be transported).  Heater-treaters are designed to remove emulsified water from the
product oil through gravity separation aided by heat and/or the addition of chemicals to enhance and
accelerate separation.  Oil is drawn off the top of the heater/treater unit and sent to the oil product vessel
for storage. Water is removed from the bottom of the heater/treater unit and is either piped to the gun
barrel or the water treatment unit.  A schematic diagram of a heater-treater is presented in Figure IV-6.
                                             rv-13

-------
                                                             0)
                                                        O  nf C >,
                                                        t.  O) 2 5=
                                                        «  J5 S-o
                                                        o>
                                                             O fr
o>
            CO
            CD
            CO
                                             0)
                                             13
                                     3
                                      en
                                      (D
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                           IV-14

-------
                                  GAS OUT
                INLET
             LIQUID OUT
Source: Smith Industries, Inc., 1980
                                             -i PRESSURE
                                               RELIEF
                                 Figure IV-4
                             Two-Phase Separator
                                   IV-15

-------
                                                   IV-16
_

-------
        Gun barrels are sometimes used as a final oil-water separation process.  The name refers to the
fact that these units are usually configured as tall vertical tanks to allow for gravity flow of oil to the oil
stock tanks. Figure IV-7 presents a schematic diagram of a gun barrel.  A gun barrel is essentially a tall
settling tank which utilizes gravity separation, sometimes assisted with heat and/or chemicals to further
break the oil water emulsion.  The water is piped to the water treatment unit.

        The water treatment system receives produced water from the oil treatment unit.  Water treatment
usually consists of one or more large settling tanks, also called skim tanks, which utilize gravity to
remove any residual suspended oil droplets from the produced water.  This process  is sometimes aided
with the use of treatment chemicals such as surfactants.

        An oil layer accumulates in the top portion of the tank: Oil is periodically removed from the top
of the tank and is piped back to the oil treatment unit. Water is drawn off the bottom of the vessel and
is either discharged to surface waters if it meets the BPT  oil and grease limitations, injected underground
or transported to another site for disposal.   In addition  to the skim tank, the water  treatment unit may
include gas flotation and  coalescers.  A detailed discussion of these other produced  water treatment
technologies can be found Section VIII.

        The major  waste  stream associated with production activities is the produced water stream.
Produced sand or production solids is another waste stream of lesser volume.  Both waste streams
originate with the production fluids and are separated from the hydrocarbon products  in the produced
water treatment system.

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.11 A
well treatment job will enlarge the existing channels within the formation and increase the productivity
of the formation. Typically, hydraulic fracturing is performed on sandstone
formations,  and acid treatment is performed on formations of limestone or dolomite.10'12

        Hydraulic fracturing injects fluids into the well under high pressure, approximately 10,000 pounds
per square inch gage (psig).  This causes openings in the formation to crack open, increasing their size
                                             IV-17

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        GAS OUTLET
        EMULSION INLET
        OIL OUTLET
           EMULSION
           DOWNCOMER
Source:  Sunda, November 23, 1994
                                                       SEPARATOR
                                                       SECTION WITH
                                                       GAS MIST
                                                       EXTRACTOR
 EXHAUST
 STACK
                                                       FIRE TUBE
                                                       ASSEMBLY
                                                       WITH BURNER
                                                       & FLAME
                                                       ARRESTOR
                                                       FREE WATER
                                                       KNOCK OUT
                                                       SECTION
                                                       WATER DUMP
                                                       VALVE &
                                                       CONTROLLER
WATER
OUTLET
                               Figure IV-6
                          Verticle Heater - Treater
                                 IV-18

-------
LLI
                                                                       1
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                                                                oo
                                                                 §
                 IV-19

-------
and creating new openings. The fracturing fluids contain inert materials referred to as "proppants," such
as sand, ground walnut shells, aluminum spheres, and glass beads, that remain in the formation to prop
the channels open after the fluid and pressure have been removed.10'18 Hydraulic fracturing is rarely done
in Gulf of Mexico operations because the unconsolidated sandstone  formations in the region  do not
require fracturing.

       Acid stimulation is performed by injecting acid solutions into the formation. The acid solution
dissolves portions  of the formation rock, thus enlarging the openings  in the formation.  The two most
common types of acid treatment are acid fracturing and matrix acidizing. Acid fracturing utilizing high
pressures results hi additional fracturing of the formation.  Matrix acidizing uses low pressures to avoid
fracturing the formation. The acid solution must be water soluble, safe to handle, inhibited to minimize
damage to the well casing and piping, and inexpensive.10

       In addition to well treatment using hydraulic fracturing and acidizing, chemical treatment of a
well may also be performed.  Well treatment with an organic solvent like xylene or toluene will remove
paraffins or asphalt blocks from the wellbore.  These deposits of solid hydrocarbons occur due to the
decrease in temperature and pressure when the liquid hydrocarbons are extracted from the well.19

3.5    WORKOVER
       Workover  operations are performed on a well to improve or restore productivity, repair or
replace downhole equipment, evaluate the formation, or abandon a well.  Loss of productivity can be the
result of worn out equipment, restricted fluid flow due to sand hi the well, corrosion, malfunctions of
lift valves, etc.  Workover  operations include well pulling, stimulation (acidizing  and fracturing),
washout, reperforating, reconditioning, gravel packing, casing repair, and replacement of subsurface
equipment.10-20'21 Responses to EPA's 1993 survey of coastal oil and gas facilities (discussed in Section
V) indicated that workovers or treatment jobs occur approximately once per year.2 The EPA survey of
coastal operators is described hi detail hi Section V.

       The four general classifications of workover operations are pump, wireline, concentric, and
conventional22,  Workovers can be performed using the original derrick if drilled from a drilling platform,
a mobile workover rig, or by wireline.  The operation is begun by using a workover fluid to  force the
production fluids back into the formation to prevent them from exiting the well during the operation.
                                             rv-20

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Then tools and devices can be attached to the wireline (a spool of strong fine wire) and lowered and
pulled from the well to perform the required operations.

4.0    PRODUCTION AND DRILLING: CURRENT AND FUTURE
4.1     INDUSTRY PROFILE
        Coastal oil and gas extraction activities currently exist in the Gulf of Mexico coastal regions of
Texas, Louisiana, Alabama and Florida, in Long Beach Harbor, California, and in Cook Inlet and the
North Slope,  Alaska.   Because of dramatic geological,  topographical and climatological differences
between these areas, production and drilling activities in these areas are equally as varied. In addition
to the geographic location,  several other factors affect the operations of this industry.  These factors
include whether oil, gas or both oil and gas are produced, whether the producing well(s) are located over
water and wetlands or on land, the depth of water, whether it is a single producing well or a cluster of
single wells, and whether it is a multi-well platform.  The coastal oil and gas industry is described below
in terms of production and drilling activity, as well as location and operational differences, where
appropriate.

        In general, the same factors that affect the operations of the producing wells will also affect the
configuration  of the separation/treatment facilities (production facilities)  that service these wells.
Production facilities consist of the treatment equipment and storage tanks that process the produced fluids.
Production facilities may be configured to service one well, or as central facilities (also known as tank
batteries or gathering centers) to service multiple satellite wells.  Production facilities are also configured
to service a single multi-well platform,  or to service multiple platforms.   A multiple-well producing
platform is a fixed structure usually located in deep waters, with least two producing wells that have the
same surface location.23

        Coastal production facilities can be located over water or on land.  Production facilities located
over water exist hi generally two types of configurations:  1) individual deep water multi-well platforms
or 2) central facilities supported on barges or wooden or  concrete pilings that service multiple satellite
wells in shallow water.  Production facilities on land may service  satellite wells in any combination of
locations.

        Depending on operational preference or regulatory requirements, many of the coastal production
facilities do not discharge produced water.  While these facilities are discussed in the industry profile,
                                              IV-21

-------
they would not incur costs due to this rulemaking.  Table IV-1 summarizes the number of producing
wells and  annual  drilling activities  for the coastal  regions of the United States  and the number of
producing facilities that would incur costs due to this rulemaking, by geographic locations.

        The production facilities listed hi Table IV-1 are discharging produced water in the coastal areas
of Texas (TX), saline and brackish coastal waters of Louisiana (LA), and the Cook Inlet of Alaska.  All
coastal  production facilities hi Mississippi (MS), Alabama (AL), Florida (PL), the North Slope,  and
California  inject all of their produced water either for disposal or for waterflooding.   There are no
discharges  of drilling fluids and cuttings from coastal operators except for those in Cook Inlet.  The
volumes and  locations of discharges  are discussed in more detail hi Sections VIII and IX.

4.2    CURRENT PRODUCTION OPERATIONS
4.2.1   Gulf of Mexico
        Multi-well platforms, such as those found hi the Gulf of Mexico offshore area, are not commonly
found in the  Gulf coastal  area.  Based on an earlier mapping effort of all oil and gas wells, EPA
determined that there are only four structures owned and  operated by  four different operators in the
coastal  Gulf of Mexico region that can be classified as multi-well platforms.23  In addition, many single
wellheads are located throughout coastal waters, serviced by gathering centers located on-land or on
platforms.

        Production facilities hi the Gulf of Mexico can be divided into two different types of structures:
those located on land or fill material and those located over water or wetlands.  Production facilities
located  on land and fill material hi wetlands  and shallow  water usually utilize earthen berms around
storage tanks and equipment to contain spills. Production facilities located over water  and protected
wetlands can be located on diked concrete platforms supported on wooden or concrete pilings. In deeper
waters such as in open bays, steel jacketed pilings or offshore type platforms may be necessary. Some
of the older facilities have been constructed using wooden platforms or pilings. Another configuration
for facilities over water is the use of barges to support equipment and for use as storage tanks. Although
there are some exceptions, hi most cases those located on land can be accessed by car or truck (land-
access)  while those facilities located  over water must be accessed by boat or barge (water-access). This
distinction is important because when estimating regulatory compliance  costs  and impacts as described
hi Sections X and XI.
                                             IV-22

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        An analysis of the EPA 1993 Questionnaire database indicates that, of the estimated 530 coastal
production facilities in the Gulf of Mexico region, 182 (or 34.4%) are land-accessed facilities and 348
(or 65.6%) are water-accessed facilities (see discussion in Section XII.3.1.1).a  Of the total number of
production facilities hi Louisiana and Texas,  approximately 60% inject the produced water.2  Also, of
the total volume of miscellaneous wastes generated hi Texas and Louisiana, 40% is currently injected or
land disposed.2 Based on state discharge monitoring records and the discharge compliance schedules
implemented hi Louisiana, EPA determined that of the total coastal production facilities hi Louisiana and
Texas, 216 will continue discharging produced water after August 1, 1996 J23

        Table IV-2 summarizes information on existing coastal oil and gas production facilities hi the Gulf
of Mexico. Detailed information on the 216 discharging facilities is presented in Appendix XI-3.

                                          TABLE IV-2
             OIL AND  GAS PRODUCTION FACILITY INFORMATION FOR  THE
                             COASTAL TEXAS AND LOUISIANA
Type of Facility
Discharging Facilities
All Facilities
No. Production
Facilities*
216"
853d
Average Volume
Produced Water
per Production
Facility (bpd)
2,265b
1565°
Average Oil
Production per
Production
Facility (bpd)
245C
2003e
Average Natural
Gas Production
per Production
Facility (Mcfd)
2649C
2179C
* The facility that accepts hydrocarbon fluids from one or more wells and separates them into oil, gas, and produced water is
 termed a "Production Facility."
6 Mdntyre, December 30, 1994 (25)
c SAIC, January 31, 1995 (2)
* Jones, September 26, 1994 (24)
« Henderson, August 22, 1994 (32)
4.2.2   Mississippi, Alabama, Florida
        According to the Mississippi State  Oil and Gas Board, there are  currently no  coastal wells
operating hi the wetlands  of Mississippi.  None are planned  hi the foreseeable future.   The only
Mississippi oil and gas activity is onshore some 6 miles inland.33
   *     The number 530 was the actual result from the 308 Questionnaire responses. This value was extrapolated to 853 as shown in Table
IV-1 to reflect actual industrial activity.24 However, for determining percentile assumptions such as the number of water-based versus land-based
facilities, the actual result of 530 was used in estimation calculations.
                                              IV-24

-------
       Alabama coastal oil and gas activity consists of approximately 15 producing gas wells located in
Mobile Bay.34  Approximately 3-5 new wells are drilled in Bay each year.35  All produced waters from
the Bay's activities are injected for disposal in UIC Class n wells located onshore. All drilling fluids and
cuttings are also transported to  shore for disposal at onshore commercial disposal facilities.

       In Florida, approximately 41 producing oil and gas wells currently exist in coastal areas on the
western side of the state.36 Average drilling rate is approximately 2 new wells per year.  All produced
water  is injected in Class II UIC wells,  primarily for disposal  although  some  is also injected for
waterflooding.  All drilling fluids are either reused, annularly injected, or left hi a dry wellbore.  Drill
cuttings are either disposed of hi reserved pits or hauled off site to landfills.

4.2.3   California
       The California coastal oil  and gas  industry currently exists on four man-made islands hi Long
Beach Harbor behind the barrier islands in San Pedro Bay. The facilities on these islands are operated
by THUMS, a consortium of five oil and gas  operating companies (Texaco,  Humble (now  Exxon),
Union, Mobil and Shell).  On these  four  islands operated by  THUMS, approximately 586 wells are
producing as of 1993.37 Six to seven new wells  are drilled each year.  All produced waters  from these
operations  are  injected, primarily for waterflooding.  No discharges occur from drilling  fluids and
cuttings. Closed-loop solids control technology is employed by these operations. All dewatered solids
are sent to an onshore landfill. The water from the solids dewatering equipment is allowed to settle (on-
site) and the decant is directed to the on-site produced water treatment system.  Plans are to begin using
a grinding and injection operation hi 1994 for drilling waste disposal.  The ground wastes will  be injected
into a UIC well on site.

4.2.4   Cook Inlet
       All the coastal oil and gas production is  currently confined to the Upper portion of Cook Inlet.
Oil and gas is produced from multi-well platforms that are similar hi construction to offshore platforms.
Table IV-3 presents information on existing oil and gas production facilities in Cook Inlet as of August
1993.   There  are four major  operators  hi  Cook Inlet:  Unocal Corp.,  Marathon Oil  Co.,  Phillips
Petroleum Co., and Shell Western E&P Inc.  In addition, ARCO and Phillips Petroleum are  together
developing  a new discovery, the Sunfish field, which is located  hi the North Upper Cook  Inlet.
However, this  field  has not been brought into production as  of this writing.  The total  current oil
                                             IV-25

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production in Cook  Inlet is  about 34,700  barrels per day  (bpd)  and the total  gas production is
330,000,000 cubic feet per day (cfd).28

       There are a total of 15 multi-well platforms in Cook Inlet, 12 of which were productive as of
August 1993. Five of the fifteen platforms separate and treat the produced water on the platform before
it is discharged overboard.  The remaining eight platforms pipe the production fluids to three shore-based
separation/treatment facilities.  Of the three shore-based facilities, two discharge treated produced water
from the facility, and the third sends its produced water back to one of the platforms for discharge.
These three facilities treat and discharge 95 % of the produced water generated from all platforms in Cook
Inlet (see Table IV-3).
                   *

       As of August 1993, Unocal owned and operated eight platforms hi the Trading Bay, Granite
Point,  and Middle Ground Shoal fields, which included a total of 135 oil producing wells, 22 service
wells used to inject seawater, and 4 gas producing wells. These platforms produced a total of 21,300 bpd
of oil in 1993.  The  gas produced by all Unocal-owned wells is not sold  and is only used to power
equipment on platforms.  Four of the platforms are located in the Middle Ground Shoal field and separate
and treat the production fluids on the platform. Oil is piped to shore for sale, while the produced water,
which totals 1,690 bpd from these four platforms, is discharged overboard.  The remaining four platforms
are located in the Trading Bay and the Granite Point fields and pipe the production fluids to two shore-
based facilities for separation and treatment.  All produced water from these platforms, totaling 84,090
bpd, is discharged to Cook Inlet after treatment at the onshore facilities.

       Marathon owns and operates four platforms in the Trading Bay and Granite Point fields, including
  *                                                              ,
a total of 38 oil producing and service wells (undistinguished in the data source), and 22 gas producing
wells.  Only two of  the four platforms are  currently producing oil and gas.  Of  the two platforms
currently shut-in, plans are to initiate gas production on only one platform.  The total produced water
flow from the two active platforms averages 43,972 bpd.  All the production fluids  are piped to either
the Granite Point or the Trading Bay shore-based facilities for separation and treatment. Produced water
is discharged to Cook Inlet after treatment.

       Shell Western E&P owns and operates two platforms in the Middle Ground Shoal field, including
a total of 46 oil producing and service wells and one gas producing well.  The gas produced is not sold
and  is only used to power equipment on platforms.  The total produced water flow from the two
platforms is 3,300 bpd.  All production fluids are piped to the East Forelands shore-based facility for
                                             IV-26

-------
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                                       IV-27

-------
separation and treatment.  Produced water is discharged to Cook Inlet after treatment.

       Phillips  Petroleum operates one platform in the North Cook Inlet field, including 12  gas
producing wells. All produced water generated is treated at the platform and discharged overboard.

4.2.5   North  Slope
       Table IV-4 summarizes the most current information regarding oil and gas production on the
North Slope. As can be seen from Table IV-4, there are a total of 2,085 oil, gas, and service wells on
the North Slope. The Prudhoe Bay field is the largest production field on the North Slope, accounting
for about 71 % of the total oil production on the North Slope. The two major operators in Prudhoe Bay,
ARCO and BP Exploration (BPX), which own and operate the east side and the west side, respectively.
                                          TABLE IV-4
            OBL AND GAS PRODUCTION FACILITIES ON THE NORTH SLOPE
                                 (Weideman, August 31, 1994)28
Field Name
Prudhoe Bay
Kuparuk
Endicottb
Lisburne
Milne Point
West Beach
Operator
ARCO&BPX
ARCO
BPX
ARCO
Conoco0
ARCO
Total
Number of ;
Oil, Gas, and
Service Wells
1,159
663
85
86
91
1
2,085
Oil
Production*
(bpd)
1,126,000
300,000
115,000
30,000
19,000
3,000
1,593,000
Average
Produced
Water (bpd)
1,233,000
300,000
80,000
8,000
11,000
0
1,632,000
Nsmber of
Gathering
Centers "
6
3
1
1
1
0
12
1 Oil production data include natural gas liquid and condensate production, where applicable.
6 Endicott field data also include production from BP's Sag Delta near Endicott.
c Conoco sold this field to BPX in December, 1993.
NOTE:
Point Mclhiyre, West Beach, and N. Prudhoe Bay production is handled in the Lisburne Production Center.
       Production fluids are piped to gathering centers for separation and treatment.  All the produced
water from the North Slope oil production operations is injected either for waterflooding or into regulated
                                             IV-28

-------
disposal wells. About 88% of all the produced water is injected for waterflooding. The remaining 12%
is injected into Class II disposal wells.28

        There are a total of 12 production facilities (gathering centers) on the North Slope, of which all
but the Endicott gathering center are in the coastal region.  The Endicott field is currently produced from
two gravel  islands constructed  in  the Beaufort Sea.  The production facilities on  these islands are
permitted, by the Alaskan Department of Environmental Conservation, as offshore facilities.  All the
produced  water from the Endicott field is injected  for waterflooding.28

4.3    FUTURE COASTAL OIL AND GAS ACTIVITY
4.3.1   Drilling
        Coastal drilling efforts vary from year to year depending on such factors as the price and supply
of oil, the amount of State and Federal leasing, and reservoir discoveries.  EPA estimates that a total of
161 wells will be drilled in coastal areas, including development wells and recompletions.43

        Based on drilling projections provided by the industry, EPA estimates future drilling in the Cook
Inlet region to be a total of 55 wells (or 8 per year) over the 7-year period from 1996 through 2002.39'40
The projected 55 wells include development wells and recompletions.  Based on the  data provided by
industry,  EPA estimates that 36 of the  55 wells  are development and  exploratory wells and  19 are
recompletions. These estimates are based on industry-projected drilling activity estimates and on the
number of unused slots on each platform.  Projections were assumed to represent recompletions for those
platforms  where drilling was  projected but no slots are available for new wells. Out of these 55 wells,
none will  be classified as "new sources" under EPA's NPDES program.  This is because  the projected
wells will be drilled from existing platforms, or will be exploratory wells (classified as existing sources).
See also Section HI of this document.

        EPA estimates that the current drilling rate  experienced by other coastal states in 1992 (see Table
IV-1) will be similar to  future annual drilling rates, also.  This is a conservative estimate based on
projections where drilling rates are not expected to increase (due to the maturity of the Gulf coastal oil
fields).  Rather than project a decrease hi drilling rates, EPA is estimating a linear projection.41  Thus,
out of the 686 well drilling operations performed per year hi Texas and Louisiana, 187 of them will be
for new production wells (as  reported in the EPA's statistical analysis of the 1993 Coastal Oil and Gas
Questionnaire.2 (Note: The  Questionnaire is discussed in detail in Section V).
                                             IV-29

-------
       These estimated  187 projected drilling operations per year are new sources because they are
expected to be drilled over a new site. The remaining 499, which are either recompletions,  sidetracks
of existing wells, exploration or service wells, are not new sources because they are drilled from existing
operations.

4.3.2   New Production Activity
       New production  activity for Louisiana and Texas is estimated to include six new facilities or
separation/treatment facilities per year, based on results of the 1993 Coastal Oil and Gas Questionnaire.26
For Alabama and Florida, EPA estimates a maximum of one new production facility per year, based on
a comparison of  the  number  of producing  wells in Alabama/Florida to the number of wells in
Louisiana/Texas.

       No new sources  are expected  hi Alaska.  Although exploration and development of new fields
will continue on the North Slope, according to the operators there are no plans to build new production
facilities.31  For new discoveries, operators on the North Slope intend to  take advantage of existing
separation/treatment facilities as much as possible, assuming that these facilities have sufficient capacity
to handle the increased load.31 For Cook Inlet, no new source production facilities are expected to occur
hi the near  future.  This  is because, even considering the  Sunfish discovery, no new  platforms
construction is expected.42

       EPA knows of no plans for new islands at the THUMS facility at Long Beach Harbor, California.
                                             IV-30

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5.0   REFERENCES

1.     Baker, Ron, "A Primer of Offshore Operations," Second Edition, Petroleum Extension Service,
       University of Texas at Austin, 1985.

2.     SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31, 1995.

3.     Navarro, Armando R., "Innovative Techniques Cut Costs in Wetlands Drilling," in Oil and Gas
       Journal. October 14, 1991, pp. 88-90.

4.     Walters, Herb, Swaco Geolograph, Personal communication with Joe Dawley of SAIC regarding
       drilling characteristics of the Gulf Coast region, August 17, 1993.

5.     Ray,  James P.,  "Offshore Discharges of Drill Cuttings," Outer Continental Shelf Frontier
       Technology. Proceedings of a Symposium, National Academy of Sciences, December 6, 1979.
       (Offshore Rulemaking Record Volume 18)

6.     Meek, R.P., and J.P. Ray, "Induced Sedimentation, Accumulation, and Transport Resulting from
       Exploratory Drilling Discharges of Drilling Fluids and Cuttings on the Southern California Outer
       Continental Shelf," Symposium - Research on Environmental Fate and Effects of Drilling Fluids
       and Cuttings, Sponsored by API, Lake Buena Vista, Florida, January 1980.

7.     U.S.  EPA,  Development  Document  for Effluent  Limitations Guidelines and New Source
       Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source
       Category, Final, EPA 821-R-93-003. January 1993.

8.     U.S. EPA.  Response to "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160, July 1993.

9.     American Petroleum Institute, "Detailed Comments on EPA  Supporting Documents  for Well
       Treatment and Workover/Completion Fluids,"  Attachment to API Comments on the March 13,
       1991 Proposal, May 13, 1991. (Offshore Rulemaking Record Volume 146)

10.    Walk, Haydel and Associates, "Industrial Process Profiles to Support PMN Review; Oil Field
       Chemicals," prepared for EPA, undated but received by EPA on June 24, 1983.  (Offshore
       Rulemaking Record Volume 26)

11.    Wiedeman,  Allison, U.S. EPA, Memorandum to Marv Rubin, U.S. EPA,  "Supplementary
       Information to the 1991 Rulemaking on Treatment/Workover/Completion Fluids," December 10,
       1992.

12.    Wilkins, Glynda E., Radian Corporation, "Industrial Process Profiles for Environmental  Use
       Chapter 2 Oil and Gas Production Industry,"  for U.S. EPA, EPA-600/2-77-023b, February
       1977.  (Offshore Rulemaking Record Volume 18)

13.    Gray, George R., H. Darley,  and W. Rogers, "Composition and Properties of Oil Well Drilling
       Fluids,"  January 1980.

14.    Arctic Laboratories Limited,  et. al., "Offshore Oil and Gas Production Waste  Characteristics,
       Treatment Methods,  Biological Effects and their Applications to Canadian Regions,"  prepared
       for Environmental Protection  Services, April 1983.  (Offshore Rulemaking Record Volume 110)
                                           IV-31

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15.    Smith Industries, Inc. Equipment Manual, 2nd Edition, Oil and Gas Division, Houston TX,
       December 1980.

16.    Sunda, John, SAIC, Memorandum to the record regarding "Production operation diagram
       submitted by Tim Brown of Texaco in response to follow-up questions regarding the Bayou Sale,
       Louisiana Tank Battery sampled by EPA on Oct. 23, 1992," November 23, 1994.

17.    American Petroleum Institute, "Introduction to Oil and Gas Production," 1983.

18.    U.S. EPA, Report to Congress, "Management of Wastes from the Exploration, Development and
       Production of Crude Oil, Natural Gas, and Geothermal Energy," Volume 1, EPA/530-SW-88-
       003, December 1987.  (Offshore Rulemaking Record Volume 119)

19.    Hudgins, Charles M., Jr., "Chemical Treatments and Usage in Offshore Oil and Gas Production
       Systems,"  Prepared for American Petroleum Institute, Offshore Effluent Guidelines Steering
       Committee, September, 1989.  (Offshore Rulemaking Record Volume 145)

20.    Acosta, Dan, "Special Completion Fluids Outperform Drilling Muds,"  Oil and Gas Journal,
       March 2, 1981. (Offshore Rulemaking Record Volume 25)

21.    American Petroleum Institute, "Exploration and Production Industry Associated Wastes Report,"
       Washington, D.C., May 1988.

22.    Parker, M.E.,  "Completion, Workover, and Well  Treatment Fluids," June 29, 1989. (Offshore
       Rulemaking Record Volume 116)

23.    Kaplan, Maureen, ERG, Memorandum to Neil  Patel, EPA,  regarding "Multi-Well Platforms -
       ERG Definition and Survey Results," February  2, 1994.

24.    Jones, Anne, ERG, Memorandum to Neil Patel, EPA regarding "Estimates for total numbers of
       coastal wells, operators, and production," September 26, 1994.

25.    Mclntyre, Jamie, SAIC, Memorandum to Allison Wiedeman, U.S. EPA, regarding LADEQ and
       TRC coastal discharge data with attachments, December 30, 1994.

26.    Stralka, Kathleen, SAIC, Requested Quick Response Estimates from the Coastal Oil and Gas
       Survey, July 12, 1994.

27.    Wiedeman, Allison, U.S. EPA, Memo to file regarding coastal oil and gas activity hi CA, AL,
       MS, and FL, September 6, 1994.

28.    Wiedeman, Allison, U.S. EPA, "Report to Alaska - Cook Inlet and North Slope Oil and Gas
       Facilities, August 25-29, 1993," August 31, 1994.

29.    Hanchera, Dan,  Marathon  Oil Company,  Letter to Manuela Erickson,  SAIC, regarding
       production activity information for platforms hi Cook Inlet, April 12, 1994.

30.    SAIC, "Oil and Gas Exploration and Production Wastes Handling Methods in Coastal Alaska,"
       January 6, 1995.
                                          IV-32

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31.    Erickson, Manuela, SAIC, Telephone conversation with Janet Platt, BPX, North Slope, Alaska
       regarding BP's plans for new production fluid gathering centers on the North Slope, August 11,
       1994.

32.    Henderson, Scott,  SAIC, Memorandum to John Sunda,  SAIC, regarding "Estimates from
       Questions All, A13, and A14 of the Coastal Oil and Gas Questionnaire," August 22, 1994.

33.    Wiedeman, Allison, U.S. EPA, Telephone conversation with Walter Boone, Mississippi State Oil
       and Gas Board, March 30, 1994.

34.    Wiedeman, Allison, U.S. EPA, Telephone conversation with Dave Bolin, Alabama Oil and Gas
       Board, April 6, 1994.

35.    Wiedeman, Allison, U.S. EPA, Telephone Conversation with Dave Bolin, Alabama Oil and Gas
       Board, May 17, 1994.

36.    Wiedeman, Allison, U.S. EPA, Telephone conversation with Charles Tootle, Florida Department
       of Natural Resources, March 29, 1994.

37.    Wiedeman, Allison, U.S.  EPA, Telephone Conversation with Kathy Lehman, Environmental
       Compliance Specialist, THUMS, April 29, 1994.

38.    Erickson, Manuela, SAIC, Personal communication with L.  Litzen, Shell Western, E & P, Inc.,
       regarding production platforms hi Cook Inlet, April 18, 1994.

39.    Marathon Oil Co. and Unocal Corp., "Drilling Waste Disposal Alternatives - A Cook Inlet
       Perspective, Cook Inlet, Alaska," March 1994.

40.    Safavi, Behzad, SAIC, Memorandum to the Confidential Business Information (CBI) Record
       regarding "CBI Supporting Documents Used in the Compliance Costs and Pollutant Removals
       Development  for Disposal of Drilling  Wasted hi Cook Inlet,  Alaska,  Coastal Oil  and Gas
       Operations,"  January 30, 1995.  (Confidential Business Information)

41.    Jones,  Anne,  ERG, Memorandum to Allison Wiedeman, U.S. EPA, regarding "Future well-
       drilling estimates," November 21,  1994.

42.    Wiedeman, Allison, U.S.  EPA, Communication with Jim  Short, ARCO, regarding  status of
       ARCO's Sunfish operations hi Cook Inlet, Alaska, May 9,  1994.

43.    Erickson, Manuela, SAIC, Facsimile to Allison Wiedeman, U.S. EPA, regarding Seven-Year
       Projected Drilling for North Slope, with attachments. January 24, 1995.
                                           IV-33

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                                       SECTION V
                    DATA AND INFORMATION  GATHERING
1.0   INTRODUCTION
       The major  studies  presenting information on coastal  oil and  gas  effluents  and treatment
technologies EPA used to develop this proposed rule are summarized in the following sections. These
include: an investigation of the underground injection of produced water and associated produced water
treatment technologies; an investigation of solids control technologies for drilling fluids; an investigation
of the drilling fluids and cuttings waste generation, treatment, and disposal in coastal Alaska; and an
investigation of commercial non-hazardous oil and gas waste disposal facilities and technologies.  In
addition, a comprehensive Clean Water Act Section 308 Questionnaire of the industry was conducted to
gather information to help characterize the coastal oil and gas subcategory.   The questionnaire and a
summary of results are described in this section.  A listing is included of certain data obtained hi previous
studies, and used in the coastal proposed rulemakhig, conducted during the development of the  offshore
subcategory effluent guidelines development.
2.0   INFORMATION TRANSFERRED FROM THE OFFSHORE  RULE
       Due to the similarities in the technologies employed and wastes generated by the offshore and
coastal subcategories of the oil and gas industry, certain data generated during the offshore rulemaking
effort have been utilized in the development of this proposed rule where appropriate.  Those data most
influential in the development of this rule, listed below, are described in more detail in the Offshore
Development Document  and will not be discussed further in this section.1
       Produced Water Characteristics for Cook Inlet
              The produced water characteristics for Cook Inlet were used as BPT-level effluent for
              calculating the pollutant reductions and the BCT cost test for the gas flotation and zero
              discharge options for Cook Inlet discharges.  The data used included flow-weighted
              averages of the organics and zinc data in the Envirosphere report2, BPT level effluent
              concentrations from the Gulf of Mexico  data cited in Table XII-15 of the Offshore
              Development Document (where  Cook Inlet data were missing  for certain pollutant
              parameters, as discussed in Section VIII of  this document), and radium data from the
              Alaska Oil and Gas Associations Comments  submitted in response to the offshore rule,
              56 FR 10664 March 13, 1991 and 56 PR 14049 April 5, 1991.3
                                            V-l

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Produced Water Characteristics for Effluent from Improved Gas Flotation

       The produced water characteristics for effluent from improved gas flotation were used
       in the development of pollutant loadings reductions for produced water for coastal options
       that used the technology and for the BCT costs  test.   In  addition,  for  options that
       included commingling miscellaneous wastes with produced water, the data were used to
       estimate the pollutant reductions for these wastes  using improved  gas  flotation  as
       described hi Section VHI.  These data were reported in Table XII-15 of the Offshore
       Development Document.
Drilling Fluids and Cuttings Characteristics

       The concentrations  of organic pollutants in mineral oil were used  to  calculate the
       pollutant loadings in drilling fluids and cuttings.   The concentrations used were the
       averages of concentrations for three  types  of  mineral  oil presented  hi  the Offshore
       Development Document, Table VII-9.

       The barium concentration used to calculate the barium loading of the discharged drilling
       fluid was calculated from the total pounds of barite hi the drilling fluid.  Based on the
       information provided hi the Offshore Development Document, page XI-8, the barite was
       assumed to be pure barium sulfate (100% BaSO4) and the barium sulfate  was assumed
       to contain 58.8 percent (by weight) barium.

       For the BPT costs, the following information came from the offshore rulemaking effort:

              Oil content hi oil-based drilling fluids = 60% by volume (Offshore Table XI-3)
              Mineral oil substitution cost = $2.00/gal (Offshore Table XI-10)
              Drilling fluid disposal cost =  $26.99/bbl (Offshore Table XI-8)
              Cuttings disposal cost = $29.26/bbl (Offshore Table XI-8)
Deck Drainage Characteristics

       The deck drainage characteristics from offshore operations were used to estimate the
       character of discharged deck drainage from coastal operations in the development of
       pollutant loadings reductions for deck drainage control options and for the BCT cost test.
       The data used were  the  untreated  data  reported hi  Table X-17 of the Offshore
       Development Document.
Domestic Waste Characteristics

       The domestic waste characteristics from Section XVI  of the Offshore Development
       Document were incorporated into the descriptive portions of this document and were not
       used in any analyses.
                                      V-2

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       Sanitary Waste Characteristics

               The sanitary waste  characteristics  from Section XVH of the Offshore Development
               Document were incorporated into the descriptive portions of this document and were not
               used in any analyses.
•      Non-Water Quality Impacts

               The non-water quality impacts data were used to estimate the non-water quality impacts
               of this proposed regulation. This includes the estimation of increases in air pollution
               emissions and safety. The data used are a combination of information from the offshore
               rulemaking and supplemented with information from  sources described later in this
               section. The data from the offshore rulemaking effort and the supplemental sources are
               listed below:

                      Air emission factors (Table XWI-9 of the Offshore Development Document)
                      Equipment power and fuel requirements4
                      Equipment operating parameters4
                      Personnel casualty and injury data5


3.0   INDUSTRY  SURVEY

       A comprehensive questionnaire entitled the "1993 Coastal Oil and Gas 308 Questionnaire" was

developed under the authority of Section 308 of the CWA.  This  questionnaire was distributed to all
known coastal oil and gas operators  and requested economic data and information on oil  and gas waste
generated, and treatment disposal methods and disposal costs for these wastes.


       Prior to this, a draft of the questionnaire was reviewed by several industry trade associations,
comments were considered and incorporated where appropriate. A pre-test survey was then sent to seven
coastal operators in August 1992. After reviewing the pre-test results and consulting the operators, EPA
made significant changes and improvements in the survey.  In order to minimize the burden, the seven
operators were not included in the final survey.


       The 1993 Coastal Oil and Gas Questionnaire, hereafter referred to as the EPA Questionnaire, was
divided into four sections.  The first two sections requested information concerning the technical and
financial  contacts.  Section 3  requested technical operating information hi two parts: Section 3.1
"Production Operations," and Section 3.2 "Well Drilling Operations."  Section 4 "Finances" requested
financial information about the operator.
                                             V-3

-------
        Section 3.1 "Production Operations" requested detailed information on: production data, treatment
system  wastewater disposal,  outfall data, treatment  technologies, treatment costs,  injection  costs,
miscellaneous waste generation and disposal, miscellaneous waste disposal costs, and treatment chemical
usage.  Section 3.2 "Well Drilling Operations" requested detailed information on: type of well, well
depth, drilling costs, type of drilling used, solids  separation technologies, drilling fluid and cuttings
disposal, waste handling and disposal costs, miscellaneous waste generation and disposal, miscellaneous
waste disposal costs, reserve pit data, and drilling chemical usage.

        The survey was designed to cover three interrelated populations. Population is a statistical term
used to describe the set of all units of interest. The three populations are: (1) all operators of coastal oil
                   *
and gas extraction facilities , (2) all coastal oil and  gas wells, (3) all wastewater treatment facilities for
coastal oil and gas extraction.  There are two basic  methods for conducting a survey: one is to perform
a "census" which requests data on all identified units in a population, the second is to sample a  subset
of the population which is referred to as a "survey."  The EPA Questionnaire was sent  to all known
coastal operators (a census) but only requested information on some of their wells (a survey).

        EPA developed a list of coastal operators and their wells by combining information from several
sources.6  Three data sources were used to identify production wells and their locations.  One source was
the database maintained by the Petroleum Information Corporation.  The database contains information
on the wells completed or worked-over between 1980 and 1990.  The second source was Tobin Survey
Incorporated.  Tobin  compiles  information on wells by geographic location.  The third source was
information supplied by the Alaska Oil  and Gas Conservation Commission including wells that were
active hi 1991. As a result, the final list of operators to be surveyed contained 361 coastal operators and
3,623 wells.6

        The operators  were grouped into three categories;  majors, large independents,  and small
independents. The wells were grouped into those completed before and after 1990 and those located in
saline and freshwater environments.  Table V-l presents the breakdown of all 3,623 coastal wells into
the categories described above.  The survey was designed so that a census of all 361 operators (not
including the seven pretest operators) was conducted.  All operators were required to complete Section
4 "Finances." Information on all 3,623 wells was not requested.  The 327 wells surveyed in the pre-test
questionnaire were excluded from the survey.  For 179 wells where particular situations existed that were
limited in occurrence, EPA requested information  on all of these wells.  Such circumstances included
wells located hi marine wetlands (one well), wells located on platforms hi the Gulf of Mexico (35 wells),
                                               V-4

-------
                                         TABLE V-l
 TOTAL WELL COUNT SURVEYED FOR COASTAL OIL & GAS WELLS BY CATEGORY
Population
Alaska
Gulf
Major
Major
Sm. tad.
Other
ALL
Prior to 1990
fresh
640
496
95
902
2,133
Saline
282
119
26
355
782
Including 1990 ami After
Fresh
21
174
21
300
516
Saline
39
67
2
84
192
Total
Well
Count
982
856
144
1,641
3,623
Actual
Wells
Surveyed
100
133
143
227
603
and all wells owned by small independent operators (143 wells).  The remaining 3,177 wells were
surveyed using a stratified probability design (see Glossary), which established a representative well
population size to be 603 wells. Operators were instructed to provide technical information only on the
wells identified and the separation and treatment facility associated with each well.

       For Section 3.2 of the Questionnaire, entitled "Drilling Operations," EPA identified 191 wells
that had been newly drilled or worked-over during the period of 1990 through 1992.  Information on
drilling operations was requested for only those identified wells.  Of these, 167 were hi the Gulf of
Mexico and 24 were hi Alaska.  Data were received for 138 of the 191  wells surveyed for drilling
operations.'

       Of the 361 EPA Questionnaires that were sent out, 89 were out of scope because they were non-
coastal operators or out of business. Of the remaining 272 surveyed operators that were in scope, 236
responded in time (as of April 1994) to  be included hi the database used hi this proposal6.   It was
determined that these 236 respondents sufficiently represented industrial operations.

       Upon their return, the EPA Questionnaires were reviewed for completeness and technical content
and then were transcribed into a computer readable format using double key-entry procedures.  Statistical
estimates were prepared in order to extrapolate the results from the sampled wells and facilities to the
entire coastal industry.7
                                             V-5

-------
       The individual data and the statistical reports were then used in the determining waste volumes,
treatment and disposal methods and costs.  The survey results were also used to estimate future industrial
activity.

4.0   INVESTIGATION OF SOLIDS CONTROL TECHNOLOGIES
       FOR DRILLING FLUIDS
       In 1993, EPA collected samples and gathered technical data at three drilling operations in the
coastal region of Louisiana.  The purpose of this effort was to gather  operating and cost information
regarding closed-loop solids control technology at active oil and gas well drilling operations and to collect
samples of water generated from drilling waste dewatering operations.  Samples were analyzed for a
variety of analytes hi the categories of organic chemicals,  metals, conventional and non-conventional
pollutants, radionuclides, and toxicity.

       Three drilling operations were visited and samples were  collected during drilling of three
exploratory wells.  The three wells were:
               The Gap Energy well (Sweetlake Land & Oil No.l) hi Holmwood, spudded on May 24,
               1993;8
               The Arco well (Miami Corporation No. 1) on the Black Bayou Prospect in Cameron
               Parish, spudded on June 22, 1993 ;9 and
               The Unocal well (LA. FURS. C-16) at Freshwater Bayou hi Vermilion Parish, spudded
               on August 7, 1993.10
       The Gap and Arco wells were drilled using land-based rigs, while the Unocal well was drilled
using a posted-barge.  At the tune of the sampling visits, all three wells were being drilled using water-
base drilling fluids. However, for one well, oil-based fluids were used for the final section of the well.
Table V-2 presents summary information obtained regarding drilling of these three wells.

       Samples of dewatering centrifuge liquid were collected to determine the characteristics of this
process stream.  This process stream consisted mostly of the water phase of the drilling fluid.  This
dewatering effluent was not discharged at any of the sites visited. One solids control contractor suggested
that further treatment with activated carbon would be necessary hi order to meet applicable discharge
criteria.9
                                             V-6

-------
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       One set of grab samples was collected on two consecutive days from the liquid discharge from
the centrifuge processing the drilling fluids. The major difference between the solids control systems was
that both Gap and Arco were using chemical treatment of the centrifuge influent with coagulant and
polymer to enhance centrifugation during the time of sampling while Unocal was  not. The result was
that separation of the drilling fluid solids from the water was much more efficient at both the Gap and
Arco sites.  Both the Gap and Arco samples  were relatively free of suspended solids (TSS ranged from
24 to 520 mg/1) while the Unocal samples were analyzed as a solids sample with total solids ranging from
23% to 24.7% and had the consistency of a drilling fluid.

       The combination chemical treatment and centrifugation, referred to as "chemically enhanced
centrifugation", allows the water to be recycled back into the drilling fluid recirculation system without
the build up of fine drill cuttings that is detrimental to the drilling fluid.  This drilling technology is
discussed in greater detail hi Section VII.

       In addition to  the  sampling activities, technical and cost information was  collected on the
following topics:

       •      drilling waste volumes and disposal methods
       •      solids control equipment design and performance
       •      drilling fluids
       •      well design and construction
       •      drilling operations
       •  '    annular injection
       •      miscellaneous waste volumes and disposal methods.

       The results of this investigation were used to determine  methods and costs  of drilling waste
disposal, and to provide information on miscellaneous waste volume, treatment and disposal.

5.0   SAMPLING   VISITS  TO 10  GULF  OF  MEXICO  COASTAL  PRODUCTION
       FACILITIES
       From May 11  through November 13, 1992, EPA visited ten coastal oil and gas  production
facilities located in Texas and Louisiana.  The purpose of this effort was to gather operating and cost
information at active oil and gas production facilities and to collect  samples of  produced water and
associated wastes. Samples were analyzed for a variety of analytes in the categories of organic chemicals,
                                             V-8

-------
metals, conventional  and non-conventional pollutants, and radionuclides.  Sampling at each site was

conducted for one day over a span of eight hours.  Technical and cost data were collected in addition to

the production waste samples. Table V-3 presents the operator name, field name, and location of the  10

facilities.  A report was prepared, entitled "Coastal Oil and Gas Production Sampling Summary Report,"

that summarizes and describes the samples collected, treatment systems employed, and data generated.21


        Below is a brief summary of the facilities, the samples collected  and the types  of pollutants

analyzed in this  study.21


   •    Of the ten facilities sampled, six were in southeastern Louisiana and four were in southeastern
        Texas.

   •  '  Five were accessible by car and five were accessible by boat.

   •    One site operator was a small independent company, one was a medium size company, and eight
        were major companies.

   •    Four facilities produced only oil and six produced both oil and gas.

   •    Produced water flowrates ranged from 2,500 bpd to 11,500 bpd.

   •    Nine facilities utilized injection wells  for  produced water disposal  and  one utilized  surface
        discharge.

   •    Nine facilities utilized settling tanks as the primary step for removal of solids and trace quantities
        of oil from produced waters.

   •    One facility utilized a coalescer for removal of trace quantities of oil prior to settling.

   •    All of the four facilities that were accessible only by boat disposed  of produced water using
        injection wells and utilized filtration as a final  treatment step, between settling and injection.
        Three of these facilities used cartridge filters and one used a 200 mesh screen.

   •    Aqueous samples were collected from settling tank effluent at all ten facilities.

   •    Aqueous samples were collected at the influent (settling effluent) and effluent of all four filtration
        systems.

   •    Aqueous samples were also collected at the influent and effluent of the coalescer,  although the
        effluent samples were analyzed only for oil and grease and TSS.

   •    Two  consecutive  four-hour grab  composite samples were collected at  all aqueous  sample
        locations.  Each four-hour aqueous composite was analyzed  for the following analytes:

                  Volatile Organics
                  Semi-volatile Organics
                                              V-9

-------
                                  TABLE V-3
                    PRODUCTION FACILITIES SAMPLED
Operator Name
Greenhill Petroleum
Oryx Energy
Exxon Corporation
Oryx Energy
Texaco
Texaco
Arco
Texaco
Badger Oil Corporation
Texaco
Field Name
Bully Camp
Chacahoula
Clam Lake
Caplen
Sour Lake
Port Neches
Bayou Sale
Bayou Sale
Larose
Lake Salvador
Location
La Fourche Parish, LA
La Fourche Parish, LA
Jefferson County, TX
Galveston County, TX
Hardin County, TX
Orange County, TX
St. Mary Parish, LA
St. Mary Parish, LA
La Fourche Parish, LA
St. Charles Parish, LA
Reference
11
12
13
14
15
16
17
18
19
20
           Metals
           Conventional Parameters
           Non-conventional Parameters
           Radionuclides.

Four   consecutive  two-hour  grab  composite   samples   were  also  collected   at   all
aqueous sample locations.  Each two hour composite was analyzed for the following:

           Oil and Grease
       -    TSS.

Samples of cartridge filters were collected at all three facilities that utilized them.  The samples
were analyzed for radionuclides only.

A grab sample of settling tank bottoms was collected at four facilities.  Due to limited quantities
available at two of these facilities, one of these samples was analyzed for radionuclides only and
the other sample was analyzed for radionuclides and metals only.

A grab sample of material that was cleaned out of a heater-treater (mostly sand and some oil) was
collected at one facility.

The remaining two settling tank bottoms samples and the heater-treater sample were analyzed for
the following analytes:

           Volatile Organics
           Semi-volatile Organics
           Metals
                                     V-10

-------
                  Conventional Parameter
                  Non-conventional Parameters
                  Radionuclides.
       One grab sample of coalescer tank bottoms was collected, and since the solids were dilute, the
       sample was analyzed as a liquid (aqueous) sample.
       One sample of sand generated during the workover of an oil producing well was collected and
       analyzed for radionuclides only.
       Figure V-l presents the location of the waste samples collected and also presents the five different
treatment and disposal sequences observed at the 10 facilities.

       In addition to  the  sampling activities, technical  and cost  information was collected on the
following topics:

       •     separator and treatment system technologies and configuration
       •     equipment space requirements
       •     support structures
       •     miscellaneous waste volumes  treatment and disposal methods
       •     produced water volumes and disposal methods
       •     energy requirements
       •     injection well remedial work requirements
       •     ancillary equipment requirements (besides the injection well) for injection
       •     injection well design and operation
       •     production data.

       The results from this study, together with data from the EPA Questionnaire, formed the basis for
EPA's produced water treatment and disposal cost analyses discussed later in Section XI. The analytical
data was used to characterize produced water effluent characteristics from BPT treatment system.

6.0   STATE DISCHARGE MONITORING REPORTS
       EPA was able to obtain detailed information on produced water discharges, for operators hi Texas
and Louisiana, by reviewing state discharge permits.  The  Louisiana Department of Environmental
Quality (LADEQ) and the Texas Railroad Commission (TRC) supplied state permit data for all known
dischargers in the coastal areas.22  The state permit  information identifies the operator, the name of the
                                             V-ll

-------










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V-12

-------
producing field, the location of the production facility, the volume of produced water discharged, the
location and permit number of the outfall, and in Louisiana only, the compliance date by which the
discharge must cease. From these data, EPA estimated that 216 production facilities in both the Texas
and Louisiana coastal region will be discharging after July 1996 (the date of issuance of this regulation).
The list of these facilities is presented in Appendix XI-3.  A separate document provides a description
of the methodology used to complete this list.22

7.0   COMMERCIAL  DISPOSAL OPERATIONS
7.1    COMMERCIAL DRILLING WASTE DISPOSAL SITE VISIT
       In May 1992, EPA visited two non hazardous oil and gas waste land treatment facilities at Bourg
and Bateman Island, Louisiana and also two waste transfer stations at Port Fourchon and Morgan City
on Bayou Boeuf, Louisiana.  Campbell Wells is the operator of these four facilities. The purpose of these
visits was to investigate the transportation, handling, disposal methods employed and associated costs of
these operations.  Detailed information was gathered concerning the operation of the landfarm treatment
process used for the disposal of non-hazardous oil field  wastes, transportation equipment,  transfer
equipment, equipment fuel requirements and costs incurred by the facilities and costs  charged to the
customers.   This information was summarized  in the "Trip Report to Campbell Wells Landfarms and
Transfer Stations in Louisiana.ll23  The information was  used in the development of compliance costs and
the non-water quality impacts for the various regulatory options being considered.

7.2    SAMPLING VISITS TO Two COMMERCIAL PRODUCED WATER  INJECTION FACILITIES
       On March 12, 1992,  the EPA visited two commercial produced water injection facilities to collect
samples and technical data.24'25  The purpose of the visits was to collect information regarding costs of
produced water disposal and other operating costs as well as to collect samples of produced water, filter
solids, used filters and tank bottoms solids for radioactivity analysis.  The two facilities were Campbell
Wells in Bourg, Louisiana and Houma Saltwater in Houma, Louisiana. Both facilities received produced
water mostly by truck but also had the capability to  receive produced water by barge.  Both facilities
utilized sedimentation and filtration as treatment processes for produced water followed by to underground
injection.  The filtration systems differed slightly in that Houma Saltwater used bag and cartridge filters
in series while Campbell Wells (Bourg) used only bag filters.  At  the Campbell Wells (Bourg) facility,
water from the landfarming operation was combined with produced water received from offsite prior to
treatment and injection.
                                             V-13

-------
       At both facilities, samples of produced water from the influent and effluent of the filtration system
were collected as well as solids from the bag filters, settling tank bottoms and at Houma Saltwater, a used
cartridge filter.  These samples were then analyzed for Ra-226, Ra-228, Gross Alpha, and Gross Beta.
The technical information gathered at these sites was used in developing compliance costs and the non-
water quality impacts for the various regulatory options being considered.  The results of the radio-
activity analyses were used in an evaluation of radioactivity concentrations in oil and gas wastes.  This
evaluation is described below.

8.0   NORM STUDY
       EPA reviewed all known data regarding the presence of naturally occurring radioactive materials
(NORM) found in discharges of produced water and associated with scales and sludges (produced sand)
generated by production equipment from this industry.  The oil and gas production process can extract
naturally occurring radionuclides from within the geologic formation.  The most common of these
radionuclides found are radium-226, radium-228, and lead-210, which are soluble hi the produced water.
Radium-226 and radium-228 concentrations in ocean water may range from 0.024 to 0.182 pCi/1 and
0.0001 to 0.1 pCi/1, respectively.26

       An EPA report27, summarizes produced water radioactivity data from the 22 available studies
EPA has reviewed, focusing on  data from coastal sites.  Each of these 22 studies is summarized in that
report according to the location of the sites, sampling plans, and analytical methods used to measure the
radionuclides.

       Tables V-4, V-5 and V-6 summarize the findings from this evaluation. This information was used
hi characterizing produced water effluents hi the Gulf Coast.

9.0   ALASKA OPERATIONS
9.1    REGION X DISCHARGE MONITORING STUDY
       In an effort to characterize discharges to Cook Inlet, EPA Region X conducted a comprehensive
Discharge Monitoring Study  of facilities that discharge produced water.2  Produced water discharges
from production facilities were sampled and analyzed for one year, from September 1988 through August
1989.  Samples were collected and analyzed from two oil platforms, one natural gas platform and three
shore-based treatment facilities, all of which discharge produced water to Cook Inlet.  The results of this
sampling effort are summarized in Table XTI-15 in the Offshore Development Document1 and are used
                                            V-14

-------
                                             TABLE V-4
                       SUMMARY STATISTICS OF RADIUM-226 (pCi/1)
                           FROM COASTAL OIL AND GAS SITES27
Study
i
2
3
6
7
8
9
10
11
16
17
20
21
22
Total
Source
Formation Water
Untreated Effluent
Acidified/Filtered Effluent
Acidified/Unfiltered Effluent
Produced Water (all sample pts)
Produced Water Effluent
«
Produced Water Effluent
(all methods)"
Produced Water Effluent
(Method 707E only)b
Produced Water Effluent
Produced Water Effluent?
Produced Water Effluent
Produced Water Effluent
Produced Water Eff. (MOGA?
Produced Water Eff. (DEQ)b
Produced Water Eff. (CSA)
Produced Water Effluent
Produced Water Effluent
(commercial facilities)11
Produced Water Effluent
(production facilities)"
Production Equipment Scale*
Production Equipment Sludge"
Disposal Wastes'
Produced Water Effluent
Drilling Waste Effluent6
Produced Water Effluent
No. of
Sites
15
4
6
7
1
1
407
352
3
1
6
4
267
405
3
2
2
10



25
2
1128
Ho. of
Samples
15
4
6
7
14
4
407
352
6
4
8
4
267
405
3
2
2
20


.
25
4
1149
Mean
326.5
195.8
238.8
275.9
20.3
14.7
162.8
181.7
197.1
539.0
2.7
497.0
181.6
159.2
197.1
96.6
50.3"
172.19"
360.0r
56.0r
90.0r

2.6"
168.4'
Sto"

140.6
140.8
110.8
9.5
3.4
144.7
141.4
72.0
145.3
2.2
96.1


75.8
65.7
7.3"
55.1"




1.2"
.
Mia
<0.1"
22
16
46
10.6
10.6
0.05
0.1
86.8
448
1.1
355
0.05
0.05
110.6
50.1
33.9
4.5




1.3
0.05
Max
1580
327
393
397
42.4
18.5
930
930
258.3
756
4.2
567
792
930
251.9
143
66.2
420




5.1
930
' Detection limit is 0.1 dpm/1.
b Samples below the minimum level of detection are set equal to the detection limit.
c Four samples analyzed by four different analytical methods.
" From SA1C, January 31, 199S7
' Combination of coastal, offshore, and onshore sites.
' Units are pCi/g for these samples.
* Mean is weighted average of means from each study of produced water effluent.
                                                 V-15

-------
                                              TABLE V-5
                       SUMMARY STATISTICS OF RADIUM-228 (pCi/1)
                            FROM COASTAL OIL AND GAS SITES27
Study
1
3
6
7
8
9
11
16
17
20
22
Total
Source ;
Formation Water
Produced Water (all sample pts)
Produced Water Effluent
Produced Water Effluent1
Produced Water Effluent
Produced Water Effluent
Produced Water Effluent
Produced Water Eff. (MOGA)'
Produced Water Eff. (DEQ)"
Produced Water Eff. (CSA)
Produced Water Effluent
Produced Water Effluent
(commercial facilities)*
Produced Water Effluent
(production facilities)1
Production Equipment Scaled
Production Equipment Sludge*
Disposal Wastes'1
Drilling Waste Effluent"
Produced Water Effluent
No. of :
Sites
15
1
1
407
3
1
6
267
405
3
2
2
10
.
.

2
1107
No. of
Samples :
15
14
4
407
6
1
8
267
405
3
2
2
20
.
.

4
1125
Mean i
.
24.0
17.5
184.5
294.1
460.0
7.5
219.7
164.5
294.1
98.6
34.9°
228.4g
120.0"
19.0"
30.0"
7.3°
168.4s
Std
.
11.6
5.8
375.9
69.4
.
3.1
.
.
77.2
71.3
4.0°
49.4
.
.
.
2.4C
•
Min
18.7
11.2
11.2
0"
233.6
.
5.3
0"
0"
244.4
48.2
17.5
3.1

.
.
5.7
0
Max
1248
54.5
24.9
7090
386
.
9.7
928
928
383.0
149
49.0
500
.
.
.
10.5
7090
* Samples below the minimum level of detection are set equal to the detection limit.
* One sample was reported with a detection limit of 0 pCi/1.
c Mean is arithmetic average of facility means; Standard deviation is pooled within-facility estimate.
* Combination of coastal, offshore, and onshore sites.
* Units are Pci/g for these samples.
' Mean is weighted average of means from each study of produced water effluent.
' from SAIC, January 31,19957
                                                   V-16

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                                          TABLE V-6
                       SUMMARY STATISTICS OF LEAD-210 (pCi/1)
                           FROM COASTAL OIL AND GAS SITES
Study
3
17
20
22
Total
Source
Produced Water (all sample pts)a
Produced Water Effluent3
Produced Water Effluent
(commercial facilities)2
Produced Water Effluent
(production facilities)3
Production Equipment Scale0
Production Equipment Sludge0
Disposal Wastes0
Centrifuge Effluent3
Produced Water Effluent
No. of
Sites
1
1
2
10
.


2
1128
No. of
Samples
14
4
2
20
.

.
4
1149
Mean
7.1
7.1
47.4
75.2b
360.0"
56.01
90.0"
12. ld
168.4s
Std
0.5
0.4
0.9
27.4"



5.6
.
Mia
6.4
6.5
42.5
40.1

.

7.0
0.05
Max
8.0
7.5
50.5
221.0
.
.

19.0
930
 * Samples below the minimum level of detection are set equal to the detection limit.
 6 Mean is arithmetic average of facility means; Standard deviation is pooled within-facility estimate.
 c Combination of coastal, offshore, and onshore sites.
 4 Units are pCi/g for these samples.
in the coastal rulemaking to characterize Cook Inlet BPT produced water discharges.

9.2    EPA SITE VISITS AND INFORMATION GATHERING EFFORTS
        In 1993, EPA embarked on a fact-finding mission regarding drilling and production operations
and practices in both regions of Alaska, Cook Inlet and the North Slope.  Information and data were
obtained by direct visits to these areas, and by contacting the Alaska Oil and Gas Association (AOGA),
state regulatory authorities, and individual operators.  The EPA findings from the site visits are presented
in a report on Cook Inlet and North Slope oil and gas facilities.2*

        AOGA and individual operators submitted, upon request from EPA, information on projects and
technologies currently being developed and used in Cook Inlet and on the North Slope to handle drilling
and production wastes, and the costs associated with these projects. The information regarding waste
handling methods and technologies was incorporated into a report prepared for EPA.29   This report, hi
addition to the  climate conditions and current state and Region X regulatory requirements, reviews all
                                              V-17

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past and current exploration and production waste handling methods in both Cook Inlet and on the North
Slope.

        The following sections summarize the information EPA has obtained through these efforts.

9.2.1   Drilling Operations on the North Slope
        In their effort to achieve zero discharge, operators of oil and gas exploration facilities on the
North Slope have developed a grinding and injection system for  drilling fluids and cuttings  as  an
alternative to land disposal.  The grinding and injection system is a result of many years of investigation
of technologies that can achieve zero, discharge of drilling wastes.

        As part of this program, operators investigated methods to reduce the volume of drilling fluids
and cuttings that would require disposal.  One such waste reduction method involved the separation of
the surface cuttings from the drilling fluid, washing  of the cuttings, and determining their potential reuse
as construction material.  Surface cuttings (cuttings generated from the first 3500 feet of drilled depth)
account for approximately 50% of the total cuttings volume.  On the North Slope, these cuttings are very
similar to sand and gravel from the local pit mines  which  are used as construction material.29

        The drill cuttings reclamation program established the potential of surface cuttings reclamation
and reuse as construction gravel material.  The next step in this program was to establish the technical
achievability and costs  of winterized, mobile cuttings processing units.  In general, the study of the
cuttings processing units consisted of processing surface hole cuttings through two separate, mobile, and
winterized units.  Processed sands and  gravel were collected and  analyzed at  specific intervals to
determine their reuse potential as construction materials.   Coarse materials were  recovered for reuse,
while fines and fluids were disposed by means of annular injection below the permafrost.

        As a result of this program, successful implementation of the use of grinding and injection for
drilling fluids and cuttings disposal  on the North Slope has been occurring for the past several years.
Wastes are injected beneath the permafrost either through the annulus of an existing well or through a
Class II disposal well.28
                                              V-18

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9.2.2   Production Operations on the North Slope
       All production waste handling methods on the North Slope are currently regulated by state
agencies.  Produced water, workover/treatment/completion (WTC) fluids, deck drainage, and produced
sand are not discharged from the North Slope coastal facilities including Endicott Island.  Only domestic
and sanitary wastes may be.discharged on the North Slope, after treatment.  Produced water is injected
for waterflooding and for disposal into Class II injection wells.28

9.2.3   Drilling Operations in Cook Inlet
       Marathon Oil Co. and Unocal Corp. recently submitted to EPA a report on drilling waste disposal
alternatives and their implementation costs based on projected drilling schedules.30  Three alternatives
were investigated in terms of technological achievability and costs: discharge to Cook Inlet, land-based
disposal, and disposal by injection.

       EPA evaluated the information presented in this report and utilized the relevant information in
the development of regulatory options for drilling wastes in Cook Inlet.   Costing information was used
to estimate the regulatory compliance costs.

9.2.4   Production Operations in Cook inlet
       Marathon Oil Co. and Unocal Corp. recently submitted to EPA a report on the technological and
economic feasibility  of  zero discharge of produced  water from the Trading Bay  onshore treatment
facility.31  This  report presented the costs and technological achievability for  three produced water
injection alternatives.

       EPA evaluated the information presented in this report and utilized the relevant information in
the development of the zero discharge option for produced water in Cook Inlet by  injection.  Costing
information was used to estimate the regulatory compliance costs.

10.0  REGION X DRILLING FLUID TOXICITY DATA STUDY
       In order to determine the appropriate toxicity level for a more stringent toxicity option for drilling
fluids and cuttings, EPA attempted to evaluate effluent toxicity test results for Cook  Inlet drilling fluids
and cutting discharges.32 EPA reviewed permit compliance monitoring records, from EPA's Region 10,
containing 161 sets of results for toxicity testing of drilling fluids and drill cuttings  used in the Alaska
                                             V-19

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offshore and coastal regions between 1985 and 1994.  (The measure of toxicity is a 96 hour test that
estimates the concentration of drilling fluids suspended paniculate phase (SPP) that is lethal to 50 percent
of the test organisms.) The records were summarized into a database which was evaluated on the basis
of the toxicity of drilling fluids and drill cuttings used in Alaska as a whole and Cook Inlet in particular.
After sorting the database to eliminate inadequate data,  such as drilling fluids contaminated by pills and
incomplete toxicity tests, 104 sets of results were retained for all of Alaska, with 59 of these from Cook
Met.

        Of the Cook Inlet bioassay test results, 83 percent were less toxic than  100,000 ppm (SPP); 60
percent were less toxic than 500,000 ppm; and one percent exhibited no toxic effect (i.e..  1 million ppm
or greater with  less than 50 percent mortality of the test organism).  (Note that  toxicity is  inversely
related to the 96-hour bioassay results so as the values cited above increase, toxicity decreases).

        These evaluations utilized an available database obtained from EPA's Region 10, which provides
an account of the relationship between toxicity and drilling fluids  currently being discharged.   The
toxicity values are identified in the available database by operator, permit number,  well name,  date and
base fluids system (mud). In addition, some  of the values are related to an identified volume of muds
discharged.  However, many of the values in the summary do not have either a volume identified or
whether the drilling fluids were discharged. This available  database is presently being updated as EPA
continues to identify the volume of drilling wastes having been discharged in Cook Inlet related to specific
toxicity test results.

11.0   CALIFORNIA OPERATIONS
        EPA visited coastal oil and gas operations  in Long Beach Harbor, California hi February of
1992.33  Four man-made islands have been constructed in  the Harbor for the purpose of oil and gas
extraction, and the facilities on these islands are operated by THUMS.  EPA met with state regulatory
officials and was given a tour of one of the islands by THUMS personnel. Both drilling and production
were occurring at the time of the visit.

        Information regarding waste generation, treatment, disposal, and  costs were obtained during the
visit. The information provided EPA with specific waste disposal technology and cost information which
has, where appropriate, been incorporated into cost analyses, and enabled  EPA to characterize California
coastal oil and gas operations.
                                              V-20

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12.0  OSW SAMPLING PROGRAM
       EPA's Office of Solid Waste conducted a sampling program of various oil and gas wastes in
j 992 34,35 As part of tm-g effor^ samples were obtained for completion, workover, and treatment fluids.
EPA has used this database to characterize the effluent for these fluids.  Treatment, workover and
completion fluids were collected from operations in Texas, New Mexico, and Oklahoma.  The samples
were analyzed for conventional, nonconventional and priority pollutants.
13.0  ESTIMATION OF INNER BOUNDARY OF THE TERRITORIAL SEAS
       EPA specifically estimated the location of the outer boundary of the coastal subcategory (which
is the inner boundary of the Territorial Seas)36 by estimating the latitude  and longitude coordinates
covering that part of the inner boundary of the Territorial Seas along Alaska's North Slope and Cook
Inlet, Texas, Louisiana, Alabama, and Southern California.

       Much of this boundary has been delineated on nautical charts published by the National Ocean
Service of the National Oceanic and Atmospheric Administration (NOAA). In some locations, however,
this boundary has not previously been delineated by NOAA, and EPA completed the coordinates using
established procedures described in  the Convention of the Territorial Seas and the Contiguous Zone,
Articles 3-13.  This boundary was used by EPA to determine the number of coastal oil and gas wells that
exist in this subcategory.
                                           V-21

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REFERENCES

1.     U.S.  EPA.  Development Document for Effluent Limitations Guidelines  and New Source
       Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source
       Category, Final. January 1993.

2.     Envirosphere Co., "Summary Report: Cook Inlet Discharge Monitoring Study: Produced Water,
       Discharges 016", prepared for Anchorage Alaska Offices of Amoco Production Company, ARCO
       Alaska, Inc, Marathon Oil Co., Phillips Petroleum Co., Shell Western E&P, Inc., Unocal Corp.,
       and U.S. Environmental Protection Agency, Region 10, August 1989.

3.     AOGA (Alaska Oil and Gas Association).  "Alaska Oil and Gas Association Comments on U.S.
       Environmental Protection Agency 40 CFR 435 Oil  and Gas Extraction Point Source Category,
       Offshore, Subcategory; Effluent Limitations Guidelines and New Source Performance Standards;
       Proposed Rule (56 FR  10664, Mar. 13,  1991 and 14049, April 5, 1991)." May 13, 1991.

4.     U.S. EPA, Engineering  and Analysis Division, "Non-Water  Quality Environmental Impacts
       Resulting from the Onshore Disposal of Drilling Fluids and Drill Cuttings from Offshore Oil and
       Gas Drilling Activities."  January 13, 1993.

5.     SAIC, "Evaluation of Personnel Injury/Casualty Data Associated with Drilling Activity for the
       Offshore Oil and Gas Industry," prepared  for Engineering  and Analysis Division,  U.S.
       Environmental Protection Agency, Jan. 11, 1993  (Offshore Rulemaking Record Volume 156)

6.     Murphy,  Matt. ERG.  Memorandum to Allison Wiedeman (U.S. EPA) regarding the Status
       Report for the Section 308 Coastal Oil and Gas Questionnaire. September 8,  1994.

7.     SAIC. Statistical Analysis of the Coastal Oil and Gas Questionnaire. January 31, 1995.

8.     U.S. EPA. Sampling Trip Report to GAP Energy Drill Site, Holmwood, Louisiana. June 16-17,
       1993. June 8, 1994.

9.     U.S. EPA. Sampling Trip Report to ARCO Oil and Gas Drill Site, Black Bayou Field, Sabine
       Wildlife Refuge, Lake Charles, Louisiana. July 21-22,  1993. October 21, 1994.

10.    U.S. EPA. Trip Report to Unocal, Intracoastal City, Louisiana, September 8-9, 1993. January
       25, 1995.

11.    U.S. EPA. Trip Report:  Greenhill Petroleum Corporation, Bully Camp Field,  La Fourche
       Parish, Louisiana. February 9, 1993.

12.    U.S. EPA. Trip Report: Oryx Energy Company, Chacahoula Field - DS&B Lease, Chacahoula,
       Louisiana. March 23, 1993.

13.    U.S. EPA. Trip Report:  Exxon Corporation, Clam Lake, Texas. September 15,1993.

14.    U.S. EPA. Trip Report:  Oryx Energy Company, Caplen, Texas. September 15, 1993.

15.    U.S. EPA. Trip Report:  Texaco, Inc., Sour Lake,  Texas. September 15, 1993.
                                           V-22

-------
16.    U.S. EPA. Trip Report:  Texaco, Inc., Port Neches, Texas. September 15, 1993.

17.    U.S. EPA. Trip Report:  Arco, Bayou Sale Field, Louisiana. June 15, 1993.

18.    U.S. EPA. Trip Report:  Texaco, Inc., Bayou Sale Field, Louisiana. June 29, 1993.

19.    U.S. EPA. Trip Report:  Badger Oil Corporation, Larose, Louisiana. July 20, 1993.

20.    U.S. EPA. Trip Report:  Texaco, Inc., Salvador Lake, Texas. July 15,  1993.

21.    U.S. EPA. Coastal Oil and Gas Production Sampling Summary Report. Draft Report. April 30,
       1993.

22.    Mclntyre, Jamie. SAIC. Memorandum to Allison Wiedeman, U.S. EPA, regarding Compilation
       of Discharge Monitoring Report Data from Louisiana Department of  Environmental Quality
       (LADEQ) and Texas Railroad Commission (TXRRC). December 30,  1994.

23.    U.S. EPA.  "Trip Report to Campbell Wells Landfarms and Transfer Stations in Louisiana,
       May 12 and  13, 1992." June 30, 1992.

24.    U.S. EPA. Trip Report to Houma Saltwater  in Louisiana. March 12,  1992. May 29, 1992.

25.    U.S. EPA. Trip Report to Campbell Wells Land Treatment,  Bourg, Louisiana. March 12, 1992.
       May 29, 1992.

26.    Hamilton, Meinhold,  and Nagy.  Produced Water Radionuclide Hazard/Risk Assessment.
       Prepared for the American Petroleum Institute. June 1991.

27.    SAIC,  "Summary of Radioactivity Studies for the  Coastal Oil & Gas  Subcategory," December
       9, 1994.

28.    Wiedeman, Allison. EPA. "Report to Alaska Cook Inlet and North Slope Oil and  Gas Facilities -
       August 25-29, 1993," August 31, 1994.

29.    SAIC.  "Oil and Gas Exploration and Production Wastes Handling Methods In Coastal Alaska,"
       prepared for EPA, Final, January 6, 1995.

30.    Marathon Oil Co. and Unocal Corp., "Drilling Waste Disposal Alternatives, A Cook Inlet
       Perspective", Cook Inlet, Alaska, March  1994.

31.    Marathon Oil Co.  and Unocal Corp., "Zero  Discharge Analysis,  Trading Bay  Production
       Facility", Cook Inlet Alaska, March 1994.

32.    SAIC, "Statistical Analysis of Permit Compliance Monitoring Records for the Toxicity of Drilling
       Fluids in Alaska (EPA Region 10)," December 9,  1994.

33.    SAIC,  "Oil & Gas Point Source Category: Trip Report of the U.S. EPA's Visit  to the THUMS
       Island Grissom Facility on February 7, 1992," July 16,  1992.
                                           V-23

-------
34.    Straus, Matthew A., Director, Waste Management Division, EPA Office of Solid Waste,
       Memorandum to Thomas P. O'Farrell, Director Engineering and Analysis Division, EPA Office
       of Water, regarding "Use of OSW Oil and Gas Exploration and Production Associated Waste
       Sampling and Analytical Data," October 4, 1994.

35.    Souders, Steve, EPA Office of Solid Waste, Memorandum to Allison Wiedeman, EPA Office of
       Water  regarding "1992 OSW Oil and Gas Exploration and Production Associated Wastes
       Sampling - Facility Trip Reports," October 27, 1994.

36.    Avanti, "Delineation of the Seaward Boundary of the Coastal Subcategory of the Oil  and Gas
       Extraction Industry," May 3, 1993.
                                           V-24

-------
                                      SECTION VI
                  SELECTION  OF POLLUTANT PARAMETERS
1.0   INTRODUCTION
       This section presents information concerning the selection of the pollutants to be limited for the
proposed Coastal Oil and Gas Extraction Effluent Limitations Guidelines and Standards.  The discussion
is presented by wastestream.

2.0   DRILLING FLUIDS AND DRILL CUTTINGS
       In the coastal subcategory, EPA is proposing to establish BAT, NSPS, and pretreatment standards
that would require zero discharge of drilling fluids and drill cuttings. Where zero discharge is required,
EPA would be controlling all pollutants in the wastestream.

       EPA is also co-proposing as alternative BAT limits applicable only to Cook Inlet, that in addition
to the BPT requirement prohibiting the discharge of free oil and diesel oil, and limiting the cadmium and
mercury content in stock barite, and limiting toxicity to 30,000 ppm (SPP), another option would enforce
these  same  requirements except with a more stringent toxicity limit of between 100,000 and 1 million
ppm (SPP).

       EPA is proposing to establish BCT limitations for drill fluids and drill cuttings that would prohibit
discharge of free oil (using the static sheen test) for Cook Inlet,  and would require  zero discharge
everywhere else.

       The toxic metals identified in drilling fluids and cuttings include zinc, beryllium, cadmium,
chromium,  copper, nickel, lead,  mercury, silver, arsenic, selenium,  and antimony.   Toxic organic
compounds in drilling fluids and cuttings include naphthalene, fluorene, and phenanthrene. Also included
are the alkylated forms of the toxic organics along with total oil, TSS and  other metals including iron,
tin, and titanium.  The pollutant data is summarized in Section VII of this document. A zero discharge
requirement would control all of these pollutants.
                                            VI-1

-------
        EPA's alternative BAT options would allow discharges of drilling fluids and drill cuttings in Cook
Inlet, with certain limitations, including either a prohibition on discharge of free oil, or in addition to the
free oil prohibition, prohibit the discharge diesel oil, and require limitations on toxicity and levels of
cadmium and mercury hi stock barite.  For either of these options, EPA would determine that it is not
technically feasible to regulate separately each toxic or nonconventional pollutant found in drilling fluids
and drill cuttings discharges. If EPA selected one of these alternative options, EPA would determine that
control of diesel oil and free oil would control toxic and nonconventional pollutants found  in these
discharges;  and thus,  diesel oil  and free  oil would  serve as indicator pollutants for these toxic and
nonconventional pollutants, including those that are not otherwise controlled by the diesel and free oil
prohibitions.  Finally, EPA would determine that controlling toxicity would indirectly control other toxic
pollutant metals.

        With respect to EPA's proposed BCT option prohibiting discharge of free oil, free oil would
serve as a surrogate pollutant for oil and grease in recognition of the complex nature of the oil present
in drilling fluids.

2.1    DIESEL OIL
        Diesel oil may contain 20 to 60 percent by volume poly aromatic hydrocarbons (PAH's) which
constitute most  of the toxic components of petroleum products. Diesel oil also contains a number of
nonconventional pollutants, including PAHs such as methylnaphthalene, methylphenanthrene, and other
alkylated forms  of the listed organic priority pollutants.  Prohibiting the discharge of diesel oil would
eliminate the discharge of the constituents  of diesel oil listed hi Table VI-1.

        The use of mineral oil instead of diesel oil as an additive in water-based drilling fluids would
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 (See Table VI-1).
Mineral oils contain lower concentrations of some of the same pollutants than diesel oil due to their lower
aromatic hydrocarbon content and lower toxicity.

2.2    FREE OIL
        The basis for a prohibition on discharges of free oil in drilling fluids and cuttings  is substitution
of water-based fluids for oil-based fluids, use of non-petroleum oil containing additives  and minimization
                                               VI-2

-------
                                            TABLE VI-1

                ORGANIC CONSTITUENTS OF DIESEL AND MINERAL OILS1
                            Concentration in mg/ml unless noted otherwise
Organic Constituents
Benzene
Ethylbenzene
Naphthalene
Fluorene
Phenanthrene
Phenol Gtg/g)
Alkylated benzenes (a)
Alkylated naphthalenes
(b)
Alkylated fluorenes (b)
Alkylated
phenanthrenes (b)
Alkylated phenols
ftig/g) (c)
Alkylated biphenyls (b)
Total
dibenzothiophenes
(A*g/g)
Aromatic content (%)
Otolfof
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 Oil
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
OUB
ND
ND
ND
0.15
0.20
ND
ND
0.69
1.74
0.14
ND
5.57
370
2.1
Mineral
OilC
ND
ND
ND
0.01
0.04
ND
ND
ND
ND
ND
ND
0.02
ND
3.2
Note:    The study characterized six diesel oils and three mineral oils. For the purpose of the general comparison and summary
        presented above, the Alaska, California, and Gulf of Mexico diesels are assumed to be representative of those used in
        coastal drilling operations.

ND = Not Detectable
(a)      Includes Cl through C6 alkyl homologues
(b)      Includes Cl through C5 alkyl homologues
(c)      Includes cresol and C2 through C4 alkyl homologues
                                                VI-3

-------
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, disposal  or reuse.
Transporting the drilling  wastes to shore would be done instead of product substitution when the used
drilling fluids are contaminated by crude oil due to the contribution of the oil from the formation being
drilled.  In these situations, toxic and nonconventional pollutants contained in crude oil are eliminated
from discharge.

        Free oil would be used as an indicator pollutant for the control of toxic  pollutants.  Free oil
would also be used as a surrogate for oil and grease hi BCT options in recognition of the complex nature
of the oils present in drilling fluids including crude oil from the formation being drilled. Both free oil
and  diesel oil  are considered to be  indicators  and to control specific toxic pollutants present in the
complex hydrocarbon mixtures used hi drilling fluid systems. These pollutants include benzene, toluene,
ethylbenzene, naphthalene, phenanthrene, and phenol.  As an illustration of the relationships between oils
and drilling fluids, Table VI-2 shows an increase hi oil and grease concentrations from water based fluids
to water-based fluids with mineral oil additives.  This table is from Section VII-4 of the 1993 Offshore
Development Document where characteristics of eight generic drilling fluids, representing water-based
drilling fluids commonly used hi the drilling industry, were presented.2

        The relationship between  oils and toxic organic constituents can be illustrated by noting, as an
example, the concentrations of the toxic organic, phenanthrene, in drilling fluids. Table VI-3 shows an
increase hi organic constituent concentrations  from water based fluids to water-based fluids with mineral
additives.  Note a particular increase hi phenanthrene from "not detected" hi water-based fluids, to  a
range of 1,060 to 19,300 fig/kg hi water-based fluids with mineral oil additives.  Furthermore, Table VI-
1 shows a general trend toward increases hi organic concentrations from mineral oils to diesel oils.  Note,
for phenanthrene in particular, a concentration hi the range of not detected to 0.04  mg/ml in mineral oil
to a range of 0.36 to 1.85 mg/ml hi diesel oil.

        Prohibiting the discharge of free oil  reduces the level of oil and grease present hi the drilling
fluids and drill cuttings allowed to be discharged and eliminates the pollutants listed above to the extent
that these are present to a lesser degree  hi substitute fluids and additives.
                                               VI-4

-------
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v, ii rt v, S
CO CN 00 00 OO
11111
^5 ^^ f^ r^4 f^H



»O O *— < 
-------
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 (for more details on the acute toxicity test see the final Offshore
Guidelines 58 PR 12507, March 4, 1993 - Appendix 2 to Subpart A of Part 435).  The technology basis
for the toxicity limitation is product substitution, i.e., substitution using less toxic drilling fluids, or if
the toxicity limitation cannot be met, transporting the drilling fluids and cuttings to shore for disposal.

        Additives such as oils and some of the numerous specialty additives, especially biocides, may
greatly increase the toxicity of the drilling fluid and drill cuttings (due to the adherence of drilling fluid
to the drill cuttings).  The toxicity is, in part,  caused by the presence and concentration  of toxic
pollutants. However, control of free oil and diesel oil, in some cases, may not be an effective means of
regulating these additives since they are neither diesel oil nor do they contain constituents with a free oil
component. A toxicity limitation requires that operators must also consider toxicity in selecting additives
and select the less toxic  alternatives. Thus, the toxicity limitation  will also serve to reduce discharges
of toxic and nonconventional pollutants. The limitation would encourage the use of the lowest toxicity
generic water-based drilling fluids or newer drilling fluid compositions with lower toxicity than the
generic fluids, and the use of low-toxicity drilling fluid additives.

        By regulating the  toxicity of drilling fluids and cuttings, certain toxic  and  nonconventional
pollutants are controlled.   It  has been demonstrated, during EPA's development  of the Offshore
limitations' (discussed in Section V of the Offshore Development Document)2,  that toxicity directly
controls the type and amount of mineral oil that can be added to a drilling fluid and pollutants such as
PAH's identified as constituents of mineral oil.   Drilling fluids and drilling fluid additives with low
toxicity would be encouraged by a toxicity limitation.

2.4    CADMIUM AND MERCURY
        By limiting cadmium  and mercury  content in the stock barite,  toxic  and  nonconventional
pollutants in drilling fluids and cuttings can be controlled. EPA has determined that it is not technically
feasible to specifically control the toxic pollutants controlled  by the mercury and  cadmium limits.
Limitations on cadmium and mercury content in the stock barite would control toxic and nonconventional
pollutants in drilling fluids and cuttings discharges.  This limitation would indirectly control the levels
                                              VI-7

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of toxic pollutant metals because cleaner barite that meets the mercury and cadmium limits is also likely
to have reduced concentrations of other metals.

       Barite is an additive used in drilling operations to increase the weight of the drilling fluid
necessary when drilling "deep" formations.  Barite is mined from either bedded or veined deposits.
Research has shown that bedded deposits are characterized by substantially lower concentration of heavy
metal contaminants including mercury and cadmium (See Table VI-4). Thus, use of barite from bedded
deposits will result in less toxic drilling fluids.

                                         TABLE VI-4
                   ANALYSIS OF TRACE METALS IN BARITE SAMPLES4

Source
Literature
Values:
Vein Deposits

Bedded Deposits

Kramer, et. al.:
Vein Deposits

Bedded Deposits

Reference Data:
Crust Average
Ocean Sediment
Trace Metals Concentration on Dry Weight : Basis" (mg/kg}
Fe


8-
22,000
100-
3,000

200-
59,000
2,500-
6,000


50,000
50,000
Pb


4-1,220

<10


<2-
3,370
1-1.8


15
110
Zn


10-4,100

<200"**


<0.2-
9,020
6-10


65
40
Hg


0.06-14

0.06-
0.19

0.8-28

0.13-
0.26


0.1
0.3
As '


7*

<500"*


0.008-
170
1.4-1.8


2
8
Ca


2-
26
1-
11






2
8
Cd


<0.2-
19
<50""




0.5-0.7


0.2
1
Jf&


19"

<5




0.4-
5.7

80
240
Gu


2-97

3-20




5.4-7.6


45
350
Co


ND

,<5-
60



1-2.2


23
100
 **
 ***
 ND
- One Sample
- Mean of 83 Samples
- Semiquantitative Emission Spectrographic Method
- Not detected
        Table VI-5 presents metal concentrations in barite. Comparing the concentrations of metals for
 "dirty" versus "clean" barite clearly indicate that for some metals, the concentrations decrease when using
 "clean" barite and others stay virtually the same.  Limiting cadmium and mercury to 3 mg/I and 1 mg/1
 respectively in stock barite indirectly controls the levels of toxic pollutant metals by using cleaner barite
                                              VI-8

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                                       TABLE VI-5
                         METALS CONCENTRATION IN BARITE5
Metal
Priority
Cadmium
Mercury
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Nonconventionals
Antimony
Barium*
Iron
Tin
Titanium
"Dirty" Barite Concentration
(rag/kg)

2.3
0.7
5.7
12.0
0.7
561.4
39.9
66.7
13.5
1.1
0.7
1.2
200.5

5.7
120,000.0
15,344.3
14.6
87.5
"Clean" Barite Concentration
{mg/kg}

1.1
0.1
5.7
7.1
0.7
240.0
18.7
35.1
13.5
1.1
0.7
1.2
200.5

5.7
120,000.0
15,344.3
14.6
87.5
* Source: SAIC, Barium Estimate, June 6, 1994

because of reduced  concentrations these  metals have in clean barite.  However, 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 with the concentrations of arsenic,
boron, calcium, sodium, tin, titanium, and zinc.5
                                           VI-9

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2.5    POLLUTANTS NOT REGULATED
       Where zero discharge would be required, all pollutants would be controlled in drilling fluids and
cuttings discharges.  Where discharges with limitations would be required, EPA has determined that it
is not technically feasible to control specifically each of the toxic constituents of drilling fluids and
cuttings that are controlled by the limits on the pollutants proposed for regulation.

       EPA has determined that certain of the toxic and nonconventional pollutants are not controlled
by the limitations on diesel oil, free oil,  toxicity, and mercury and cadmium 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 from EPA's field sampling program and does not believe them to
be found through out the industry; the pollutants when found are present hi trace amounts not likely to
cause toxic effects; and due to the large number and variation hi 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 hi additives or specialty chemicals.

3.0   PRODUCED WATER
       In the Coastal Oil and Gas Effluent Guidelines, EPA's preferred BAT option for produced water
is to require zero discharge everywhere except for Cook Inlet, Alaska where oil and grease would be
limited to a 29 mg/1  monthly average and a 42 mg/1 daily maximum.   The preferred  NSPS and
pretreatment standards option is zero discharge everywhere.  The preferred BCT option is an oil and
grease limitation of 48 mg/1 monthly average and 72 mg/1 daily maximum as  required for BPT. These
limitations represent the appropriate levels of control under BAT, BCT and NSPS.  EPA is controlling
all pollutants contained in produced water  where zero discharge is required and for  Cook Inlet, oil and
grease is being regulated as an  indicator pollutant to control the discharge of toxic pollutants.  Oil and
grease would be limited under  NSPS as both a conventional and an indicator pollutant  controlling the
discharge of toxic pollutants.

3.1    POLLUTANTS REGULATED
       Where  EPA would require zero discharge, EPA would be regulating all pollutants found in
produced water. (See Table VHI-4 for a listing of pollutants found hi produced water).  Where produced
water discharges would be allowed, (in Cook Inlet for BAT, and under BCT) EPA would be regulating
oil and grease as an indicator for toxics and nonconventional pollutants and as a conventional pollutant.
                                             VI-10

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        As previously denoted in the Offshore Technical Development Document (Section VI), oil and
grease serves as an indicator for toxic pollutants in the produced water wastestream which include phenol,
naphthalene, ethylbenzene, and toluene.  Also see Table VDI-3 of Section VHI which lists 35 organics
detected at least once in EPA's sampling programs.  The remaining toxic organic pollutants were not
detected.

        The technology basis for the oil and grease limitations is gas flotation. In addition to oil and
grease, gas  flotation technology with chemical addition removes both metals and organic compounds.
The insoluble metal hydroxide particle formation and adsorption by the chemical  (polymer) floe  of oil
and the action of the gas bubbles forces both the oil (oil and grease) containing floe and metal hydroxide
floe to the surface for removal (skimming), thus resulting hi lower concentration levels in the discharge
of oil and grease for  the above priority pollutants.   (See Section VIII for discussions of gas flotation
technology.)

        During the Offshore Guidelines development, EPA determined the characteristic of produced
water both after the BPT level of control and after gas flotation technology.  This data, shown here in
Table VI-6 demonstrates that as oil and grease is removed, so too are the organic pollutants.  (Note, this
table is taken from the Offshore Guidelines and presents data that may be different from that used in the
development of the Coastal Guidelines presented throughout the proceeding sections of this document).

3.2    POLLUTANTS  NOT REGULATED
        Where EPA would  require zero discharge, all pollutants found hi produced water would be
regulated.  Thus, this discussion pertains only to EPA's BAT option for Cook Inlet and EPA's BCT
option.

        The feasibility of regulating separately each of the constituents of produced water determined to
be present was also evaluated during the development of the Offshore Guidelines (See Section VI of the
Offshore Technical Development Document).2 EPA determined that it is not feasible to regulate each
pollutant individually  for reasons that include the following:   1) the variable nature of the number of
constituents in the produced water, 2) the impracticality of measuring a large number of analytes, many
of them at or just above trace levels, 3) use of technologies for removal of  oil which are effective in
removing many of the specific pollutants, and 4) many of the organic pollutants are directly associated
with oil and grease because they are constituents of oil, and thus, are directly controlled by the oil and
grease limitation. These reasons apply to the Coastal Guidelines.
                                             VI-11

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                                      TABLE VI-6

         POLLUTANT LOADING CHARACTERIZATION - PRODUCED WATER3
-. J
Pollutant Parameter " /
"" s S
Oil & Grease
TSS
f "fe s
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

BPf-Level Effluent
Improved <*as
Flotation Effluent
, - , Concentrations mg/1
25.0
67.5
23.5
30.0a
Concentrations p%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

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
a Source: SAIC, January 13, 1993.8

Note: This table is taken from the Offshore Development Document and used here for illustrative purposes. It may not
be the same as data presented for the coastal produced waters presented later in Section VIII.
                                          VI-12

-------
       While the oil and grease limitations limit the discharge of toxic pollutants, EPA determined during
the  Offshore Guidelines  rulemaking,  that  certain  of  the  toxic priority  pollutants,  such  as
pentachlorophenol,  1,1-dichloroethane,  and bis(2-chloroethyl) ether would not  be controlled by the
limitations on oil and grease in produced water. EPA is not proposing to regulate these pollutants in this
rule because EPA did not detect them in the samples within the coastal oil and gas data base.  (See the
Offshore Development Document, Section VI, page VI-7).

       Naturally Occurring Radioactive Materials (NORM), mainly consisting of radium 226 and radium
228, in produced water was found in concentrations averaging 400 pCi/1 (for both Radium 226 and
Radium 228 combined, sometimes referred to as total radium) in the coastal areas of the Gulf of Mexico.9
This pollutant would be eliminated by a zero discharge requirement.

       Existing data for NORM in Cook Inlet shows an average NORM discharge concentration of 4.51
pCi/1 (total radium).10  This is less than the  concentrations necessary for compliance in drinking water
standards11 (5 pCi/1 for total radium) or Louisiana state regulations12 (60 pCi/1, soluble radium), and thus,
indicates the concentration of NORM discharged into Cook Inlet waters to be low.  Therefore, NORM
is not being considered as a pollutant necessary for regulation in Cook Inlet.

       Produced water treatment technology has not been shown to remove NORM. According to data
submitted for the offshore record, removals of radium 226 and  radium 228 by granular filtration and
unproved gas flotation, if any, are believed to be minimal.7  The Offshore Development Document also
presents the membrane filtration performance on pollutant removals (summarized on Table IX-17 of that
document), which shows insignificant radium removals.

4.0   WELL TREATMENT,  WORKOVER, AND COMPLETION FLUIDS
       EPA's is co-proposing two options for BAT & NSPS for controlling pollutants found hi well
treatment, completion and workover fluids:  1) require limitations prohibiting the discharge of free oil,
or 2) to require zero discharge for all coastal areas except for Cook Inlet, where  EPA proposes oil and
grease limitations of 29 mg/1 30-day average and a 42 mg/1 daily maximum, (same limitations being
proposed for  produced water).  EPA is also proposing a no discharge of free oil limitation for BCT as
determined by the static sheen test and a zero discharge requirement for all coastal areas under NSPS,
PSES and PSNS.  These limitations represent the appropriate level of control under BAT, BCT, PSES,
PSNS and NSPS.
                                            VI-13

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       Where EPA proposes zero discharge,  EPA would be controlling all pollutants found in well
treatment, workover and completion fluids. As with produced water, oil and grease serves as an indicator
for toxic pollutants in well treatment, workover and completion fluids including, phenol, naphthalene,
ethylbenzene, toluene, and zinc. EPA has determined that it is not technically feasible to control these
toxic pollutants specifically,  and that the limitations on oil and grease reflect control  of these toxic
pollutants at the BAT and NSPS levels. EPA would regulate free oil as a surrogate for the control of oil
and grease in recognition of the complex nature of oils.

       EPA has determined, moreover,  that it is not feasible  to  regulate separately each  of the
constituents in well treatment, completion and workover fluids because these fluids in most  instances
become part of the produced water wastestream and take on the same characteristics as produced water.
Due to the variation of types of fluids used, the volumes used and the intermittent nature of their use,
EPA believes it is impractical to measure and control each parameter.  However, because of the similar
nature and commingling with produced water, the limitations on oil and grease and/or  free oil in the
Coastal Guidelines will control levels of certain toxic priority and nonconventional pollutants for the same
reason as stated in the previous discussion on produced water.
4.1     POLLUTANTS NOT REGULATED
       While the oil and grease and, in certain instances, the no free oil limitations limit the discharges
of toxic and nonconventional pollutants found in well treatment, completion and workover fluids, certain
other pollutants are not controlled.  These pollutants are the same as those listed in produced waters as
not being controlled by an oil and grease limitation. EPA exercised its discretion not to regulate these
pollutants because  EPA did not detect  them in more than a very few  of the samples within the
subcategory and does not believe them to be found throughout the coastal subcategory; and the pollutants
when found are present in trace amounts not likely to cause toxic effects.
5.0    PRODUCED SAND
        EPA is proposing BPT limitations for produced sand equal to zero discharge, which will serve
to control all pollutants present in  the produced sand wastestream.   This limitation represents the
appropriate level of control under BAT, BCT, NSPS, PSES and PSNS.

6.0    DECK DRAINAGE
        EPA is controlling pollutants found in deck drainage by the prohibition on the discharge of free
oil.  This limitation is the current BPT level of control and represents the appropriate  level of control
under BCT, BAT and NSPS.  .
                                             VI-14

-------
        The specific conventional, toxic and nonconventional pollutants found to be present in deck
drainage are those primarily associated with oil, with the conventional pollutant oil and grease being the
primary constituent. In addition, other chemicals used in the drilling and production activities and stored
on the structures have the potential to be found in deck drainage.

        The specific conventional, toxic and nonconventional pollutants controlled by the prohibition on
the discharges of free oil are the conventional pollutant oil and grease and the constituents of oil that are
toxic and nonconventional pollutants (see previous discussion in section 2, subsection 2.2 of this chapter
describing the chemical constituents of oil).  EPA has determined that it is not technically feasible to
control these toxic pollutants specifically,  and that the limitation on free oil in deck drainage reflects
                   %
control of these toxic pollutants at the BAT and NSPS level.  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.

        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.
                                              VI-15

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7.0   REFERENCES
1.     Batelle New England Marine Research Laboratory,  "Final Report  for Research Program on
       Organic Chemical Characterization of Diesel and Mineral Oils Used as Drilling Mud Additives"
       prepared for the Offshore Operators Committee - December 31, 1984 (Offshore RulemaMng
       Record, Volume IS).

2.     Development Document for Effluent Limitations  Guidelines and New Source Performance
       Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category,
       EPA 821-R-93-003, January 1993.

3.     CENTEC Analytical Services Inc., "Results of Laboratory Analysis and Findings Performed on
       Drilling Fluids and Cuttings - Draft," submitted to Effluent Guidelines Division, U.S. EPA, April
       3, 1984 (Offshore Rulemaking Record Volume IS).

4.     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 Rulemaking Record 26).

5.     SAIC,  "Descriptive  Statistics  and  Distributional  Analysis  of  Cadmium  and  Mercury
       Concentrations in Barite, Drilling Fluids, and Drill Cuttings from the API/USEPA Metals
       Database," prepared for Industrial Technology Division, U.S. Environmental Protection Agency,
       February 1991.  (Offshore Rulemaking Record Volume 120).

6.     SAIC, Worksheet entitled "Calculation for Average Density of Dry Solids in Cook Inlet Drilling
       Mud," June 6, 1994.

7.     Memorandum from Ronald Jordan, Engineering and Analysis Division, U.S. EPA, to Record.
       "Offshore Oil and Gas - Characterization of BPT- and BAT- Level Produced Water Effluent,"
       December 10, 1992.

8.     SAIC,  "Analysis of Oil and Grease Data Associated with Treatment of Produced Water by Gas
       Flotation Technology," prepared for the Engineering and Analysis Division, U.S. EPA, January
       13, 1993.

9.     SAIC,  "Statistical Analysis of Effluent from Coastal Oil and Gas Extraction  Facilities (Final
       Report)," September 30, 1994.

10.    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 Rulemaking
       Record Volume 138).

11.    40 CFR Part 141, Subpart B (Drinking Water Standards).

12.    Louisiana Code (LAC) Title 33, Part EX. Water Quality Regulations Chapter 7, March 20, 1991.
                                           VI-16

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                                      SECTION VII
                                  DRILLING WASTES
  CHARACTERIZATION, CONTROL AND TREATMENT TECHNOLOGIES
1.0   INTRODUCTION
       The first three parts of this section describe the sources, volumes, and characteristics of drilling
wastes generated from coastal oil and gas exploration and development activities.  The last part of this
section describes the control and treatment technologies currently available to reduce the volume  of
drilling wastes and the quantities of pollutants discharged to surface waters.

2.0   DRILLING WASTE SOURCES
       This section focuses on three wastes generated during drilling: spent drilling fluid, drill cuttings,
and dewatering liquid. Drilling fluid and drill cuttings are both major wastes streams of concern because
they are generated hi significant volumes.  Dewatering liquid is a process stream that sometimes becomes
a waste stream, but is most often either recycled or sent offsite with waste drilling fluids and cuttings to
commercial disposal facilities.

2.1    DRILLING FLUID SOURCES
       Drilling fluids, also referred to as drilling muds, are suspensions of solids, chemicals, and other
materials hi a base of water or oil which is specifically formulated to lubricate and cool the drill bit, carry
drill cuttings from the hole to the surface,  and maintain downhole hydrostatic pressure. Drilling fluids
typically  contain a variety of specialty chemicals (called "additives" hi this  report) to control density
(weight) and viscosity, reduce fluid loss to the formation, inhibit corrosion, and control or impart other
properties to the drilling fluid.

       Drilling fluids are  formulated at  the drill site according to the  drilling conditions.   Once
formulated, the fluid is pumped down the drill pipe and ejected to the borehole  through jets in the drill
bit. The  drilling fluid returns to the surface through the annulus (space between the casing and the drill
pipe).  As the fluid travels up the annulus, it carries the drill cuttings hi suspension.  The fluid then
passes through the solids  control equipment (shale shaker screens, hydrocyclones, etc.) to remove the
                                            vn-i

-------
cuttings, and  is returned to the mud tank for recirculation.   The design and use of solids  control
equipment are discussed hi detail hi Section 5.5, "Waste Mhihnization-Enhanced Solids Control."

       Excess drilling fluids are removed from the fluid circulation system during the drilling operation
and at the end of the drilling program for various reasons.  Excess drilling fluids are generated during
drilling when:

       •       cement, casing,  drill pipe or packer fluid are placed downhole,
       •       the fluid is diluted to maintain constant rheological properties, and
       •       the entire drilling fluid system is periodically changed over in response to changing
                    «
               drilling conditions.

At the end of the drilling program, the remaining fluid left over in the circulation system and the storage
tanks is either considered waste or recycled and/or regenerated for future use.

2.2   DRILL CUTTINGS SOURCES
       Drill cuttings are small pieces of formation rock that are generated by the crushing action of the
drill bit.  Additional hole material can slough off the drill hole wall, which is commonly referred to as
"washout."  Drill cuttings are carried out of the borehole with the drilling fluids.  Drill cuttings can
disperse as fine drill solids into the drilling fluids and can significantly effect the fluid's rheological (flow)
properties.  Solids control is the process of maintaining the concentration  of drill solids in the  drilling
fluid at an acceptable level. .The most common solids control methods are mechanical removal, dilution,
and displacement.

       Dilution and displacement are usually practiced together because each method is dependent on
the other. As the level of fine drill solids increases hi the drilling fluid, the viscosity also increases. For
a drilling fluid to remain effective, the viscosity must be maintained at a specific level.  Diluting the
drilling fluid  with make-up water has been the  traditional method of viscosity control.  In order to
maintain other properties of the drilling fluid after dilution, additives must be mixed into the  fluid in
correct proportions.  Therefore, the dilution method of viscosity control increases the total volume of
drilling fluid hi the system and requires the purchase of additional drilling fluid materials.   Since the
drilling fluid circulation system can hold only a limited volume of fluid at  any time, the excess  volume
generated as  a  result of dilution must be  removed from the active system.   Thus, the major waste
                                              vn-2

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generated from the use of dilution/displacement is spent drilling fluid.  The disposition of the displaced
drilling fluid depends on several factors including, but not limited to, site location, applicable regulations,
and the operator's waste management  budget.  Detailed discussions regarding the management  and
disposal of waste drilling fluid are provided in later sections.

        Viscosity can also be maintained by mechanically separating undesirable solids  (drill cuttings)
from the drilling fluid (see also Section 5.5).  It is important to note that dilution/displacement is often
practiced in combination with mechanical solids control as a means of maintaining desired drilling fluid
properties, although the amount of excess drilling fluid is minimized in this application.  The major waste
resulting from mechanical solids control is drill cuttings with adhering drilling fluid.  The disposition of
the waste drill cuttings depends on the same factors listed above for waste  drilling fluid.  These factors
are discussed in detail in later sections.

2.3    DEWATERING LIQUID SOURCES
        Dewatering liquid may come from one of two sources: the dewatering of waste drilling fluids
and/or cuttings storage vessel or pit, or from a dewatering centrifuge used as part of the solids  control
system.  EPA does not consider this  as a separate waste stream because it is often recycled back into the
drilling fluid circulation system as make up water or mixed with waste drilling fluids  and cuttings that
are sent to offsite commercial disposal facilities. EPA investigated this particular potential waste source
because it  has  been regulated separately in the Region  VI general NPDES permit  (55 FR 23348).
Dewatering liquid was the focus of an EPA sampling program at three active drill sites in southern
Louisiana.1'2-3  These sampling efforts are described in Section V.4.0, "Investigation of Solids Control
Technologies for Drilling Fluids." These data were not used for regulatory purposes because EPA later
determined through contacts  with industry and onsite visits, that this waste stream is rarely discharged
as a separate waste.  The technical aspects of dewatering liquid generation are discussed in greater detail
in Sections 5.5.5 and 5.5.6.

3.0    DRILLING  WASTE VOLUMES
        Approximately 79,000 bbls per year  of drilling fluids and cuttings  are being discharged by the
coastal  oil  and gas industry, all of which is occurring in Cook Inlet. This is equal to  approximately
553,000 barrels of drilling fluids and cuttings from all of the drilling  projects  currently planned by
industry extending until the year 2002. The following sections discuss the factors affecting the volumes
of drilling waste generated and numerical estimates of these volumes.
                                              vn-s

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3.1    FACTORS AFFECTING DRILLING WASTE VOLUMES
       Drilling fluids discharges are typically in bulk form and occur intermittently during well drilling
and at final well depth. Low volume bulk discharges are the most frequent and are associated with fluid
dilution, the process of mamtaining the required level of solids in the fluid system.  High volume bulk
discharges occur less frequently during a well drilling operation, and are associated with drilling fluid
system changeover and/or emptying of the mud tank at the end of the drilling program.

       The volume of drilling fluid generated and the volume of drill cuttings recovered at the surface
will depend on the following:

       •       Size and type of drill bit
       •       Hole enlargement
       •       Type of formation drilled
       •       Efficiency of solids control equipment
       •       Type of drilling fluid
       •       Density of drilling fluid.

       The EPA Offshore Oil and Gas  Development Document describes  the affect of each of these
factors on drilling fluid volume.4.

       The volume of drill cuttings generated depends primarily on the dimensions (depth and diameter)
of the well drilled and on the percent washout. Washout is the enlargement of a drilled hole due to the
sloughing of material from the walls of the hole.  Drill solids are continuously removed via the solids
control equipment during drilling. The greatest volumes of drill cuttings are generated during the initial
stages of drilling when the borehole diameter is large and washout tends to be higher.  Continuous and
intermittent discharges are normal  occurrences in the  operation of solids control  equipment.   Such
discharges occur for periods from less than one hour to  24 hours per day, depending on the type of
operation and well conditions.

       The volume of drill cuttings generated also depends on the type of formation being drilled, the
type of bit, and the type of drilling fluid. Soft formations are more susceptible to borehole washout than
hard formations.  The type of drilling fluid used can affect the amount of borehole washout and shale
sloughing. The type of drill bit determines the characteristics of the cuttings (particle size).  Depending
                                             vn-4

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on the formation and the drilling characteristics, the total volume of drill solids generated will be at least
equal to the borehole volume, but is most often greater due to the breaking up of the compacted formation
material.

       Additional information regarding hole enlargement due to washout is listed in Table VII-1.  These
data were provided to EPA  by drill site operators during visits to three  coastal sites hi  southern
Louisiana.1'2-3 Because the volume of washout varies depending on the type of formation being drilled,
no single set of numbers can be applied as a rule of thumb to all drilling situations.  However, Table VTI-
1 indicates that the percent washout generally decreases with hole depth.  It should be noted that the
values in Table VII-1 were estimates obtained from industry operators during EPA's drilling site study
and were not directly measured.

3.2    ESTIMATES OF DRILLING WASTE VOLUMES
       In order to compare waste volumes generated during various drilling projects, a normalized waste
volume can be determined by  dividing the total reported waste discharged from the active drilling fluid
circulation system by the total volume of hole drilled. The volume of hole drilled is calculated  from the
bit sizes used for specific depth intervals, and from estimated washout volumes. The volume  of waste
discharged is typically available from waste transport reports or other records maintained at the drill site,
and are often estimated based on the volume of the vessel used to store and/or transport the waste. Once
calculated, the ratio of waste-to-hole volume can then be compared between drilling projects.  For drill
cuttings, this ratio is called the "expansion factor"  because it indicates how much a given volume of
cuttings increased after it was drilled out of the hole. No such distinctive name is  used for the ratio of
waste drilling fluid to calculated hole volume.  For both drilling fluids  and cuttings, the waste-to-hole
volume ratio should always be greater than one,  although in some cases it is  less than one due to the
disposal of fine cuttings with the waste mud,  or to inaccurate waste volume tracking procedures or
records.  Table VTI-2 lists the hole volumes, waste  volumes, and the calculated waste-to-hole volume
ratios for eight different drilling projects hi the coastal Gulf of Mexico region.  The first three projects
were created based on a "model well" as part of EPA Region VTs development of two general NPDES
permits for coastal Louisiana and Texas  (55  FR  23348), and were not actual  wells drilled.  The
characteristics of the model well (e.g., depth intervals, hole volume, percent washout, etc.) and the solids
control system parameters were designed to represent typical coastal drilling projects. The remaining five
projects in Table VTI-2 were actual wells, including two offshore and three coastal.
                                             vn-s

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                        TABLE VH-1.  PERCENT WASHOUT  FACTORS
Reference

SAIC, May 25, 19941


SAIC, Aug. 8, 19942



SAIC, Aug. 5, 19943


Depth Interval
; - -{feet) ;;; ^-y
0 - 3,000
3,000 - 11,500
> 11,500
0 - 4,000
4,000 - 11,000
11,000 - 13,000
> 13,000
0 - 3,000
3,000 - 10,000
> 10,000
Pet-cent Washout
-
100
25-50
10
75
40
20
10
100
50
25-50
       A number of observations can be made from the data in Table VH-2.  Referring to the EPA
Region VI data only, it is apparent that as solids control system efficiency increases, the mud-to-hole
volume ratio decreases  and the cuttings expansion factor  increases.  A low efficiency solids control
system will allow a significant volume of drill cuttings to remain in the circulating drilling fluid, thus
requiring greater dilution of the drilling fluid and hence increasing the volume to be disposed. A higher
efficiency solids control system will remove a greater volume of cuttings from the circulating drilling
fluid, thus decreasing the need for dilution as well as the volume of waste drilling fluid.  In addition,
if chemically enhanced  centrifugation (CEC) is part of the solids control system, the volume of waste
solids should be slightly higher than systems not using CEC because the flocculated solids add to the
volume discharged by the centrifuge.

       These trends are to be expected, but are not always observed in practice due to  site-specific
conditions, inaccuracies in hole volume estimation, and in waste volume tracking and reporting. Data
from the five actual drilling projects listed in Table VH-2 illustrate this point. The cuttings expansion
factors for the two offshore drilling  projects are both less than one, suggesting that washout volumes
may have been overestimated and that a significant volume of cuttings may have been included with
the discharged mud volume.  Also, the 8,130 barrels of cuttings reported for the last drilling project in
                                             vn-6

-------
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SAIC, May 25, 1994'
ta obtained during EPA site
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this table is known to include 591  barrels of spent drilling fluid and  is believed to include  more,
particularly because the  cuttings were collected  in a barge  and there  was no other holding vessel
dedicated to spent drilling fluid at the site.  Such uncertainties  about what is included in a load of
drilling waste  and its volume occur because there are no requirements for keeping waste drilling fluid
and cuttings volumes separate when  they are being hauled offsite.

       Volumes of waste drilling muds and  cuttings generated by  operators located  in Cook Inlet,
Alaska were reported in responses to the  1993  EPA Questionnaire for Coastal Oil and Gas Operators.6
From the data submitted hi the survey and information obtained directly from the operators, an average
volume of muds and cuttings generated was calculated to be 14,354 barrels from an average well of
11,765 feet in depth. Table VII-3 lists the data used to calculate these averages.5

       Based on this estimation and on projected drilling schedules provided by operators in Cook
Inlet, the total volume of drilling  wastes generated from drilling activities  in Cook Inlet is a total of
553,000  bbls over the 7 years following promulgation of this rule, or 79,000 bbls per year (see Section
X for details).

3.3    DEWATERING LIQUID VOLUMES
       Estimates of dewatering liquid volumes were obtained from two of the three drilling operations
visited by EPA  in 1993.1-2 Referring to Table VH-2, the wells drilled to depths of 12,860 and 14,928
feet generated  estimated volumes  of 4,800  and 2,423 barrels of dewatering  liquid, respectively.
Although a larger hole volume is generally associated with larger volumes of waste fluids and cuttings,
there is no apparent relationship between well depth and dewatering liquid volume.  As  explained in
Sections 5.5.5  and 5.5.6, factors affecting the  volume and quality of the liquid effluent from a
dewatering process  are related to  the selected dewatering method  and the  efficiency of the upstream
solids separation equipment rather than the well depth.

4.0    DRILLING WASTE CHARACTERISTICS
4.1    DRILLING FLUID CHARACTERISTIC
        Several  broad categories of drilling fluids exist such as water-based  fluids  (fresh or salt water),
low solids polymer fluids, oil-based  fluids, and oil emulsion fluids.  This section discusses only water-
and oil-based fluids because they represent the traditional and most widely used drilling fluids.
                                              vn-s

-------
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        Oil-based muds are only used for specific drilling conditions because they cannot be discharged
and are more expensive to use than water-based muds.  The discharge of oil-based muds and associated
cuttings is prohibited under the BPT limitations of "no discharge of free oil." Industry has indicated
that oil-based drilling fluids continue to be the material of choice for certain drilling conditions.7  These
conditions include the  need for thermal  stability when  drilling  high-temperature  wells, specific
lubricating characteristics when drilling deviated  wells, and the ability to reduce stuck pipe or hole
washout problems when  drilling  thick, water-sensitive shales.  A  primary concern  when  using
conventional, oil-based fluid systems is their potential for adverse environmental impact in the event
of a spill.  Because of the relatively high toxicity of diesel oil, some  mineral oil-based fluid systems
have replaced diesel oil-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   (MgCl2),  calcium  chloride/bromide
(CaCl2/CaBr2),  or zinc chloride/bromide (ZnCl2/ZnBr2).  All freshwater  fluids contain bentonite (sodium
montmorillonite clay) and caustic soda (NaOH),  while saltwater fluids may contain  attapulgite clay
instead of bentonite. Clays are a basic component of drilling fluids used to enhance the fluid viscosity.
The most common required drilling fluid properties and the additives used to  enhance these properties
are discussed below.

        Several different formulations of drilling fluids and additives can be created to achieve the
required downhole conditions.  The most common properties of the drilling fluid that the mud engineer
controls are:

               Rheology (flow properties)
               Density
               Fluid loss control
               Lubricity
               Lost circulation
               Corrosion and scale control
               Solvents
               Low solids polymer fluids
               Bactericides.
                                             vn-io

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Each of these properties can be tailored to specific well and drilling conditions through the addition of
active solids, inactive solids, and chemicals to the base drilling fluid. The EPA Offshore Development
Document discusses each of the above-listed properties, and describes the individual components of
drilling fluids as well as typical drilling  fluid compositions.4  A comprehensive list of drilling fluid
components and their applications is provided in Appendix VII-1.8

        Barite,  which is used  to control the  density of drilling fluids, is the primary  source of toxic
metal pollutants.  The characteristics  of raw barite will determine the concentrations of metals found
in the spent drilling fluid system. A statistical analysis of metals concentrations in spent drilling fluids
showed a higher concentration of toxic metal pollutants in drilling fluids formulated with "duly" barite
                    *
than in those formulated with "clean" barite.9

        Based on the results of this  analysis,  EPA developed a profile of metals  concentrations in
drilling fluids  formulated with "clean" barite as part of the  development of Offshore Guidelines.
"Clean" barite is defined as  stock barite that meets the maximum limitations of cadmium of 3 mg/1 and
for mercury of 1 mg/1.4 Table VII-4 presents  the estimated characteristics of drilling fluids and cuttings
taylored specifically for Cook Inlet since  drilling wastes are discharged in this area only.  Table VTI-4
includes the  offshore metals concentration profile developed from the statistical analysis for "clean"
barite.   The only difference  to be noted is the concentration  of barium., which was reevaluated in this
rulemaking effort because  the average weight of drilling  fluid (10 Ib/gal) reported by Cook Inlet
operators  hi  the 1993  EPA Coastal Questionnaire was lower than the average offshore  model fluid
weight of 11.0 Ib/gal.  The  revised barium concentration  for coastal regulations was calculated to be
120,000 mg/kg as compared to the calculated  concentration of 359,747 mg/kg estimated for the offshore
model well.10

        Mineral oil, which  is used in Cook Inlet drilling  operations mostly  to free stuck  pipe,  is a
drilling fluid  additive that contributes  toxic organic pollutants to the drilling fluid system.  An operator
in Cook Inlet, Alaska recently  estimated that the amount of mineral oil typically used in water-based
drilling fluids is approximately 0.02 percent.6 The  concentrations  of organic compounds listed in Table
VII-4 were calculated based on this estimate,11 and on the average concentrations of organics  hi mineral
oil as listed in Table VII-9 in the Offshore Development Document4
                                             vn-ii

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TABLE VH-4.  COOK INLET DRILLING WASTE CHARACTERISTICS
Waste Characteristics
Percent of cuttings in waste
drilling fluid
Average density of cuttings
Average density of waste drilling
fluid
Percent of dry solids in waste
drilling fluid, by volume
Average density of dry solids in
waste drilling fluids
Vatae
19%
980 pounds per barrel
420 pounds per barrel
11%
1,025 pounds per barrel
Reference
1993 EPA Survey of Coastal Oil and Gas
Operators6
Estimated12
1993 EPA Survey of Coastal Oil and Gas
Operators6 and Calculations15
Calculations 10
Calculations 10
u Drilling Fluid Pollutant Concentration Data
Conventionals
Total Oil
Total Suspended Solids
Priority Metals
Cadmium
Mercury
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Priority Organic?
Naphthalene
Fluorene
Phenanthrene
Non-Conventional Metals:
Aluminum
Barium
Iron
Tin
Titanium
Non-Conventional Organics
Alkylated benzenes (a)
Alkylatcd naphthalenes (b)
Alkylated fluorenes (b)
Alkylated phenanthrenes (b)
Total biphenyls (b)
Total dibenzothiophenes
Ibs/bbI of drilling fluid
0.0596
113.0
rag/kg dry drilling fluid
1.1
0.1
5.7
7.1
0.7
240.0
18.7
35.1
13.5
1.1
0.7
1.2
200.5
Ibs/bW of drilling EMd
0.0000035
0.0000563
0.0000084
Big/fcg dry drilling fluid
9,069.9
120,000.0
15,344.3
14.6
87.5
Ibs/bbl of drifting fluid'
0.0021017
0.0000344
0.0001218
0.0000143
0.0001360
0.0000004
Reference
Estimated11
Estimated10
Reference
Offshore Development Document, Table
XI-64
Reference t
Calculated11 from concentrations in
Offshore Development Document, Table
VII-94
Reference
Offshore Development Document, Table
XI-64; except for barium, which was
estimated.10
- - •.- -'Reference
Calculated11 from concentrations in
Offshore Development Document, Table
VH-94
                         vn-12

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       The TSS attributable to drilling fluids is estimated based on two physical properties of the waste
drilling fluids:  the estimated percentage of the fluid that is dry solids (11%), and the estimated density
of the dry solids (1,025 Ibs/bbl).10 The dry solids content of the drilling fluid was estimated from mud
reports provided by the operator of one of the drill sites visited by EPA.1  The density of dry solids was
estimated based on the mud weight of 10.1  Ibs/gal  obtained from the mud reports,1 and calculated  by
subtracting the density of water (in Ibs/gal) from the mud weight.10 Finally, the TSS concentration in
drilling fluid was calculated as follows:
            (0.11 bbl dry solids/bbl drilling fluid) x (1,025 Ibs dry solids/bbl dry solids)
                               = 113 Ibs dry solids/bbl drilling fluid
4.2   DRILL CUTTINGS CHARACTERISTICS
       Drill cuttings themselves are inert solids from the formation. However, drill cuttings discharges
also contain drilling  fluids that have  adhered  to  the  cuttings.   The  composition of drill cuttings
discharges is directly dependent upon the fluid used.  Cuttings associated with oil-based drilling fluids
or from petroleum bearing formations will contain  hydrocarbons  which adsorb on the surface of drill
solid particles and  resist removal by washing operations.   The volume of the fluid adhering to the
discharged cuttings  can vary considerably depending on the formation being drilled, the type of drilling
fluid being used, the particle size distribution of the cuttings, and the efficiency of the solids control
equipment.  A general rule of thumb is that five percent (5%) drilling fluid by volume is associated with
the cuttings.16  Data from a drilling project  in the Outer Continental  Shelf off southern  California
indicate that the cuttings discharges from the solids control equipment were  comprised of 96 percent
cuttings and four percent adhered drilling fluids.17

       For  the  purpose  of estimating pollutant reductions,  the total  suspended  solids  (TSS)
concentration attributable to drill cuttings is equivalent to the density of the dry weight of cuttings (980
Ibs/bbl).12 This density was estimated from Cook Inlet geologic information provided by the industry,13
and the specific gravities of low- and high-gravity solids,14 as follows:
               The first 500 feet of depth consists of high-gravity solids13 with a specific  gravity of
               4.5.14
               The depth from  500 to 10,000 feet consists  of low-gravity  solids13 with  a specific
               gravity of 2.6.14
               50% of the total cuttings volume is generated during the first 3,000 feet.6
                                             vn-13

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               The average specific gravity for the first 3,000 feet (50% of the total volume) =
                        [(4.5 x 500 ft) + (2.6 x 2,500  ft)] / 3,000 ft = 2.92
               The average specific gravity for the remaining depth = 2.6
               The overall specific gravity for drilling  cuttings =
                                      (2.92 + 2.6) / 2 = 2.8
               The average density  of dry cuttings (using water at standard temperature and pressure
               as a reference) =
                               2.8 x 350 Ibs water/bbl = 980 Ibs/bbl
4.3    DEWATERING LIQUID CHARACTERISTICS
                    *
        During site visits to three southern Louisiana drilling operations,  EPA collected samples  of
dewatering centrifuge liquid to determine the quality of this process stream.1>2>3  This process stream
consisted mostly of the water phase of the drilling fluid.

        At each drill site, one set of grab samples was collected on two consecutive days from the liquid
discharge from a decanting centrifuge that was part of the solids control  system (see also Section 5.5.5).
The major difference between the three solids control systems was that two of them included chemical
treatment of the centrifuge  influent to enhance liquid\solid separation, also referred to as chemically
enhanced centrifugation (CEC~see Section  5.5.6).  The third system used no additional chemicals
upstream of the centrifuge.  The result was that separation of the colloidal solids from the liquid phase
was much more  efficient at the two sites using CEC.  These samples were relatively free of suspended
solids (TSS ranged from 24 to 520 mg/1), while the untreated sample had to be analyzed as a solid due
to its solids content (23% to 24.7%), and had the consistency of a drilling fluid.

        Table  VH-5 compares  data obtained from  the two  sites that used CEC to effluent limits
established for this waste stream in a general permit covering drilling  waste discharges in the coastal
Gulf of Mexico region (58 FR 49126).  The dewatering  liquid at these sites was being treated  for
recycle and not for surface discharge.   In fact, the majority of these waste volumes was  hauled to
commercial disposal.1-2  The solids control  contractor  at one  of these sites  suggested  that further
treatment with activated carbon would produce discharge-quality  effluent.2
                                             VII-14

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       TABLE VH-5.  COMPARISON OF ANALYTICAL CHARACTERISTICS OF
 CENTRIFUGE WATER EFFLUENT FROM THE GAP ENERGY AND ARCO DRILLING
             SAMPLING EPISODES TO THE EPA REGION VI GENERAL
         PERMIT POLLUTANT LIMITATIONS FOR DRILLING  OPERATIONS
Pollutant
Oil & Grease
TSS
TDS
COD
PH
Chloride
Arsenic
Barium
Cadmium
Chromium
Copper
Lead
Manganese
Mercury
Nickel
Selenium
Silver
Zinc
tMfs
mg/1
mg/1
mg/1
mg/1
S.U.
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
General Permit
Limitations2
Texas
15
50
3,000
200
6-9
500
0.1
1.0
0.05-0.1
0.5
0.5
0.5
1.0
0.005
1.0
0.05-0.1
0.05
1.0
Louisiana
15
50
-
125
' 6-9
500
-
-
-
0.5
-
-
-
—
—
-
-
5.0
GAP Energy1
6/ltf/93
ND(l.O)
24
7,600*
1,040*
6.27
317
0.310
ND(0.018)
ND(0.004)
1.26*
ND(0.012)
ND(0.044)
3.84
ND(0.0002)
ND(0.026)
0.044
ND(0.010)
0.006
6/17/93
1.0
35
6,420*
735*
8.95
866*
ND(0.018)
2.32
ND(0.002)
0.069
ND(0.006)
ND(0.022)
ND(0.003)
ND(0.0002)
ND(0.013)
ND(0.0258)
ND(0.005)
0.501
ARCO2
7/2-1/93
8.0
520*
14,000*
5,370*
7.48
2,050*
0.0766
0.667
ND(0.005)
4.59*
0.23
ND(0.047)
0.442
0.00115
0.0279
ND(0.02)
ND(0.004)
0.083
7/22/SB
3.0
440*
15,200*
4,630*
7.4
2,150*
0.0679
0.696
ND(0.005)
4.42*
0.141
ND(0.047)
0.762
0.00075
0.0273
ND(0.02)
ND(0.004)
0.198
3 58 FR 49126

* Samples that exceed General Permit Limitations


4.4    COOK INLET DRILLING WASTE CHARACTERISTICS

       For the purpose of developing compliance cost and pollutant reduction estimates, particular

characteristics of drilling wastes in Cook Inlet, Alaska were identified. The sources for these data include

the 1993 EPA Questionnaire for  Coastal Oil and Gas Operators, the  EPA Offshore Development

Document,  direct correspondence with the operators, and calculations and estimates based on the data
                                       vn-is

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from these sources.  Table VII-4 lists the characteristics of interest, including densities of cuttings and
drilling fluid, percentage of solids in drilling fluid, and pollutant concentration data.

5.0   CONTROL AND TREATMENT TECHNOLOGIES
       This section includes discussions of drilling waste treatment technologies currently employed in
the coastal oil and gas industry.  The technologies include the following:

       •       product substitution to minimize pollutant content
       •       closed-loop solids control systems to minimize waste stream volume
       •       reserve pits
       •       conservation and reuse/recycling.

       In addition, EPA investigated the following disposal methods:

       •       land treatment/disposal
       •       subsurface injection of drilling fluids
       •       grinding and subsurface injection of drill cuttings

5.1    BPT TECHNOLOGY
       EPA  has developed effluent limitations guidelines  for the Coastal subcategory based on Best
Practicable Control Technology Currently Available (BPT), which represented the average of the best
existing technologies -at the time of investigation. These standards were promulgated on April 13, 1979
(44 FR 22069).  At that time, EPA determined that drilling product substitution, or the use of more
environmentally benign products, combined with onshore disposal was the best practicable control method
available.  An example of product substitution is the use of water-based drilling fluid in place of oil-based
drilling fluid such that the drilling fluid (and cuttings) discharged would pass  the no-free-oil limit.
Effluent limitations based on this technology allow no discharge of free oil in drilling fluids and drill
cuttings. This limitation is implemented by requiring no oil sheen to be present upon discharge.

5.2   PRODUCT SUBSTITUTION - ACUTE TOXICITY LIMITATIONS
       It has been shown that low toxicities can be achieved through the use of water-based drilling
fluids and low toxicity specialty additives.4 Thus, limitations based on acute toxicity would encourage
operators to substitute low toxicity additives for high toxicity additives.  For the purpose of estimating
                                             vn-ie

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compliance costs and pollutant reductions, two options are presented that include toxicity based limitations
(see Section X for detailed discussion of these options).  One option includes the current offshore
limitation of 30,000 ppm in the suspended particulate phase (SPP), which is currently met by all but 1 %
of the drilling wastes in Cook Inlet.18 The other option includes a toxicity limitation of 1,000,000 ppm
(SPP) which data from Cook Inlet discharge monitoring reports indicate is being met by 83 % of the
drilling wastes currently discharged.19   The data supporting the 1,000,000 ppm toxicity limitation are
presented in Section X.2.

5.3    PRODUCT SUBSTITUTION - CLEAN BARITE
        Barite is a major component of drilling fluids which can represent as much as 70 percent of the
weight of a high-density drilling fluid. Barite has been shown to contain varying concentrations of metals
of toxic concern, particularly cadmium and mercury.  Barium sulfate, the natural source of barite, has
also been shown to  contain varying concentrations of metals depending on the characteristics of the
deposit from where the barite was mined.  During the  development of the Offshore Guidelines, a
statistical analysis of the API/USEPA Metals Database  indicated that there is some correlation between
cadmium and mercury and other trace metals in the barium.9  Thus, regulating the concentration of
cadmium and mercury in barite would indirectly regulate all other metals present in barite. The Offshore
Development Document includes a detailed discussion of the findings of this analysis.4

5.4    PRODUCT SUBSTITUTION - MINERAL OIL
        In addition to using low toxicity drilling fluids,  low toxicity lubrication additives can reduce the
overall toxicity of the drilling fluid.  For many years, diesel oil was the preferred additive for lubrication
purposes and for spotting jobs.  EPA has evaluated other lubricants that have similar properties to diesel
but are less  toxic.  Mineral oil has become a common substitute for diesel oil as it can be used as a
torque-reducing agent and a spotting fluid.4

        An OOC sponsored analysis of organic chemical characterization of diesel and mineral oils used
as drilling fluid additives indicated that there are similar constituents in both diesel and mineral  oils but
at significantly higher concentrations in the diesel.20 The analysis revealed quantitative differences in the
total aromatic, total  sulfur and organic sulfur contents, as well as in the concentrations of individual
aromatic hydrocarbons (benzene, naphthalene,  biphenyl, fluorene  and phenanthrene alkyl homologue
series) and sulfur- and nitrogen-polycyclic aromatic compounds (PAC) (debenxothiophene and carbazole
                                            vn-i?

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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.20 Several industry studies  investigated the effectiveness of using
diesel oil versus mineral oil in 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.

5.5    ENHANCED SOLIDS CONTROL: WASTE MINIMIZATION/POLLUTION PREVENTION
       A widely recognized method of minimizing drilling waste volumes is the use of high-efficiency
solids control systems, sometimes referred to as "closed-loop" solids control systems or CLSs. The term
"closed-loop" is somewhat misleading in that it implies a closed system from which only waste cuttings
are removed. The system is not truly closed because, regardless of the system's level of efficiency, some
cuttings are always retained in the drilling fluid and some drilling fluid is  always discarded with the
cuttings.21  While no  single definition of the term "closed-loop" is available,  definitions throughout
current literature generally describe closed-loop technology as the process of minimizing both the amount
of waste produced from an active drilling fluid circulation system and the amount of dilution required by
the drilling fluid.21-22'23  In practice, then, a CLS returns as much drilling fluid to the circulation system
as is economically and practically possible.  The drill cuttings removed  from the circulation system are
consequently reduced in liquid content and overall volume.   While the practical application of solids
control systems cannot be 100 percent "closed," the CLSs currently in use in the coastal oil and gas
industry are measurably more  efficient than conventional systems that utilize reserve pits and little or no
waste minimizing technology.

       Following is a list of advantages to using CLS technology compiled from current literature:22-23'24

       •       Reduced dilution  and associated displacement of drilling fluid, resulting in reduced
               drilling fluid maintenance costs
       •       Reduced waste volume and disposal cost
       •       Reduced disposal costs offset increased  costs  for improved solids control
       •       Reduced total drilling location waste management costs
                                             vn-is

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        •      Reduction or elimination of the need for an earthen pit and avoidance of significant site
               closure costs at land-based sites
        •      Increased rate of penetration
        •      Increased drilling efficiency through optimization of drilling fluid solids content and
               Theological properties
        •      Reduced trouble costs
        •      Minimal environmental impact
        •      Reduced waste transportation and disposal liability.

        It is apparent in both industry literature and industry practices (as observed directly by EPA) that
closed-loop solids control technology is achievable using currently available equipment.1-2'3'22  A typical
CLS consists of at least some of the following  equipment, depending on the drilling program: shale
shakers, a sand  trap, a degasser, hydrocyclones (desanders,  desilters, microclones), a flocculation
chemical addition manifold, a dewatering centrifuge, and a barite recovery centrifuge if weighted drilling
fluid is used. Closed-loop  solids control systems can provide  greater than  90 percent solids removal
efficiency when flocculation enhancing chemicals are used.25  Without chemical addition, CLS efficiency
ranges between 72-75  percent.25   The following sections describe these unit processes as they are
currently utilized in closed-loop solids control systems.

5.5.1    Shale Shakers
        Shale shakers, also called vibrating screens,  are usually  the first step  in a solids control system.
The function of a shale shaker is to remove the largest drill cuttings from the active drilling fluid system
and to protect downstream  equipment from unnecessary wear and  damage from abrasion.  Variables
involved in shale shaker design include screen cloth characteristics,  type of motion, position of screen,
and arrangement of multiple screens.

        Screen characteristics are expressed as mesh size (the number of openings in a liner  inch),
opening size, percent open area,  and wire diameter.  Typical mesh  sizes range from 30 to 250.26  The
type of screen motion is determined by the eccentric weight or reciprocator (the vibrating device) and the
suspension system. Motion can be circular,  elliptical, or straight-line.  Screen position depends  on the
effectiveness of the vibrating motion to move solids. Ideally, balanced circular or elliptical motion  should
move the solids across the screen regardless of screen position.  Tilting the  screen might be necessary
                                             VII-19

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to overcome problems brought on by unbalanced elliptical motion.  Such tilting can cause an increase in
drilling fluid loss with the cuttings.  Multiple screens are used when the solids load is too great for a
single screen (or under other problematic drilling conditions), and are used hi one of two arrangements:
series or parallel. Staged (or "cascaded") screens hi series are arranged so that the underflow of the first
screen is the feed to the second, and so that the coarser mesh screen comes first.  Parallel arrangements
can include multiple screens on a single deck or side-by-side pairs of shale shakers.  Some operators use
two sets of shale shakers hi series, wherein the first shakers,  referred to as "scalp" shakers,  contain
coarser mesh to remove sticks and the largest particles, and the second set of shakers contain finer
mesh.25

        A term that is used to quantify the portion of solids that remain hi the discharge as compared to
the solids that leave with the liquid underflow is the "median cut."  This term is used to describe  the
performance of all solids separation equipment in addition to shale shakers. The median cut-size particle
for a shale shaker screen is that of which half pass through and half remain on the screen. For a given
shale shaker (or any solids separation unit), a smaller median cut particle size indicates better separation
than a larger  median cut particle size.  The range of acceptable median cut particle size depends on
multiple factors for any particular unit.  Factors that determine what the median cut will be for a given
shale shaker include the screen mesh size,  screen opening shape (square or rectangular), the amplitude
(or distance) of the vibration, and the particle shapes.  Not all particles smaller than the screen mesh get
through, and likewise, some oversize particles pass through due to their shape.

        Common  shale  shaker problems include solids  overloading and screen plugging (called
"blinding").   Both problems cause the screen to be bypassed and thus reduce the liquid throughput.
Solids overloading, which may occur at tunes of increased drilling rate, can be overcome by adding a
screen, either hi series or hi parallel. Blinding may be due either to a film of small particles that adheres
to the screen and reduces the effective open area or to near-size particles plugging the screen.  The
former case may be corrected with a coarser mesh screen,  and the latter might require a smaller mesh.
Some shale shakers are equipped with a spray bar that showers water over the cuttings on the screen to
enhance mud/cuttings separation. However, Cagel recommends that only temporary spray bars be used
to apply a "mist" to sticky clay cuttings and other problematic solids.27

        Current innovative screening device designs include fine mesh (up  to 400) screens capable of
processing drilling mud through an effective area of up to 600 square feet per second under a slight
                                             vn-20

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vacuum. Advantages of such designs include improved degassing capability and reduced free liquid on
the discarded solids.28

5.5.2   Sand Traps
        A sand trap is a settling tank positioned to receive the liquid underflow from the shale shakers.
This tank serves to "trap" sand and other large particles that bypass the shale shaker screens, either by
design or due to a problem with the shakers (e.g.,  torn screen, blinded screen, solids overload).  This
settling protects the downstream  equipment from wear due to abrasion.  A properly designed sand trap
is not stirred (as are other tanks in the active mud system), removes solids only through a bottom-opening
dump valve, and discharges mud over a retaining weir. Because large amounts of barite could settle out
hi this quiescent tank,  weighted muds should bypass the sand trap, unless there are problems with the
shakers.29'30

5.5.3   Degassers
        The purpose of a degasser is to remove gas and air from the drilling fluid which, due to its
compressibility, can have detrimental effects on the drilling fluid.  In addition, centrifugal pumps used to
feed downstream equipment, as  well as hydrocyclones, do  not operate efficiently with gas-cut fluid.
Therefore, in a well designed system,  a degasser is positioned after the sand trap and before the
hydrocyclone pumps.

        Two basic designs of degassers include atmospheric and vacuum.  Atmospheric degassers use
turbulence to  separate bubbles from the drilling fluid,  and vacuum degassers use a combination of
turbulence, thin film,  and vacuum to perform the necessary separation.  Available degasser performance
data indicate that atmospheric degassers work satisfactorily on lower-weight, lower-viscosity water-based
fluids as well as  oil-based fluids.31 Vacuum degassers perform better than atmospheric degassers on
heavier fluids.  However, when the yield point (a Theological property) of the drilling fluid is below 10
lb/100 ft,2 shale shakers can remove enough of the gas to make degassing equipment unnecessary.29

5.5.4   Hydrocyclones
        The hydrocyclones used in drilling fluid circulation systems are static units that have no moving
internal parts.  Drilling fluid is fed tangentially into a hydrocyclone under pressure. Separation of the
solid particles from the liquid occurs in these units by means of centrifugal forces imposed on the influent
as it spirals down the  inside of the cone, which causes the heavier particles to move radially to the outer
                                            vn-2i

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edge of the stream.  The underflow solid particles exit through the bottom of the conical housing and the
liquid overflow passes upward near the center and out through the top. Figure VII-1 illustrates the flow
patterns  within  a properly operating hydrocyclone, as well as the  nomenclature  associated with
hydrocyclone technology.

       Hydrocyclones are typically referred to as  "desanders" and "desilters," depending on the size
particle they are intended to remove from the drilling fluid. Desanders are designed to remove particles
down to 40 microns in size, desilters remove down to 20 microns, and specially designed "microclones"
remove down to 10 microns (55 PR 23348). As a point of reference, human hair ranges in size from
30 to 200 microns.  Particles less than two microns are referred to as "clay," particles from two to 74
microns are "silt," and particles greater than 74 microns are "sand.29" While there is no industry standard
     *
for the distinction, desander cones generally range hi size from six to 12 inches in diameter, and desilter
cones range from two to five inches.32 The two-inch desilters are referred to as "microclones."

       The cones of a desander are often arranged  hi two parallel rows of three each, for a total of six
cones.  The liquid overflow from each cone enters a header which returns the combined overflows to the
next tank hi the active drilling fluid system. Desilters often consist of two rows of six cones each.  The
number of cones required depends on the size of each  cone and the type of solids being handled.  Cones
can also be arranged hi a circle around a common header.

       The problems experienced by hydrocyclones include clogged inlet or exit flow holes and improper
flow adjustment.  When the underflow opening  is blocked, solids will exit the cone through the top with
the liquid overflow and return to the active drilling  fluid system. When the feed stream is blocked, the
absence of the upward liquid flow can cause liquid overflow from adjacent cones to enter the cone from
the overflow header and be lost through the underflow opening. If the flow rate is improperly adjusted,
the hydrocyclone can become  overloaded with  solids,  thus causing solid particles to exit with the
overflow.

       In the 1970's,  "mud cleaners" were developed for weighted fluid systems for the purpose of
capturing solids that exit through the hydrocyclone underflow, thus allowing the weighting agents existing
with the solids to be returned to the system. A mud cleaner is a combination hydrocyclone-shale shaker
designed to remove sand-sized particles while returning medium and  fine silt as well as clay-sized
material to the active drilling fluid system.  One source states that the purpose of this separation step is
to reduce the amount of barite make-up required  by returning some solids that would  otherwise be
                                            VH-22

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                       OVERFLOW LIQUID
                          DISCHARGE
FEED INLET
 VORTEX FINDER
         VORTEX
                           SOLIDS
                         UNDERFLOW
                         DISCHARGE
                         Figure VII-1
                  Hydrocyclone Flow Patterns
                             VH-23

-------
discarded by the hydrocyclone.29 However, the return of the clay-bearing liquid should be stopped if
viscosity becomes a problem. Another source states that the purpose of the mud cleaner is to remove any
API sand (between 74 and 178 microns) that is not removed by the primary shale shakers, and offers
guidelines for proper operation.31 With recent improvements in shale shaker screens and hydrocyclone
performance, the need for mud cleaners must be determined on a case-by-case basis.

5.5.5   Centrifuges
        Centrifuges are used in solids separation systems to enhance the solids removal efficiency.  For
example,  use of centrifuges with standard rig equipment only, can boost a system's removal efficiency
from 30 to 40 percent.33 Two centrifuge designs are currently in use in the solids separation systems:
decanting centrifuges and perforated rotor centrifuges (also called "RMS" for rotary mud separator).

        Both the decanting centrifuge and the RMS  can be used  as "barite-recovery" units from which
the barite-laden solids are returned to the active drilling fluid system while the liquid (dewatering effluent)
is discharged or disposed. However, only the decanting centrifuge is used as a solids dewatering device,
from which relatively dry solids (fine cuttings) exit to a waste pile and the liquid may be returned to the
active drilling fluid system.  The RMS is not capable of removing enough liquid from the solids fraction
to be used as a dewatering step hi a  closed-loop solids control system.25 Additional discussion regarding
the applications of these units  is included in the next section.

        The decanting centrifuge, illustrated in Figure W-2, is equipped with a spiral conveyor housed
within a conical- or cylindrical-shaped bowl, both of which rotate hi the same direction.  The conveyor
rotates at a slower speed than that of the bowl and the relative rotation between the two dictates the solids
conveying speed.   Bowl rotation speeds range from 1,500  to 3,500 rpm,  and the conveyor speed is
determined by the gear ratio, which may be controlled.  A typical gear ratio is 80:1 where the conveyor
loses one revolution per 80 revolutions of the bowl, such that a bowl speed of 1,500 rpm will correspond
to a conveyor speed of 1,481 rpm and a relative conveying speed of 18.75 rpm.  Retention time within
the unit ranges between 10 and 80 seconds.28

        The performance of a decanting centrifuge is  measured by the feed rate  capacity,  the solids
discharge capacity, and the liquid discharge capacity. The feed rate depends on the solids content of the
feed, such that a feed with a high solids content will be limited by the solids discharge capacity, and a
feed with a low solids content will be limited by the liquid discharge capacity. The solids discharge
                                             vn-24

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                                  VII-25

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capacity depends on the rates at which solids are conveyed and discharged through the openings.  The
liquid discharge capacity depends on the capacity of the openings to discharge liquid of a certain depth
within the bowl. A major development in decanter bowl design occurred in the early 1970's when a
cylindrical or "contour" bowl was introduced. With this design, the increased bowl volume allows for
a higher feed rate with the same separation achieved by a conical design. Due to their additional cost,
contour bowl decanting centrifuges are typically used to dewater waste solids and recycle liquid back to
the active system, rather than for barite recovery.29

        The advantage of the RMS over the decanting centrifuge is that of portability. Because the solids-
laden underflow is liquid, it exits  the  unit through a pipe, thus  allowing  the unit to be positioned
                    »
anywhere in relation to the mud tanks.  In contrast, a decanting centrifuge must be placed so that the
solids fall directly into the receiving vessel (either the mud tanks or a waste container) or onto a solids
conveyor.

        Figure VII-3 illustrates the operation of a RMS. The feed enters the unit through an opening in
the outer housing. The perforated rotor is the only part that rotates, causing the heavier particles to move
radially toward the wall  of the outer  housing.  The liquid overflow enters  the  rotor through the
perforations and exits the unit through a pipe attached to the end of the rotor.  The solids-laden underflow
exits through a pipe located in the outer housing located at the opposite end from the feed inlet.  The rate
at which the underflow discharges is regulated by a choke valve in the discharge pipe.  This choke also
controls the amount of liquid exiting through the overflow discharge. Normal operation with a water-
based fluid requires a dilution of ten parts feed mud to seven parts dilution water. This water must be
compatible with the  active  drilling fluid.   Disadvantages  to  the RMS, as compared to a  decanting
centrifuge, include  a slightly higher barite loss, a  high demand  for dilution water,  and a high rate of
overflow discharge requiring disposal.28  However, the smaller RMS is applicable in situations over water
where there is no room to move a decanter around the  mud tanks.

5.5.6   Chemically Enhanced Centrifugation
        Chemically enhanced centrifugation (CEC)  is a term used to describe the addition of coagulation
and flocculation chemicals to enhance the effectiveness of a decanting centrifuge. CEC is also referred
to as "dewatering" because its purpose is to remove  as much of the liquid phase from  the feed to a
decanting centrifuge as is economically practical.  The use of CEC systems is cited  throughout current
literature23'34-35 and has been observed recently by EPA.1-2 The CEC step is typically located where it can
                                             VH-26

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process the discharge from other solids separation equipment such as desilters, desanders, and barite-
recovery centrifuges. The products of this dewatering step are a damp solid discharge and a clarified
liquid discharge.

        A CEC step is included in a CLS when it is necessary to remove colloidal particles (less than 5
microns) from the active drilling fluid system. If excess drill solids are not removed from a CLS, each
pass through the system causes the particles to degrade to smaller sizes making them increasingly difficult
to remove.   The mechanical  action of centrifugal  pumps  and shale  shakers contribute to particle
degradation.  An undesirable increase in drilling fluid weight and viscosity can occur when drill solids
degrade, due  to the increased surface area of the smaller particles.35  Increased surface area causes
increased water consumption.  Drill solids degradation can be controlled through the choice of drilling
fluid and additives, which  can consequently increase the efficiency of the mechanical solids control
equipment.  Additionally, removing colloidal solids  with a CEC step prevents returning detrimental
particles to the active drilling fluid system.

        Chemical treatment is needed to remove low-gravity particles (below 5 microns in size) which
are not removed by centrifugation alone.35  These small particles must first be treated with coagulant to
reduce the radius of their electric charge (called "zeta potential") which repels them from particles of like
charge.  Flocculent is then added to allow the coagulated particles to come  together (or "bridge") into
larger groups of particles that can be removed by  a decanting centrifuge.  High molecular weight
polyacrylamides are commonly used for flocculation.36

        The degree to which the discharged liquid is clarified depends on its intended disposition, either
as recycle back to the active drilling fluid system, or as waste to be disposed in some manner (including
annular injection,  surface discharge, or off-site  disposal). The solids discharged from a CEC unit are
typically 35 to 75 percent water by volume.23   If the discharged liquid is to be returned to the active
drilling fluid system, it must be compatible with the drilling fluid.

        Finally, it is important to note that onsite dewatering of spent drilling fluid is typically practiced
only when an economical onsite method of disposal or reuse is available for either the dewatering liquid
or the dewatered solids.  Such methods  include onsite land disposal of the solids and injection of the
liquid into either the annulus of the well being drilled or an available disposal well. When an economical
means of disposing or reusing the products of dewatering is not available, the least expensive method of
                                             VH-28

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handling these wastes is to remove the dewatering step and haul the spent drilling fluid to an offsite
disposal facility.

5.5.7   Closed-Loop Solids Control System Design
        To better understand the design of a closed-loop solids control system, it is important to discuss
the basic applications of each unit hi relation to the active drilling fluid circulation system. Table VII-6
describes various applications of solids separation equipment used with unweighted and weighted drilling
fluid systems.29  The distinction between whether a separation step is primary or secondary is determined
by the origin of the feed stream to a particular unit: a primary separation step is  fed directly from the
active drilling fluid circulation system, and a secondary step is fed from a primary step. Also of concern
is whether a separation unit is designed to handle a flow rate equal to the total drilling fluid circulation
rate ("full" flow) or a fraction thereof ("partial" flow).

        As shown in Table VTf-6, the location of a centrifuge within a solids control system varies
depending on its application. Both decanting and RMS centrifuges can be located as  primary separation
units when  used to recover barite  from a weighted drilling fluid.  In this primary application, the
centrifuge processes  the entire volume of recycled drilling fluid.   A decanting centrifuge, the only
centrifuge useful for dewatering purposes, may be located  hi a secondary position to receive either
desilter underflow or barite recovery centrifuge overflow.  This secondary separation  step processes only
a fraction of the total drilling fluids system volume.

        Figure VII-4 illustrates a system hi which the shale shakers, degasser, desander, and desilter, are
operated in  primary full-flow,  and the  decanting centrifuge is operated as secondary separation of the
hydrocyclone underflow.  This example is  an  unweighted drilling fluid application.   The  system
arrangement illustrated hi this  figure is typical of CLSs used to minimize solid waste volume and to
recycle water back into the active drilling fluid system. Table VII-6 demonstrates that there is often more
than one piece of equipment capable of performing a given separation task.  The choice of equipment is
usually the result of an analysis weighing the drilling program operating parameters and conditions against
overall  cost.  Current literature cites the fact that poor choices of solids  separation equipment were
prevalent  in the 1980s due to a general misunderstanding of the operating principles of each unit27'29
Ormbsy, 1983). However, it is apparent that more operators are taking a closer and more careful look
at solids separation technology as a means of reducing drilling fluid make  up  costs as well as drilling
waste generation and costs.
                                             VII-29

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       CLS systems change with operating conditions, even during the same drilling operation.  For
example, a CLS might consist of multiple shale shakers, hydrocyclones,  and a dewatering centrifuge
during the drilling of the surface interval of the hole where an unweighted water-base fluid is used and
the rate of drill cuttings production is greatest.  Then as the fluid is weighted up and the rate  of
penetration decreases, one of the shale shakers might be removed and a barite-recovery centrifuge might
replace the desilter.  If a formation of reactive clay is reached, flocculation chemicals and associated
equipment might be added at that point. Examples of these and other CLS design considerations are cited
in current literature.38

       EPA recently visited three drill sites in southern Louisiana, each of which utilized closed-loop
solids control technology.1A3 Figures VH-5, VH-6, and VTI-7 depict the solids control systems used at
the three sites.  The CLS used  at the GAP Energy drill site (Figure VH-5) included a CEC step  to
separate water from  spent drilling fluid for recycle back into the active drilling fluid system.  A unique
feature of the GAP site is that in addition to the solids  control equipment provided with the drilling rig,
another suite of solids control equipment was brought onsite by the solids control contractor.  Depending
on the requirements of the  drilling program, it is not uncommon for the solids control contractor  to
substitute part or all of the rig-supplied equipment. The ARCO drill site (Figure VH-6) included a barite
recovery centrifuge and a CEC step to separate and recycle water from the barite recovery centrifuge
overflow.  Chemical addition was minimized at ARCO to keep fluid treatment chemicals hi the recycle
water.  Thus,  the water samples obtained from the dewatering centrifuge at the ARCO  site were
significantly darker than the water samples  obtained at the GAP site. Based on visual inspection, samples
from both sites were free of  settleable solids. The CLS system used at the UNOCAL site (Figure VTI-7)
was similar to the ARCO system, except  that no chemicals were added to the feed to the dewatering
centrifuge. By comparison, then, the water sample from the UNOCAL site was considerably more turbid
than the samples obtained at the  other sites, containing total solids ranging from 23% to 24.7 %?

5.5.8   Solids Control System Efficiency
       Table VII-7 lists solids control system efficiencies from various literature sources. These numbers
are not statistically comparable due to the lack of information available regarding the methods by which
they were calculated.  However, it is interesting to observe that efficiency increases dramatically for
systems using chemically enhanced centrifugation over those relying only on mechanical means.
                                             VH-32

-------

Primary
Solids
Control
System
Cut
Ta
Fresh Mud
Mud "One in Uft Hooper
Pumps* of 7*me of __
>•->. Sampling Visit I I
Well Bcre 1 1
1 |
X"N^ j f*""^f
Sp X^N. \n Mud Quality
Jt— — - 1 2 Parallel « Tank
. 	 Shafe Shalcuri 	 	 	 \O
	 • ' 125M«* D«,as»r "

t 4^ 	 X



Cuttings 1 	 $ 	 1 •; f Make-Up *— Water
n?p n?H
Des«nder U U U U Dasiltr ^ !

>r Not In Us* At rma of 	 	 ,
_^NAug«r Sampling Visit
„ Waste Mud v
	 _ . . Tank 500 bbl

Secondary
Solids
Control
Systtm



,.„.,, « Unacceptable
^ 	 Shale Shaken Watte Mud
1 	 1 linear Motion " '* Tank 500 bbl *



>• T t " r3"L
Cuttings I I i i LZJ* Centrals
1 1 1 M 1 1 — • Po|ymer * — * "^
Oesander I) M M M Desilter | <4\-* \
Cutting.^^, *-r* Coagulant [3}- » ^e^lT"] ^*
, 	 _L 	 	 r*"*^"! Shal"ir _.*-— "^ Sarapl*
i/.-, 	 „„ > i — I Point
Cuiunui^— Mud

For Dis'ioMl Waste Mud

J
Figure VH-5
GAP Energy Mud Recirculation and Solids Control System

VII-33

-------
#
o
«o
f
Dewaicring
Centrifuge
Sump
£
o
*0
B «• _ iki
1 tl _*•»•*




III
                                                 §
                                                 I
                                                 s
                                                 o



                                                •9
                                                I
                                                •s
VII-34

-------

                                   0 +*
                                   as
  1
^ a !2
NN ft TH
N-1 .2  _
> -i-2
2"3«
                                 S
                                   o
                                   O
VII-35

-------
                                           TABLE VH-7
                 CLOSED-LOOP SOLIDS CONTROL SYSTEM EFFICIENCIES
Source
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Walters, 199133
Finke, Aug. 18, I99325
Finke, Aug. 18, 199325
Wojtanowicz, 198841
Wojtanowicz, 198841
Equipment llsetP
' * ''<.'&'",
1
2
1
3
3
1
2
4
5
6
6
Reported Efficiency
(vol. %)
31.13
37.58
30.40
88.31
87.97
21.73
45.53
72-75
>90
99.967"
99.945b
1       Classes of equipment:
        1:       Rig shale shakers, desander, and desilter only.
        2:       Rig equipment plus rental mud cleaner and centrifuge.
        3:       Unitized system; 2-4 parallel shale shakers, desander mud cleaner, desilter mud cleaner, microclone, low-
                speed centrifuge, and high-speed centrifuge.
        4:       Unitized system: two sets of shale shakers (in series), desander mud cleaner, desilter mud cleaner, and
                dewatering centrifuge.
        5:       Same as 4 plus flocculation chemicals and finer hydrocyclones.
        6:       Dewatering centrifuge and flocculation chemical addition only
b       Wojtanowicz studied different sizes of dewatering centrifuges with flocculation chemical addition and reported the best
        two efficiencies observed as measured by weight % of the solids in the centrifuge liquid effluent compared to the
        centrifuge feed.

        The difference in CLS  efficiencies with  and without chemical addition was apparent from the
systems observed during EPA's three drill site visits.  All efficiencies  reported by the solids control
contractors at these sites are general values for the equipment used, as illustrated hi Figures VII-5, -6,
and -7.  None of the efficiencies were directly measured on-site.  The solids control contractors at both
the GAP and ARCO sites reported efficiencies of approximately 90% when chemical flocculation was
used.1-2  The contractor at the ARCO site estimated efficiencies of 72-75% for the same equipment when
chemicals are not added.2  Similarly, an efficiency of 75% was reported for the system used at the
                                                VH-36

-------
UNOCAL site, where chemical flocculation was waved due to the availability of annular injection of the
decanting centrifuge overflow.2

       For the purpose of calculating compliance cost estimates,  the control technology method that
included closed loop solids control assumed an efficiency of 69%, based on data received from operators
in Cook Inlet in response to the 1993 Coastal Oil and Gas Questionnaire.6  Details of this and other CLS
assumptions are discussed hi Section X.5.2.

5.6   RESERVE  PITS
       Although their use is being phased out in much of the coastal Gulf of Mexico region, reserve pits
are still employed within the coastal subcategory.  A reserve pit is an earthen pit (lined or unlined) that
is used to contain drilling fluids and wastes  such as drill  cuttings, discharges from solids  control
equipment,  location drainage,  drilling  fluid, excess cement,  equipment  wash-down  water,  and
completion/workover fluids. In addition, the pit contents can  be used as reserve fluids in the event that
the drilling fluids in the active system are lost to the formation.23'39 Different types of earthen pits (lined
or unlined) are used at land-based drilling sites to manage both solid and liquid materials and wastes.

       Pit construction is based on the volume of waste to be placed hi the pit.  When sizing the pit, the
smallest practical volume should be used.  This minimizes the size of a land-based drilling location. In
addition  to  drilling wastes, the  reserve pit also accumulates  precipitation, thus a  smaller  pit  will
accumulate less over the course of drilling operations. An industry source indicated that the pit should
be designed using the assumption that two barrels of drilling waste will be generated for every foot of
hole drilled.40

       The pit must also be designed to prevent migration of pit contents.  This is achieved through the
use of adequate berm (levee) height to maintain freeboard hi the pit to prevent overflow of pit contents.
Louisiana regulations specify that a minimum two feet of freeboard be maintained in the pit at all times
(Louisiana Administrative Code, Statewide Order 29-B). In addition, the material used hi pit construction
must have a low permeability to prevent the pit contents  from leaching  during the course of drilling
operations.  If soil of adequate permeability is not available at the drilling site, the pit can be lined.

       In terms of site layout, two types of approaches to reserve pit construction are documented in
current literature.  The following sections discuss conventional reserve pits, which are the historically
                                             VII-37

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traditional approach to land-based drilling waste management, and "managed" reserve pit systems, which
reflect current industry efforts to segregate and rninimize wastes at the drill site.

5.6.1    Conventional Reserve Pits
       In a conventional reserve pit system, one pit is used to contain all of the drilling wastes at the
drilling location.  These wastes may include drill cuttings, spent drilling fluid, location drainage, excess
cement, equipment wash water, and completion/workover fluids. A footprint area of 200 feet by 300 feet
would normally be required for a conventional reserve pit at a drilling location with an approximate well
depth of 14,000 to  18,000 feet.42  Assuming a levee ten feet wide encloses the pit, the actual surface
dimensions of the pit would be 180 feet by 280 feet.  Pit construction companies  indicate that the average
conventional reserve pit is 200 feet by 200 feet.43-44  The pit is generally five to six feet deep but depths
of eight and ten feet are also used.44 The depth is limited by the height of the water table.  Figure VH-8
is a layout of a typical drilling location where a conventional reserve pit has been used to manage drilling
fluids and wastes.  Pit construction companies also indicate that they are frequently asked to segment or
partition the conventional reserve pits.43'44

5.6.2   Managed Reserve Pits
       The following text is adapted from a paper presented by EPA at the SPE/EPA Exploration and
Production Environmental Conference held in San Antonio, Texas in March 1993 45

       A managed reserve pit is  a waste segregation system that  uses two or more  pits to prevent
contaminated wastes from coming hi contact with uncontaminated materials. This can occur when using
a conventional  reserve pit while drilling into salt formations, if the well experiences a  salt-water kick,
or if oil-based fluid or fluid containing barite is used for drilling.46 The number and size of the individual
pits or cells depend on the  number and volume of distinct waste streams expected to be generated during
drilling operations.   For  instance, one cell  would be sized and  constructed as  the reserve pit to
accommodate the volume of drilling fluid required for the  operation plus an  adequate freeboard.  A
second cell would be constructed to manage cuttings, a third cell for rainwater runoff which may also be
used for rig wash and drilling fluid make-up water.  An important design consideration of the managed
reserve pit system is to ensure that natural communication between the cells is  prevented.  The transfer
of material between pits is handled using a dragline or manually controlled pumps.
                                             VH-38

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Location
Drainage
 Sump
                                         Ring Levee Ditch
                                            Figure VII-8
                Layout of a Drilling Location Utilizing a Conventional Reserve Pit
                                                                                             Location
                                                                                             Drainage
                                                                                              Sump
                                               VII-39

-------
        The entire managed reserve pit system can be constructed in an area that would be occupied by
a conventional reserve pit.42  Thus, while the overall footprint of the managed pit system is comparable
to that of a conventional reserve pit, a benefit is derived from keeping contaminated waste separated from
waste that might be recycled, reused, or disposed of at a lower cost.

        The operation of a managed reserve pit system is summarized as  follows.42  Solids and residual
drilling fluids are discharged to the shaker pit from the solids control equipment.  Solids from the shaker
pit are transferred to the storage pit and fluids are transferred to the settling pit along with rain water and
equipment wash water.  Following settling, the water is transferred to the treatment pit.  Reserve pit
treatment often includes lime addition to raise the pH,  followed by aeration by mixing the pit contents.
                    *
Such treatment clarifies the water by causing the solids to settle out. From the treatment pit, water is
recycled for continued use in the drilling operations or discharged.  The status of the managed pit system
is evaluated  on a daily basis and consists  of assessing the volume of  wastes in  the system  and the
distribution of these wastes among the pits in the system.

5.6.3   Pit  Closure and Site Restoration
        The regulations hi the States of Louisiana and Texas specify requirements for pit closure and
approved disposal methods for pit contents  (Louisiana Statewide Rule 29-B; Texas Statewide Rule 8).
The closure and disposal requirements (applicable to conventional and managed reserve pits) include:

        •      Dewatering and backfilling
        •      Solidification
        •      Landfarming and backfilling
        •      Injection (liquids)
        •      Burial on-site (solids)
        •      Treatment and discharge (liquids)
        •      Off-site commercial disposal.

        Disposal of drilling wastes can be accomplished via on-site annular injection, on-site landfarming
or burial,23-43 injection into a dedicated UIC  Class n disposal well (either on- or off-site) or hauling off-
site for land application at either  a centralized commercial  facility or a non-commercial site.
                                             vn-40

-------
       Following disposal of pit contents by any of the methods mentioned above, the reserve pit(s) is
backfilled with the earthen levee material and/or stockpiled soil from initial excavation of the pit(s). The
area may then be graded and restored to predrilling conditions.42'47

5.6.4   Reserve Pits on the North Slope
       Reserve pits have been the drilling fluids and cuttings disposal method of choice on the North
Slope since drilling began in that region. A discussion of the use of reserve pits and other land disposal
methods unique to Alaska is included in the document entitled "Oil and Gas Exploration and Production
Wastes Handling Methods hi Coastal Alaska".48  However, the  North Slope operators have recently
ceased using reserve pits and now rely on a grinding and injection system for drilling waste, described
in detail in Section 5.10.

5.7   CONSERVATION AND REUSE/RECYCLING
       The emergence of the closed-loop solids control system has provided operators with one of the
best means of reducing wastes generated and increasing recycling opportunities.  Additionally, reuse and
recycle is particularly desirable for fluids that have a hydrocarbon (diesel or mineral) liquid base because
they are expensive and cannot be discharged.  Economically attractive reuse practices for spent oil-based
and synthetic-based drilling fluids are:

       •       Mud company buys back the used drilling fluid which is hauled to shore, processed, and
               reused.
       •       The spent drilling fluid is treated with additional solids-suspending agents and used as a
               packer fluid.

5.8   LAND TREATMENT AND DISPOSAL
       This section discusses land-based treatment and disposal methods for drilling wastes at onsite and
centralized commercial  land treatment and disposal facilities.  In addition, this section discusses current
land disposal methods in Cook Inlet, Alaska.

5.8.1   Onsite Landfarming
       Onsite landfarming of drilling wastes is a potential option in cases where there is adequate space,
the soil conditions are suitable, and the  oil company is the land owner or has permission from the land
owner to landfarm.
                                             VII-41

-------
        The landfarming process consists of spreading a thin layer of the drilling waste over the landfarm
area. After spreading the drilling waste, the top soil and humus layer that was stripped in the preparation
phase of the drill site is spread over the drilling waste with a nitrogen fertilizer.  The drilling waste,
topsoil, and fertilizer are mixed through cultivation with a set of disks or a tractor-mounted tiller. The
cultivation/fertilizer cycle is repeated about twice a year for two or three years.  The time  period is
dependent on the quantity and the concentration of the drilling waste applied to the soil and the size of
the application area.49  The area can be successfully re-vegetated once the hydrocarbon content in the soil
is less than one percent and the chloride content in the soil is less than 1,000 ppm.49 Seed germination
studies have revealed that landfarming operations can be re-vegetated within 180 days.50

        Microbial decomposition is the major cause of hydrocarbon reduction in landfarming, although
evaporation and volatilization of the light-end hydrocarbons is probably significant.50  To  maximize
microbial decomposition, the most important aspects of landfarming are to maximize the surface contact
between the drilling waste and soil bacteria,  to aerate the soil/drilling waste mix to promote aerobic
decomposition, and to boost the soil microbe count by providing additional nutrients in the form of high
nitrogen fertilizer.  The two commonly used fertilizers are 34-0-0 and 11-51-0 (nitrogen-phosphorous-
potassium ratio).  Fertilizer application rates are typically on the order of 1,000 pounds per acre.49

        EPA's costing analysis of drilling waste disposal (Section X) did not include onsite landfarming,
but rather assumed that all wastes would be sent injected onsite (see Section 5.10) or sent to commercial
disposal facilities (see below).

5.8.2   Centralized Commercial Land  Treatment and Disposal Facilities
        Centralized commercial facilities for non-hazardous oil field wastes  (NOW) are treatment and
disposal and/or processing facilities that are located offsite from the drilling operation and are  generally
not operated by an oil and gas operator. In Louisiana, the Department of Natural Resources permits
NOW facilities and in Texas, the Texas Railroad Commission permits NOW facilities.

        Centralized commercial treatment facilities receive drilling wastes in vacuum trucks, dump trucks,
cuttings boxes or barges. In Louisiana, the transportation of drilling wastes in barges is common because
of the high frequency of drilling projects occurring hi coastal waters.  One major commercial waste
treatment facility in Louisiana has treatment facilities with barge access and several transfer stations with
barge access.51
                                              VH-42

-------
       Most of these facilities employ a landfarming technique whereby the wastes are spread over small
areas and are allowed to biodegrade until they become claylike substances that can be stockpiled outside
of the landfarming area. Another common practice at centralized commercial facilities is the processing
of drilling waste into a reusable construction material.  This process consists of dewatering the drilling
waste and mixing the solids with binding  and solidification agents. The oil and metals are stabilized
within the solids matrix and cannot leach from the solids. The resulting solids are then used as daily
cover at a Class I municipal landfill. Other  potential uses for the stabilized material include use as a sub-
base for road construction and levy maintenance.52

       The treatment process most often employed at land treatment facilities consists of a cycle which
includes application, treatment, certification, and excavation.  The treatment phase is designed to address
heavy metals, sodium imbalances in the waste, chloride concentrations in excess of the state regulatory
limits,   oil and grease  concentrations in excess of the regulatory limits and  moisture  contents.
Commercial landfarming facilities typically treat waste in cells designed for a particular amount of waste.
When the maximum amount of waste has been applied to a cell, the treatment process begins.53

       The landfarming  treatment process  for  one commercial NOW facility located in  southeast
Louisiana is described hi the following paragraphs.51'53

       The treatment cells at this facility range hi size from 1.5 to 6 acres and consist of above-ground-
level structures surrounded by berms built up to a height of 6 to 8 feet.  Topsoil is removed prior to cell
construction.  Clay deposits under  the topsoil serve as natural barriers to groundwater contamination.
The clay acts to prevent cell leachate drainage to groundwater and to prevent groundwater infiltration into
cells where there is a high natural water table.

       The application phase of treatment  consists of filling the cell with incoming drilling waste.  The
maximum application that the state of Louisiana allows is 15,000 barrels per acre  over a three month
period. Approximately 20 tons per acre of gypsum or calcium sulfate is spread and mechanically mixed
with the waste. Through a classic ion exchange chemical reaction, the calcium from gypsum or calcium
sulfate replaces the sodium on the  soil particles.  This step is necessary in reducing the exchangeable
sodium percentage (ESP) of the soil.  The ESP is a measure of the number of exchange sites on the soil
particles which are occupied by sodium ions.  The Louisiana regulations for landfarming limit the ESP
concentration to 25 percent.
                                             ¥11-43

-------
       The next step of the treatment phase is flooding of the cell to remove the soluble salts from the
soil-waste matrix.  Approximately 6 to 12 inches of water is pumped onto the cell and mixed with the
waste with mechanical equipment.  The higher salt concentrations in the waste drive the concentrations
up hi the fresh water, thereby lowering the concentrations hi the waste. Once the chloride concentrations
reach an equilibrium and the water ceases to absorb more salts (at approximately 1,500-2,000 ppm), the
solids are allowed to settle out of the water and the water is pumped out of the cell into a surface
impoundment prior  to injection.   The  salt removal  step is an  important step in  maximizing  the
biodegradation process because many microorganisms do not function well in a high salt environment.
The treatment process has taken about four to six months at this point.

       The next step of the landfarming process consists of treatment of the oil  and grease content of
the waste.  The oil and  grease content is lowered by mixing the  waste with  the soil and through
biodegradation.  This treatment step consists of cultivation of the soil/waste mixture to improve exposure
to the sun and air which maximizes biodegradation.  The matrix in the cell is cultivated twice a month
for a period of six to eight months.

       Once all the material in the cell is treated and all the analytes are below the state-required
limitations, the "cleaned"  clay-like product is transferred from the cell to a stockpile area onsite. This
material is used  to maintain or construct new berms around the cells.

5.8.3   Cook Inlet Land Disposal
       There are currently no commercial land disposal facilities permitted in Cook Inlet.  There are
however, several non-commercial waste disposal facilities available to some Cook Inlet operations. These
are: Marathon Landfill at  Kustatan (west side of Cook Inlet), UNOCAL grinding and injection wells in
Kenai gas field  (project discontinued due to mechanical failure of the injection  well), and UNOCAL
Beaver Creek Landfill on the Kenai Peninsula.  Marathon and UNOCAL jointly operate the disposal site
at Kustatan,  located 3 miles north of the Trading Bay facility.68  Table Vtt-8 summarizes  the waste
disposal options available  to operators in Cook Inlet.

       The site at Kutatan is a landfill used for the disposal of drilling wastes and tank bottoms. This
facility services the same platforms as do Trading Bay and Granite Point facilities.68 The landfill consists
of lined cells into which wastes are placed  and stabilized.  The size of the landfill is 16 modules, each
module containing 4 lined  cells, for a total size of 64 cells. Each cell can hold approximately 2,000 cubic
                                             VII-44

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                                       TABLE VH-8
             SUMMARY OF WASTE DISPOSAL OPTIONS FOR OPERATORS
                                    IN COOK INLET68
Operator
Marathon
Unocal
Shell Western
Phillips
ARCO
Solid Waste
Disposal Site
Kustatan Waste Disposal
Site
Beaver Creek Waste
Disposal Site
Clean Soils, Inc. (rotory
kiln) - private company
Kustatan Waste Disposal
Site
Kenai Gas Field
Only commercial sites in
the lower 48 states
Only commercial sites in
the lower 48 states
Only commercial sites in
the lower 48 states
Location
West side of Cook
Inlet
Beaver Creek
Production Facility
West side of Cook
Inlet
West side of Cook
Inlet
West side of Cook
Inlet
-
-
-
Capacity
615,680 bbl
14,000 cu yds
(remaining)
Max.: 40 tons/hr
feed rate
615,680 bbl
Pilot project
-
-
-
Restrictions
Limited to waste
generated in the
Trading Bay unit by
Marathon and
Unocal
Limited only for
wastes generated at
Beaver Creek
(federal wildelife
refuge)
Used for solids only
(dewatering
required).
Operating
agreement with
Marathon
Project stopped in
1993 due to
downhole
mechanical failure
-
~
-
yards or 9,620 bbl of material, for a total capacity of 615,680 bbl. Once a cell has reached full capacity,
it is covered and closed.  When one module reaches capacity, a new module is developed.68  To date,
only 19,240 bbl of wastes have been disposed at Kustatan.69  This facility is only accessible and operated
in the summer months because of its location and of the harsh climate conditions in Cook Inlet. Due to
the shallow waters on the west side of Cook Inlet, only barges can be used to transport the wastes to the
west side of Cook Inlet for disposal.
                                          VH-45

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5.9    SUBSURFACE INJECTION OF DRILLING FLUIDS
        Subsurface injection of spent drilling fluids is an established oil field practice.  If the solids
control system at a well includes a dewatering step, the resulting liquid stream may also be injected if
it is not being recycled into the drilling fluid system. Subsurface injection can be either through the
annulus of an existing casing system, as shown in Figure Vtt-9, or into  a UIC Class II injection well.
The process  consists of pumping the fluid down hole into a receiving formation.   Prior to injection,
drilling fluids are typically screened using a shale shaker to remove any large particles.  The typical
drilling fluid injection system consists of a shale shaker, mud tank, and pump.  Triplex (three-plunger)
pumps are commonly used as injection pumps. Maintenance of all flow  rates, pressures, and injection
zones is the responsibility of the oil company in accordance with the requirements of the permit.  Annular
injection is not feasible in cases where there is a bad  cement job or in areas where there is potential of
affecting a sensitive production zone.54

5.10   GRINDING AND SUBSURFACE INJECTION OF DRILLING WASTE
        The process of grinding and injection of drilling muds and cuttings was developed by operators
on the North Slope Alaska in mid-1980's.  This process is currently being used on the North Slope for
the injection of spent drilling fluids and cuttings.  EPA has recently learned that several similar projects
have also occurred or are planned in coastal areas in the Gulf of Mexico and California,55 and in the
North Sea56 for the injection of drilling fluids and cuttings.  The following  sections discuss these projects.

        The  critical parameters that affect the performance of any grinding and injection system are:
drilled solids particle size, the injectable fluid density and viscosity, percent solids in the injectable fluid,
injection pressure, and the characteristics of the receiving formation.  These parameters and their effect
on the design of the grinding and injection system are discussed in detail hi the following sections.

5.10.1  Cuttings Processing System and Injection
        The  cuttings grinding system consists of three separate unit processes: screening, grinding, and
slurrification.  On the North Slope, cuttings are first conveyed to a large triple-deck classifier where the
cuttings are washed with high pressure  water to remove residual drilling fluid and are sorted according
to size.  The underflow from the classifier, which contains particles smaller than 74 microns, and the
washwater are sent to the injection slurry pit.  The  overflow, which contains particles larger than 74
microns, are further processed in a ball mill grinding unit.57
                                              VII-46

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Ground
Surface
 0 ft
Approximate
Drilled Depth
  at End of
  Sampling
                                                                             Annular Injection
          Drilling Muds
         and Cuttings to
            Surface
                   11.158  ft

                   11,500  ft
                       11,990 ft
                                                            16 in. dia. Conductor Pipe
                                                            Driven from 0 to 69 ft
                                                            13.5 in. Drill  Bit
                                                            10.75 in. Casing
                                                            Set from 0 to 2,530 ft
                                                              Zone where
                                                              Annular  Injection
                                                              of Drilling Waste
                                                              May Occur
                                                                :  Muds and Cuttings

                                                          -:v:,
                                                          
-------
       The grinding unit is a 30-inch by 34 inch chamber that contains 3,000 Ib of 1.5-inch forged steel
balls. The cuttings are fed into this chamber for size reduction.  In order to achieve the required particle
size, the chamber  is vibrated at 1,200 cycles with and amplitude of 3/4 inch.57  After size reduction in
the ball mill, cuttings are pumped to a hydrocyclone for further classification.  Particles larger than 74
microns are returned to the ball mill for repeated grinding, while particles smaller than 74 microns are
sent to the injection pit.

       The injection pit has a capacity  of 500 barrels  and is mechanically agitated to maintain a
homogeneous  slurry.  Chemicals such as bentonite and extenders  are added to the pit to increase the
solids carrying property, or viscosity of the injection fluid.  The injection fluid is typically maintained
at a funnel viscosity of 100 seconds per quart.57

       The final step of this process is the injection system.  Ground and slurried cuttings are pumped
from the injection pit to the injection pump(s) by hard chrome-lined  centrifugal pumps.57 The centrifugal
pumps have a pumping capacity of 500  gallons per minute  (gpm).   BPX  uses  a pair of positive
displacement piston injection pumps,  each with a pumping capacity  of 210 gpm.  These are 165-
horsepower (hp) triplex pumps driven by a 150 hp electric motor  through a four-speed gearbox. The
injection pressure  varies between 600 to 1,000 psi depending on the weight of the fluid being injected.
Typically, the density of the injection fluid is maintained within 10 to 11 pounds per gallon (ppg) with
a solids content of 25 to 30% .^

       Successful grinding and injection projects hi the Gulf of Mexico coastal region were cited by one
company licensed  to perform this technology.58  Drill cuttings generated from drilling operations in the
coastal Gulf of Mexico region often consist of bentonitic shale  formations which break up easily when
hydrated and subjected to high shear pressures.  Because of these cuttings properties, the grinding and
injection systems employed hi the Gulf of Mexico coastal projects take advantage of the transfer pumps'
shear force for size reduction.59 Freshwater or seawater are added to the cuttings stream before and after
size reduction. After size reduction, the cuttings slurry is further mixed with freshwater or seawater so
that the injectable fluid has a  funnel viscosity of 70 to 90 seconds per quart and a density of 11 to 12
PPS-58
        Similar grinding and injection processes were successfully tested on other drilling fluid systems,
mainly on oil-based fluids and cuttings.56-60'61 With the new grinding and injection technology available
and proven on oil-based fluids and cuttings, the use of oil-based fluids followed by grinding and injection
                                             vn-48

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may prove in some cases to be more economical than land disposal, thus further reducing the overall well
cost.  The cuttings processing systems employed on these projects are similar to the system used on the
North Slope.  Variations of this process consist of the type of screens used, elimination of cuttings
washing systems, and the type of grinding equipment used.  Rotating ball mills instead of vibrating ball
mills  have been successfully used on  offshore platforms.  Although rotating  ball mills  are  high
maintenance pieces of equipment, they are usually employed on offshore platforms for grinding large and
relatively high density material.  Vibrating ball mills are not typically used on offshore platforms because
of the possible structural impact of the weight and of vibration.13'56

        Cuttings  washing is practiced only where water-based drilling fluids  are used  in drilling
                      *
operations, such as on the North Slope, because of the potential reuse of these cuttings as construction
material.57

5.10.2 Receiving Formation Evaluation-North Slope Operations
        The injection mechanism for solids-laden fluids differs from that used for solids-free liquids such
as produced water.   Produced water is injected at  a pressure that does not fracture the receiving
formation. On the North Slope, successful cuttings injection operations demand that a fracture be created
hi the receiving formation before injection of the cuttings slurry can occur.  Without a fracture, the solids
in the slurry would quickly plug up the pore spaces in the formation.62

        Therefore, the success of the grinding and injection technology depends on the proper selection
of the receiving formation.  In general, the desired characteristics of the receiving formation are to be
unconsolidated,  of high porosity (typically  20%), high permeability  (typically 0.5 Darcy) material of
sufficient thickness (typically 33 feet) and at a sufficient depth not to  affect the surrounding environment.
The specific values, however, change for different drilling locations.63

        Injection of a  homogeneous  cuttings slurry can be achieved through a dedicated  wellbore or
through the annular  space between a string of casing and the exposed formation.  The slurry is pumped
at a specified rate into the wellbore or the annulus.  When the downhole pressure of the fluid exceeds
the formation pressure, the  formation fractures  and the cuttings slurry  flows into the fissure.  The
pumping operation continues until all slurry is injected into the formation.
                                             VH-49

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        The optimum injection pressure depends on the characteristics of the receiving formation,  and
should be continuously monitored.  The mechanisms of inducing a fissure in the formation, such as its
mode of propagation, its size, its containment, and its impact on nearby wellbores, should be well
understood before injecting the cuttings slurry.  Fracture modeling can be used to estimate the size  and
shape of the injection fracture.  A new 3-dimensional model has been developed to optimize the design
of hydraulic fractures and to simulate drill cuttings injection.64

        Subsurface geology of the North Slope is uniform throughout the area, making disposal of drilling
wastes by injection an attractive alternative to land disposal.  North Slope geologic stratification is more
suited to injection because of the shale and sandstone formations, and because of the permafrost which
underlies most of the North Slope.

        Shale,  which is composed entirely of clays, is  a relatively plastic and  low permeability rock.
These properties make it a good confining zone.  The fracture gradient for shale ranges from 0.8-0.9
psi/ft. For comparison purposes, sandstone (a rock composed of sand sized rock and mineral fragments)
has a fracture gradient of 0.55-0.65 psi/ft.65 The lower the fracture gradient, the easier the formation  will
fracture. Therefore, sandstone is a better receiving formation than shale because it fractures more easily,
while shale is a better confining formation.

        Of importance to the oil and gas operations on the North Slope is the continuous permafrost
which descends from the surface to depths between 1,000 and 2,000 ft.57  The permafrost provides a  low
permeability barrier so that the injected wastes  do not migrate upward towards the surface.

5.11   AVAILABILITY OF INJECTION WELLS
        As stated above, the uniformity of the underlying geology of the North Slope makes injection of
drilling wastes a viable disposal method throughout in that area. In Cook Inlet, Alaska,  drilling wastes
were injected during a 1994 project at a platform operated  by  Shell, thus demonstrating that injection
zones are available  in Cook Inlet.66  In the coastal Gulf of Mexico area, a statistical analysis  of the
responses to the 1993 Coastal Oil and Gas Questionnaire  indicates that  122 new production drilling
projects, or 65% of the 187 new production wells drilled hi 1992,6 utilized annular injection for disposal
of drilling wastes.67
                                             vn-so

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6.0   REFERENCES

1.     U.S. EPA. "Sampling Trip Report, to Gap Energy Drill Site, Holmwood, Louisiana, June 16-17,
       1993." JuneS, 1994.

2.     U.S. EPA.  "Sampling Trip Report to ARCO Oil and Gas Drill Site, Black Bayou Field, Sabine
       Wildlife Refuge, Lake Charles, Louisiana, July 21-22, 1993." October 21,  1994.

3.     U.S. EPA. "Trip Report to UNOCAL Intracostal  City,  Louisiana, September 8-9,  1993."
       Freshwater Bayou, Vermilion Parish, Louisiana.  January 25, 1995.

4.     U.S. EPA. "Development Document for Effluent Limitations Guidelines and New Source
       Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source
       Category (Final)." January 1993.

5.     Offshore Operators Committee.   Alternate Disposal Methods for Mud and Cuttings.  Gulf of
       Mexico and Georges Bank, December 7, 1981.

6.     U.S. EPA.  Responses to the 1992 "Coastal Oil and Gas Questionnaire." OMB No. 2040-0160.
       July 1993. (Confidential Business Information)

7.     Erickson, Manuela, SAIC, Communication  with Lee Dewees, M-I Drilling Fluids, regarding
       Prices for Mineral Oil and Barite, August 16,  1994.

8.     Chilingarian, G. V., and P. Vorabutr. Drilling and Drilling Fluids. Elsevier Science Publishers
       B.V., Amsterdam, The Netherlands.  1983.

9.     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)

10.    SAIC.   Worksheet entitled "Calculations for Average Density of Dry Solids in Cook Inlet
       Drilling Mud."  June 6, 1994.

11.    SAIC.  Worksheet entitled "Estimation of Organic Concentrations in Cook Inlet Drilling Mud."
       June 7, 1994.

12.    SAIC.   Worksheet entitled "Calculations for Average  Density of Cuttings in Cook Inlet."
       September 7,  1994.

13.    Marathon Oil Co. and Unocal Corp.  "Drilling Waste  Disposal Alternatives - A  Cook Inlet
       Perspective, Cook Inlet, Alaska." March 1994.

14.    Moore, P.L.,  "Drilling Practices Manual," 2nd edition, PenriWell, 1986.

15.    SAIC.  Worksheet entitled "Calculation of Average Mud Weight for Cook Inlet Drilling Mud."
       April 13, 1994.
                                           VII-51

-------
16.    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)

17.    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.

18.    Schmidt, R., Unocal, Correspondence to Manuela Erickson, SAIC, regarding drilling fluids not
       acceptable for discharge, July 11, 1994.

19.    SAIC,  "Preliminary Statistical Analysis  of Permit  Compliance Monitoring  Records for the
       Toxicity of Drilling Fluids in Alaska (Draft Final Report)," September 30, 1994.
                   *
20.    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  U," prepared  for  Offshore Operators  Committee, December 24, 1986.  (Offshore
       Rulemaking Record Volume 60)

21.    Wojtanowicz,  Andrew  K.   "Environment Control Potential  of  Drilling Engineering:   An
       Overview of Existing Technologies" (SPE-21954) hi 1991 SPE/IADC Drilling Conference.

22.    Lai, M. and N. Thurber.  "Drilling Wastes Management and Closed-Loop Systems"  hi Drilling
       Wastes, Proceedings of the 1988 International Conference on Drilling Wastes, Calgary, Alberta,
       Canada.  F.R. Engelhardt, et al., editors.  April 5-8, 1988.

23.    Longwell  ffl, H.J.,  and TJ.  Akers.   "Economic Environmental  Management of Drilling
       Operations" (IADC/SPE23916) in Proceedings: 1992IADC/SPE Drilling Conference. February
       18-21, 1992.

24.    Hanson, Paul M., et al. "A Review of Mud and Cuttings Disposal for Offshore and Land Based
       Operations." Circa 1986.

25.    Finke, Bob.  Gauthier Brothers, Inc.  Personal communication with Jamie Mclntyre of SAIC
       regarding solids control equipment. August 18, 1993.

26.    Gauthier Brothers. Equipment and Services Catalog.  1993.

27.    Cagel, W.S.   "Solids  Control Update:  Part 1-Shale Shaker and Centrifugal Pumps" in
       Petroleum Engineer International. July 1987.

28.    Ormsby, George  S.  "Drilling Fluid Solids Removal" in Drilling  Practices Manual, second
       edition, Preston L. Moore.  Pennwell Books, Tulsa, Oklahoma. 1986.

29.    Ormsby, George  S.  "Drilling Fluid Solids Removal" in Drilling and Drilling Fluids. G.V.
       Chilingarian and P. Vorabutr. Elseyier Science Publishers B.V., Amsterdam,  The Netherlands.
       1983.
                                           VH-52

-------
 30.     Walters, Herb.  Swaco Geolograph.  Personal communication with Jamie Mclntyre of SAIC
        regarding solids control systems. September 21, 1993.

 31.     Cagel, W.S.  "Solids Control Update: Part 2-Degassers, Hydrocyclones, and Mud Cleaners"
        in Petroleum Engineer International. July 1987.

 32.     Kirsner, Jeff.  Attachment to a letter to Ron Jordan of EPA-EAD:   "Short-Course on Solids
        Control," Baroid Drilling Fluids, Inc. September 5, 1991.

 33.     Walters, Herb.  "Dewatering of Drilling Fluids" in Petroleum Engineer International. February
        1991.

 34.     Malachosky, Ed, et al.   "Impact of Dewatering Technology on the Cost of Drilling-Waste
        Disposal" in Journal of Petroleum Technology. June 1991.

 35.     West, Gary and Bob Pharis. "Dewatering Cuts Drilling Mud and Disposal Costs" in Oil and Gas
        Journal, September 30, 1991.

 36.     Neiderhardt, Dietmar.  "Dual Centrifuge System with Flocculation Improves Barite Recovery"
        in Oil and Gas Journal. March 15, 1993.

 37.     Finke, Bob.  Gauthier Brothers, Inc.  Personal communication with Jamie Mclntyre of SAIC
        regarding solids control equipment.  November 1, 1993.

 38.     Navarro, Armando R., "Innovative Techniques Cut Costs in Wetlands Drilling," in Oil and Gas
        Journal. October 14, 1991.

 39.     Interstate Oil Compact Commission.  "EPA/IOCC Project on State Regulation of Oil and Gas
        Exploration and Production Waste." December 1990.

 40.     Hall, Charles  R. and Richard A. Spell.  "Waste Minimization Program Can  Reduce Drilling
        Costs" in Oil and Gas Journal. July 1, 1991.

 41.     Wojtanowicz, Andrew K.  "Modern Solids Control: A Centrifuge Dewatering-Process Study" hi
        SPE Drilling Engineering. September  1988.

 42.     Pontiff, Darrell, et al.   "Theory, Design and Operation of An Environmentally Managed Pit
        System" hi Proceedings  of the First International Symposium on Oil and Gas  Exploration and
        Production Waste Management Practices. September 10-13, 1990.

 43.     Sonnier, Kirby. Tanner Construction Company. Personal communication with Susan Roman of
        SAIC regarding the costs to construct reserve pits.  October 15, 1993.

44.     Dishman, Jamie. Bockmon Construction Company.  Personal communication with Susan Roman
        of SAIC regarding costs  to construct reserve pits. October 15, 1993.

45.     Derkics, Daniel and Steven  Souders.    "Pollution Prevention  and  Waste  Minimization
        Opportunities for Exploration and Production Operations"  (SPE 25934) in SPE/EPA Exploration
        and Production Environmental Conference. March 7-10, 1993.
                                           VH-53

-------
46.    Spell, Richard, et al. "Evaluation of the Use of a Pit Management System" in Proceedings of
       the First International Symposium on Oil and Gas Exploration and Production Waste Management
       Practices.  September 10-13, 1990.

47.    Ehrhart, Joe.   Chessher Construction Company and Newpark  Resources, Inc.  Personal
       communication with Susan Roman regarding costs to construct reserve pits.  October 15, 1993.

48.    SAIC. "Oil and Gas Exploration and Production Wastes Handling Methods in Coastal Alaska."
       January 6, 1995.

49.    Zimmerman, Peter K. and James D. Robert. "Oil-based Drill Cuttings Treated by Landfarming"
       in Oil and Gas Journal. August 12, 1991.             v

50.    Barker, G.W., et al. "Land Treatment of Petroleum Hydrocarbon-Based Drill Cuttings:  Pilot
       Scale Field Study" (SPE-24565) in SPE Annual Technical Conference and Exhibition: October
       4-7. 1992.

51.    U.S.  EPA.  "Trip Report to Campbell Wells Land Treatment, Bourg, Louisiana, March 12,
       1992."  May 29, 1992.

52.    Clark; Phillip. Newpark Environmental Services, Inc. Personal communication with Joe Dawley,
       SAIC, October 15, 1993.

53.    Brazzel, Jerry.  Campbell Wells.  Personal communication with Joe Dawley, SAIC, regarding
       landfarming process, October 6, 1993.

54.    Hargrave, Johnny.  Central Industries.   Personal communication with Joe Dawley,  SAIC.
       October 8, 1993.

55.    Wiedeman, Allison. U.S. EPA. Memorandum regarding "Coastal Oil and Gas Activity in CA,
       AL, MS, and PL."  September 6, 1994

56.    Schuh, P.R., Secoy, B.W., and Sorrie,  R.  "Case History: Cuttings Reinjection on the Murdoch
       Development Project in the Southern Sector of the North Sea." SPE 26680.  Presented at the
       Offshore European Conference in Aberdeen, September 7-10, 1993.

57.    BP Exploration.   "Supplemental Information, North Slope Operations," November 12,  1993.

58.    Mechanical Slurry Disposal (M.S.D.),  Inc. Product Catalog.

59.    Herbert, Terry.   MSD,  Inc.  Communication with Joe Dawley, SAIC,  regarding Cuttings
       Slurrification and Injection Costs, November 15, 1993.

60.    Louviere, R.J., and Reddoch, J.A., "Onsite Disposal of Rig-Generated Waste via Slurrification
       and Annular Injection,"  SPE 25755,  Presented at the 1993 SPE/IADC Drilling Conference,
       February 23-25, 1993.

61.    Crawford, H.R., and Lescarboura, J.A., "Drill Cuttings Reinjection for Heidrun:  A Study," SPE
       26382, Presented at the 68th Technical Conference SPE in Houston, TX, October 3-6, 1993.
                                           VII-54

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62.    Andersen,  E.E.,  Louviere,  R.J.,  and  Witt,  D.E.    "Guidelines  for Designing  Safe,
       Environmentally Acceptable Downhole Injection Operations."  SPE 25964.  Presented at the
       SPE/EPA Exploration & Production Environmental Conference, San Antonio, TX., March 7-10,
       1993.

63.    Dusseault, M.B., and Bilak, R.A.  "Disposal of Produced Fluids by Slurry Fracture Injection."
       Geomechanics  Group Publication.  Presented at  the 4th Petroleum Conference of the  South
       Saskatchewan Section, October 18-20, 1993.

64.    Van den Hoek, PJ.  "New  3D Model for Optimized Design of Hydraulic Fractures and
       Simulation of Drill-Cutting Reinjection."  SPE 26679.  Presented at the Offshore European
       Conference in Aberdeen, September 7-10,  1993.

65.    AOGCC (Alaska Oil and Gas Conservation Commission).  Letter to Manuela Erickson, SAIC,
       regarding "disposal injection of UIC Class II waste within the State of Alaska."  October 27,
       1993.

66.    Erickson, Manuela.  SAIC.  Personal  communication with Lori Litzen, Shell Oil Company,
       regarding information on the Shell platforms in Cook Inlet, Alaska. April 18,  1994.

67.    Henderson, Scott.   SAIC.  Memorandum to Jamie Mclntyre,  SAIC, regarding the "Estimated
       Number of Wells using Annular Injection" from the 1993 Coastal Oil and Gas Questionnaire.
       December 20, 1994.

68.    Allison Wiedeman, U.S. EPA, "Trip Report to Alaska Cook Inlet and North Slope Oil and Gas
       Facilities, August 25-29, 1993."  August 31, 1994.

69.    Safavi, B., SAIC,  Calculations of Landfill Capacity in Cook Inlet, September 29,  1994.
                                           VII-55

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                                    SECTION VIII
                               PRODUCED WATER-
 CHARACTERIZATION, CONTROL AND  TREATMENT TECHNOLOGIES
1.0   INTRODUCTION
       The first three parts of this section describe the sources, volumes, and characteristics of produced
water from coastal oil and gas production activities. The final part of this section describes the treatment
technologies available to reduce the quantities of pollutants in produced water discharged to surface
water.

2.0   PRODUCED WATER SOURCES
       Produced water is the water (brine) brought up from the hydrocarbon-bearing strata during the
production of oil and gas.  Produced water includes: the formation water brought to surface with the oil
and gas, the injection water used for secondary oil recovery that has broken through the formation,  and
various well treatment chemicals added during production and the oil/water separation process.

       Formation water, which' comprises the bulk of produced water, is found hi the same rock
formation  as is the crude oil and gas.  Formation water is classified as meteoric,  connate, or mixed.
Meteoric water comes from rainwater that percolates through bedding planes and permeable layers.
Connate water (seawater in which marine sediments were .originally deposited) contains chlorides, mainly
sodium  chloride  (NaCl), and dissolved solids  hi concentrations  many tunes greater than common
seawater. Mixed water is characterized by both a high chloride and sulfate-carbonate-bicarbonate content,
which suggests multiple origins.

3.0   PRODUCED WATER VOLUMES
       Produced water is the highest volume waste source in the coastal oil and gas industry.  The total
volume of produced water being discharged by the coastal oil and gas industry is 227.5 million bpy (or
623,000 bpd). The volume of wastewater generated by the oil and gas industry is somewhat unique hi
comparison with industries in which wastewater generation is directly related to the quantity or quality
of raw materials processed. By contrast, produced water can constitute from 2 percent to 98 percent of
                                          vm-i

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the gross hydrocarbon fluid production at a given well or production facility.  In general, the percent of
produced water volume to oil and gas is small during the initial production phase when hydrocarbon
production is the greatest, and increases as the formation approaches hydrocarbon depletion.  Produced
water volumes are generally greater for facilities producing oil or a combination of both oil and gas as
compared to gas-only facilities.  The volume of produced water at a given facility is a site-specific
phenomenon.  In some instances, no formation water is encountered while in others there is an excessive
amount of formation water encountered at the start of production.

        As discussed hi Section IV, the entire volume of produced water generated hi the North Slope
region of Alaska and the coastal region of California is injected for waterflooding, and therefore will not
be discussed hi this section. In addition, hi the Gulf of Mexico states of Florida and Alabama, all coastal
facilities inject their produced water, primarily for  disposal, and therefore, are not discussed hi this
section.  Produced water characteristics for those coastal areas  discharging it (i.e.,  Cook Inlet, Alaska
and Texas and Louisiana) are discussed below.

3.1    GULF  OF MEXICO
        For the Gulf of Mexico region, the three sources of data that are available  for produced water
volumes are:  the 1993 Coastal  Oil and Gas Questionnaire database, the Gulf  of Mexico state permit
discharger database and the 1992 EPA 10 production facility data. These three data sources are discussed
hi detail hi  Section V.  Because the Coastal 308 Questionnaire was not a census, the data concerning
produced water volumes and other parameters from the survey were statistically extrapolated as estimated
industry-wide averages.   The Gulf of Mexico  state permit discharging  facilities database contains
comprehensive facility-specific data, but only includes facilities that are discharging.  The 1992 EPA 10
production facility study contains  data from only 10 selected facilities that primarily inject  produced
water.  The following is a summary of the produced water flow data from these three sources.

        According to the statistical analysis of the EPA 1993 Coastal Oil and Gas Questionnaire, hereafter
referred to as the coastal questionnaire statistical results, the average produced water generation rate from
a coastal facility was 1,923 barrels per day (bpd) for facilities that inject produced water and 2,069 bpd
for facilities that surface discharge produced water.1

        Table  VDI-1  presents  the produced water volumes, treatment systems information,  and
hydrocarbon production from the production facilities sampled hi EPA's 10-facility study. Details of this
                                             vm-2

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study are discussed in Section V.4.  All of these facilities, except for Texaco Port Neches, disposed of
their produced water via subsurface injection. As can be seen from this table, no correlation is apparent
between oil or gas production and produced water volumes.

       Appendix XI-3 presents the database of the 216 coastal discharging facilities in the Gulf of
Mexico.  As can be seen from these data, produced water volumes for discharging facilities range from
1 bpd to 144,000 bpd. The average produced water volume for discharging facilities is 2,265 bpd.  The
total volume of produced water discharged in the Gulf of Mexico is 489,237 bpd.

3.2   ALASKA
       Table Vni-2 presents the produced water volume and treatment data for Cook Inlet.  As noted
in Section IV, there are five platforms that discharge directly into Cook Inlet while the remaining nine
pipe  their combined production fluids (hydrocarbon and  water)  to  one of three  shore-based
separation/treatment facilities. The total volume of produced water discharged from platforms in Cook
Met is 1,860 bpd, and the overall total including the three shore-based facilities is 134,182 bpd.  The
three shore-based facilities discharge approximately 96 percent of the  Cook Inlet produced water, not
including the Dillon platform discharges.

4.0   PRODUCED WATER COMPOSITION
       Since the 1979 promulgation of the Coastal Oil and Gas BPT Effluent Limitations Guidelines,
EPA has conducted several produced water characterization studies. A number of these studies were used
in the development of the 1993 Offshore Guidelines.   These studies  are the 30 Platform Study, the
California Sampling Program, and the Alaska Sampling Program,  and are described hi detail ha the
Offshore Development Document.2 Therefore, data from these studies will not be presented individually
La this document.  In some cases, data summarized hi the Offshore Development Document have  been
used  in the tables presented in  this section,  particularly  with respect to  certain  treatment  system
performance data and the composition of produced water hi Cook Inlet.  For the Gulf of Mexico region,
the EPA 10 Production Facility Study is the source of produced water composition data.  Separate
discussions on the characteristics of produced water  and the databases used are presented for both the
Gulf of Mexico and Cook  Inlet regions.
                                            vm-4

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                    TABLE VHI-2  PRODUCED WATER VOLUMES FOR
           OIL AND GAS PRODUCTION FACILITIES IN COOK INLET REGION3
Facility Name
Operator
Avg. Prod. Water
Vol. (fapd)
PW
Disch. Location
Treatment:
Technologies
DISCHARGING PLATFORMS
Dillon
Bruce
Anna
Baker
Tyonek "A"
Unocal
Unocal
Unocal
Unocal
Phillips
2,650a
160
1,500
30
170
Platform
Platform
Platform
Platform
Platform
Skim Tanks
Skim Tanks
Skim Tanks
Skim Tanks
Skim Tanks, Gas
Flotation
SHORE BASED TREATMENT/DISPOSAL FACILITIES
Granite Point
Trading Bay
E. Foreland
Unocal
Marathon
Shell
Western
Total .
300
126,072"
3,300
134,182
Spark Platform
Outfall
Outfall
-
Skim Tanks
Skim Tanks, Gas
Flotation, Settling
Pits
Skim Tanks,
Corrugated
Separators
-
       *  Dillon platform was not discharging as of the time of EPA's cost analysis. Recent information indicates that it is
          currently discharging.4  During 1991 the discharge volume was 2,650 bpd.
       b  This value is the sum of volumes reported individually for each platform contributing to the Trading Bay facility
          reported in SAIC, January 6, 1995.
4.1    COMPOSITION OF PRODUCED WATER FOR THE GULF OF MEXICO
       The 1992 EPA 10 Production Facility Study characterizes BPT-level produced water effluent for
the coastal region of the Gulf of Mexico.  Although samples were collected at a number of locations
within each facility, samples collected at the effluent of the settling tanks were most representative of BPT
level treatment.

       Table VIH-3 presents the overall summary of occurrence of the organic pollutants detected in the
20 samples of settling tank effluents that were collected.  As can be seen from this table,  only benzene
and toluene were detected in 100 percent of the samples and o&p-xylene, 2-propanone, ethylbenzene,
m-xylene and phenol were detected hi greater than 50 percent of the samples.  An additional 28 organic
pollutants were detected in the range from 5 percent to 50 percent of the samples.  Out of  a total of 232
                                            vra-5

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                           TABLE VIH-3
PERCENT OCCURRENCE OF ORGANICS FOR SETTLING TANK EFFLUENT
   SAMPLES FROM THE 1992 EPA 10 PRODUCTION FACILITY STUDY5
Pollutant
Benzene
Toluene
o+p Xylene
2-Propanone
Ethylbenzene
m-Xylene
Phenol
n-Hexadecane
Naphthalene
o-Cresol
2-Butanone
Benzoic Acid
Hexanoic Acid
n-Tetradecane
p-Cresol
n-Decane
n-Dodecane
2,4-Dimethylphenol
n-Octadecane
n-Eicosane
2-Hexanone
2-MethylnaphthaIene
Trichlorofluoromethane
Benzyl Alcohol
Methylene Chloride
n-Docosane
n-Hexacosane
n-Tetracosane
Vinyl Acetate
l,2:3,4-Diepoxybutane
Bis(2-Ethylhexyl) Phthalalte
Chloromethane
Di-n-Butyl Phthalate
n-Octacosane
n-Triacontane
tlnits
Mil
t&l
lien
ften
t&
r&i
/tg/i
r&i
r&i
ne/1
men
ton
KS/1
f^
ven
fen
pgfl
pen
pen
/Kg/I
fen
PS/I
fen
nsn
ran
wfl
w/i
Atg/l
A»g/l
fg/1
fg/1
«fl
ffifl
r&i
r&i
\ Number of
Independent Samples
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
Number of Independent
Samples w/ Detects
20
20
16
16*
15
14
11
10
10
10
10
9
9
9
9
8
8
8
7
6
6
6
3
2
2
2
2
2
2
2
1
1
1
1
1
Percent Detects
100.0
100.0
80.0
80.0
75.0
70.0
55.0
50.0
50.0
50.0
50.0
45.0
45.0
45.0
45.0
40.0
40.0
40.0
35.0
30.0
30.0
30.0
15.0
10.0
10.0
10.0
10.0
10.0
10.0
10.0
5.0
5.0
5.0
5.0
5.0
Two of the 16 detected samples of 2-Propanone were greater than the upper limit of the calibration range.
                              vra-6

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priority and non-conventional organics analyzed, 197 were not detected.

       Table Vni-4 presents summary analytical data of the settling tank effluents from the 1992 EPA
10 Production Facility Study. Only pollutants that were detected in at least one sample were reported.
Any non-detected sample results were given the value of one-half  the detection limit  value  in the
derivation of the overall mean values.  These data were used as BPT-level effluent concentrations for the
Gulf of Mexico region in the development of the Coastal Guidelines.

4.2   COMPOSITION OF PRODUCED WATER FOR COOK INLET
       Table VDI-5 presents the summary data obtained  from several sampling programs that are
considered to be representative of the composition of produced water in Cook Inlet. The primary source,
a comprehensive Cook Inlet Discharge Monitoring Study was conducted by EPA Region 10 to investigate
oil and gas extraction point source discharges.6 In this study, produced water discharges from production
facilities in Cook Inlet (coastal subcategory) were sampled and analyzed for one year, from September
1988 through August 1989. Samples were collected from two oil platforms and one natural gas platform,
all of which discharge to the surface waters, and also from three shore-based central treatment facilities.
Flow-weighted averages were then calculated using the mean concentrations from each discharge hi this
study.  This study, however, only provided data for  10 organic pollutants and zinc. Concentrations for
the other  pollutants included in Table VTJI-5 were taken from the BPT-level effluent data from the
Offshore Development Document.2 EPA determined it appropriate to apply effluent data for offshore
platforms  to these in Cook Inlet because of the similarities in operation. The data for Radium 226 and
228 are from the Alaska Oil and Gas Association's comments on the offshore rulemaking.7

5.0   CONTROL AND TREATMENT TECHNOLOGIES
       Treatment processes for produced water  are primarily designed to control oil and grease, priority
pollutants, and total suspended solids.  Currently, most state and NPDES permits that allow the discharge
of coastal produced water to surface water bodies with limits only for the oil and grease content (BPT
limitation) hi the produced water.

5.1   BPT TECHNOLOGY
       BPT effluent limitations restrict the oil and grease  concentrations  of  produced water to a
maximum of 72 mg/1 for any one day, and to a thirty day average of 48 mg/1. BPT end-of-pipe treatment
that can achieve this level of effluent quality consists of some, or all of the following technologies:
                                            vra-7

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                      TABLE Vin-4
SUMMARY POLLUTANT CONCENTRATIONS FOR SETTLING EFFLUENT
      FROM THE 1992 EPA 10 PRODUCTION FACILITY STUDY5
Pollutant
Settling Effluent
Concentration

CONVENTIONAL AND NON-CONVENTIONAL
POLLUTANTS
Total Recoverable Oil and Grease
Total Suspended Solids
Ammonia
Chlorides
Total Dissolved Solids
Total Phenols
52,956.00
133,063.00
65,773.00
65,111,000.00
84,036,000.00
2,030.00
PRIORITY POLLUTANT METALS
Antimony
Arsenic
Beryllium
Cadmium.
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Silver
Thallium
Zinc
166.00
10.80
5.56
22.80
128.00
180.00
515.00
0.58
109.00
250.00
252.00
180.00
329.00
OTHER METALS
Aluminum
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
1,072.00
52,573.00
20,244.00
2,501,000.00
83.60
15,492.00
615,699.00
1,301.00
86.90
205,500.00
9,683.00
305.00
32.40
96.60
25.00
PRIORITY POLLUTANT VOLATILE ORGANICS
Benzene
Ethylbenzene
Methylene chloride
Toluene
4,285.00
115.00
170.00
3,370.00
Pollutant
Trichlorofluoromethane
Settling Effluent
Concentration
(ugfl)
294.00
OTHER VOLATILE ORGAMCS
Carbon Disulfide
Chloromethane
m-Xylene
o+p Xylene
Vinyl Acetate
2-Butanone
2-Hexanone
2-Propanone
8.48
28.60
136.00
86.10
29.40
122.00
35.80
913.00
PRIORITY POLLUTANT SEMI-VOLATILE
ORGANICS
Bis(2-ethylhexl)phthalate
di-n-Butyl Phthalate
Naphthalene
Phenol
46.00
46.00
144.00
553.00
OTHER SEMI-VOLATILE OKGAJNICS
Benzole Acid
Benzyl Alcohol
Hexanoic Acid
n-Decane
n-Docosane
n-Dodecane
n-Eicosane
n-Hexosane
n-Hexadecane
n-Octacosane
n-Octadecane
n-Tetracosane
n-Tetradecane
n-Triacontane
o-Cresol
p-Cresol
l,2:3,4-Diepoxybutane
2-Methylnaphthalene
2,4-Dimethylphenol
RADIONUCLIDE
Gross alpha (pCi/1)
Gross beta (pCi/1)
Lead 210 (pCi/1)
Radium 226 (pCi/1)
Radium 228 (pCyi)

3,813.00
49.50
790.00
139.00
38.00
225.00
68.00
36.10
283.00
35.20
82.90
38.20
119.00
35.00
121.00
149.00
71.10
67.20
117.00
S
383.54
312.63
64.28
172.18
228.40

                         vra-8

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                               TABLE VOI-5
         PRODUCED WATER POLLUTANT
                       FOR COOK INLET,
 CHARACTERIZATION
ALASKA
Pollutant Parameter
CON VlBimUJN ALS
Oil & Grease (mg/L)
TSS (mg/L)
PRIORITY METALS
Arsenic
Cadmium
Copper
Lead
Nickel
Zinc
PRIORITY ORGANMJS
2,4-Dimethyl phenol
Anthracene
Benzene
Benzo(a)pyrene
Chlorobenzene
Di-n-butylphthalate
Ethyl benzene
Naphthalene
Phenol
Toluene
JXUES-UUJN ViaVi'KKN ALS
n-Alkanes
p-Chloro-m-cresol
Steranes
Triterpanes
2-Butanone
Total Xylenes
Aluminum
Barium
Boron
Iron
Manganese
Titanium
Radium 226
Radium 228
Concentration 
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        •      Equalization (surge tank, skimmer tank)
        •      Chemical addition (feed pumps)
        •      Oil and/or solids removal
        •      Gravity separators
        •      Flotation
        •      Filters
        •      Plate coalescers
        •      Filtration (used prior to subsurface disposal)
        •      Subsurface disposal (injection).

        The amount of 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 in produced water hi a range of particle sizes
from molecular to droplet.  Reducing the oil content of produced water involves removing three basic
forms of oil: (1) large droplets of coalesceble oil, (2) small droplets of emulsified oil, and (3) dissolved
oil. The removal efficiency and resultant effluent quality achieved by the treatment unit is also dependent
upon the influent flow, the influent concentrations of oil and grease and suspended solids, and the other
types of compounds hi 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
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 can result hi 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 hi deck drainage entering the
treatment unit, high flow volumes caused by heavy rainfall, and equipment  failures.

        End-of-pipe control technology for  coastal treatment of produced water from oil and  gas
production consists of physical and/or chemical methods. The type of treatment system selected for a
                                            vin-io

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particular facility  is dependent upon availability  of space,  waste characteristics,  volumes, existing
discharge limitations, and other site specific  factors.   Oil skimming  with gravity separation and/or
chemical treatment using settling tanks is widely used in the coastal industry because the support structure
is relatively inexpensive (compared to offshore platforms where more compact technologies are installed)
and maintenance costs are low compared to more sophisticated technologies.  A description of the unit
processes that may be used in  the treatment scheme for produced water is presented in the following
sections.

5.1.1    Equalization
       Equalization dampens flow and pollutant concentration variation of wastewater prior to subsequent
downstream treatment.    By reducing  the  variability of the  raw  waste loading,  equalization can
significantly improve the performance of downstream unit processes by providing uniform hydraulic,
organic, and solids loading rates. Increased treatment efficiency reduces effluent variability associated
with slug raw waste loadings.   Equalization is accomplished in a holding tank.  The tank should be
designed with sufficient retention time to dilute the effects of variable  flow and concentrations on the
treatment plant performance.  Some oil and water separation will also take place in the equalization tank.

5.1.2    Solids Removal
       The fluids produced with oil and gas may contain small amounts of sand or scale particles from
the piping which must be removed from  lines and vessels. Removal of these solids  can be accomplished
by blowdown, by  cyclone separators (desanders),  or during  equipment cleanout.  Desanders are not
typically used in coastal  operations to remove sand (and other particles) from produced water.  The most
common method of removing produced solids from the process equipment is during cleanout of the
gravity separators  which accumulate solids.  Equipment cleanouts typically occur every three to five
years.  Additional  information on produced sand generation rates and disposal practices is presented in
Section IX.

5.1.3    Gravity Separation
       The simplest form of produced water treatment is gravity separation in horizontally or vertically
configured tanks or pressure vessels.  Gravity separators are sometimes called skim tanks, skim vessels,
or water clarifiers.  Gravity separators are designed with enough storage capacity  to provide sufficient
residence time for the  oil and water to separate.   Performance of these systems depends upon the
characteristics of the oil and produced water, flow rates, and retention time. Gravity separation systems
                                            vm-ii

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with large residence times are typical for coastal operations, however on the Cook Inlet platforms that
do not pipe produced water to onshore facilities, gravity separation systems have limited residence tunes
because of space and weight limitations.  While a  treatment system  relying exclusively on gravity
separation requires large tanks with long retention tunes, any treatment can benefit from even short
periods of quiescent retention to allow for some oil and water separation and dampen surges in flow rate
and oil loadings.  Many coastal operations configure two or more gravity separators in series with the
first separator acting as both an equalization tank and as a gravity separator.

       Offshore type platforms such as those hi Cook Inlet, Alaska use a devise called a skim pile as
the final gravity separation treatment step. A skim pile is a large diameter pipe attached to the platform
extending below the surface of the water.  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 VO-1 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 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.  The
pump operates intermittently and removes the separated liquid to a skimming vessel for further treatment.

5.1.4   Parallel Plate Coalescers
       Parallel plate coalescers are gravity separators which contain a pack of parallel, tilted plates
arranged so that oil droplets passing through the pack need only rise a short distance before striking the
underside of the plates. Guided by the tilted plate, the droplet then rises, coalescing with other droplets
until it reaches the 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 hi the water are relatively
small, parallel plate coalescers may not provide an effective oil-water separation.
                                             vra-:i2

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                   Inlet
Oil  Risers-
                                    Quiescent Zone

                                    Flowing Zone
        Discharge to Surface Water
                                             - Oil

                                             - Oil and Water
               Figure VHI-1
             Typical Skim Pile
                  VIII-13

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5.1.5   Gas Flotation
       Although gas flotation may be used for BPT treatment (and served as the technology basis for
BPT limitations established in 1979), it is currently used at only a small proportion of coastal facilities
in the Gulf of Mexico.  Results of the 1993 Coastal Oil and Gas Questionnaire show that the majority
of coastal operators are using gravity separation instead of gas  flotation to comply with current BPT
limitations.  The questionnaire results showed that only 20 facilities out of the 224 that were surveyed
in the coastal Gulf of Mexico area reported using gas flotation.1 However,  improved gas flotation is
being considered as a BAT technology for the coastal subcategory and is discussed as  such in Section
5.2.1.

       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 in their path, and the gas and
oil rise to the surface where they are skimmed off as a froth. Gas flotation may also aid in the removal
of oil-wet solids,  finely divided solids and solids with low  specific gravity.   These solids  become
entrained in,  and exit the system with the oily  froth.

       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 in induced-gas flotation.9

       Dissolved-gas flotation processes were at one time extensively used for the final treatment of
produced oil  field water in offshore operations.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. However, space requirements at coastal facilities are not as limited and therefore
coastal operators may elect to install DGF.
                                            VHI-14

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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 in the form of ah" bubbles which interact with the
dispersed material and carry them to the surface of the liquid.  Often the oil and solid particles act as
nuclei for the growing gas bubbles.  Mechanical flight scrapers  are then used to remove the floated
material.

        Since the solubility of air at atmospheric conditions is low and efficiency of the flotation process
is 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.10-12 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 pressurized retention
tank. During this process, the gas is sheared into finely dispersed bubbles which remain in the solution
for a short period of time (1  to 3 minutes retention tune) in the retention tank.  At this point the excess
gas (undissolved air) is purged from the tank. From the retention tank, the pressurized saturated water
passes through a backpressure regulator before entering the flotation unit.  This regulator facilitates the
necessary instant pressure drop in the system and creates turbulence  for  proper dispersion of super
saturated water.  Floe, which forms as air bubbles interact with the suspended material, is lifted to the
surface  of the flotation cell, where it is removed by mechanical skimmers.  The more dense suspended
material which is not amenable 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-
                                             vra-is

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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 oil particles and floats them to the surface.  A skimmer system is used to remove
the floated oil and 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
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
       4
        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 hi the new designs. Such
consideration may include repositioning the diffuser nozzles so that the air is released hi the vertical
direction for maximum efficiency and minimum turbulence in the flotation tank.11'13

        Some  of the  main  advantages of IGF  include:  less stringent  operation and  maintenance
requirements,  lower comparative power requirements, and adaptability to existing facilities. In addition,
because of the larger bubbles produced hi this type of unit, interactions are much faster resulting in
shorter required retention tune and smaller units.  Hence, less capital cost and space are required.9'11'12

        Figure Vin-2 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 hi  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 hi the flotation region of the tank.
                                            vm-16

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                                      3

                                      |
                                      "8

                                      1
                                    c <"

                                    §>O

               0)
               CO

               O



               1
                                      ff

                                      1
                                      i
                                       i
                                       es
I
t/3
vm-17

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        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

        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 hi 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 hi mechanical-type systems.11

        The rate at which gas flows into an eductor is a function of recycle rate (eductor pressure), gas
inlet orifice size, and any valve that may have been installed hi the gas feed pipe. The gas flow rate and
energy dissipation are the major factors hi determining the  size of bubbles produced.  The recycle flow
rate is generally controlled manually through control valves installed hi 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 hi a decrease hi the initial residence  tune.  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 in overall operating cost, and
experience less downtime than other types of gas flotation  systems. However, because the gas transfer
per unit volume of water  in 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
                                             vra-is

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5.1.6   Chemical Treatment
        The addition of chemicals  to the wastewater stream  is an effective means of increasing the
efficiency of treatment systems. Chemicals are used to improve removal efficiencies in gravity separation
systems, plate coalescers, and flotation units.  The three basic types of chemicals that are used to enhance
equipment removal efficiencies in wastewater treatment are:

        Surfactants: Surfactants, also known as surface-active agents or foaming agents, are large organic
molecules that are slightly soluble in water and cause foaming in wastewater treatment plants and in the
surface waters into which the waste effluent is discharged.  Surfactants are sometimes used to treat oil-wet
solids.  Oil-wet solids tend to settle poorly because the combined lower density of the oil and higher
density of the solids results in particles that have neutral buoyancy in water. Surfactants break apart the
oil and solids so that they can more readily separate from the water.

        Coagulants:   Coagulating  agents assist  the  formation of a floe and  improve the settling
characteristics of the suspended matter.  The most common coagulating agents are aluminum sulfate
(alum) and ferrous sulfate.

        Polyelectrolytes: These chemicals are long chain, high molecular weight polymers used to bring
about particle aggregation.  Polyelectrolytes act as coagulants to lower the charge of the wastewater
particles, and aid in the formation of interparticle bridging.  Depending on whether their charge, when
placed in water, is negative, positive, or neutral, these polyelectrolytes are classified as anionic, cationic,
and nonionic, respectively.

        Surface active agents and polyelectrolytes are the most  commonly used chemicals hi wastewater
treatment processes.   The chemicals are usually injected into the wastewater in the piping upstream of
the treatment unit without pre-mixing.   Serpentine pipes, existing piping arrangements, etc., induce
enough turbulence to  evenly disperse these chemicals into the water stream.

5.1.7   Subsurface Injection and Filtration
        Subsurface disposal is sometimes used to comply with BPT limits. Injection is generally, used
for waterflooding to enhance production (or to meet water standards).  At some facilities injection is
preceded by a filtration process to protect the  formation face from becoming fouled with solids.
                                            vm-i9

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Subsurface injection and filtration are identified as BAT technologies as a means of disposing of produced
water and therefore are 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 injection, cartridge
filtration, granular filtration, crossflow membrane filtration,  and activated carbon adsorption.  The
following sections describe these technologies in detail.
                    %
5.2.1    Improved Performance of Gas Flotation Technology
       During the development of the offshore rule, EPA evaluated the costs and feasibility of improved
performance of gas flotation treatment systems to determine whether more stringent effluent limitations
based on improved performance of gas flotation would be appropriate.  Since most coastal facilities do
not currently use this technology it is reasonable to  assume that for most coastal the improvements can
be designed into any newly installed systems.  The performance data for this technology has been adopted
from the offshore rule.  Table VTJI-6 presents summary data for improved gas flotation  effluent as
compared to settling effluent.

       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

        Chemicals are commonly used to aid the flotation process.  Chemicals function to create  a surface
or a structure that can  easily absorb or entrap air bubbles. Three basic types of chemicals, which  are
                                            vm-20

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                                              TABLE Vm-6
                      PRODUCED WATER EFFLUENT CONCENTRATIONS
                                           GULF OF MEXICO
Pollutant Parameter


Oil & Grease
TSS

1. Priority Organic Pollutants
Bis (2-ethylhexyl)phthalate
2,4-Dimethylphenol
Benzene
Chloromethane
Di-n-butylphthalate
Ethylbenzene
Methylene chloride
Naphthalene
Phenol
Toluene
2. Priority Metal Pollutants
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver .
Thallium
Zinc
3. Other Non-Conventional Pollutants
Acetone
Aluminum
Ammonia
Barium
Benzole acid
Benzyl alcohol
Boron
2-Butanone
Calcium
Carbon disulfide
Chlorides
Cobolt
1 ,2 ,3 ,4-Diepoxybutane
Hexanoic Acid
2-Hexanone
Iron
Magnesium
Manganese
2-Methylnapthalene
Molybdenum
n-Decane
n-Docosane
n-Dodecane
n-Eicosane
n-Hexosane
n-Hexadecane
n-Octacosane
n-Octadecane
n-Tetracosane
n-Tettadecane
n-Tricontane
o-Cresol
p-Cresol
Strontium
Sulfur
Tin
Titanium
Trichlorofluoromethane
Total Xylenes
Vanadium
Vinyl acetate
Yttnum
; Settling
Effluent5
Improved Gas
Flotation Effluent"
Concentrations (mg/1)
52.956
133.063
23.5
30.0
Concentrations (jtgft)
46.00
117.00
4,285.00
28.60
46.00
115.00
170.00
144.00
553.00
3.370.00
166.00
10.80
5.56
22.80
128.00
180.00
515.00 '
109.00
250.00
252.00
180.00
329.00

913.00
1,072.00
65,773.00
52,573.00
3,813.00
49.50
20,244.00
122.00
2,501,000.00
8.48
65,111,000.00
790.00
71.10
83.60
35.81
15,492.00
615,699.00
1,301.00
67.20
86.90
139.00
38.00
225.00
68.00
36.10
283.00
35.20
82.90
38.20
119.00
35.00
121.00
149.00
205,500.00
9,683.00
§05.00
32.40
294.00
222.10
96.60
29.40
25.00
46.00"
117.00"
1,225.91
28.60
6.43
62.18
170.00"
92.02
536.00
827.80
166.00
10.80
5.56
14.47
128.00
180.00
124.86
109.00
250.00
252.00
180.00
133.85

913.00"
49.93
65.733.00"
35.560.83
3,813.00"
49.50"
16,473.76
122.00"
2,501,000.00
8.48"
65,111,000.00
790.00"
71.10"
83.60
35.81"
3,146.15
615,699.00
74.16
67.20"
86.90
139.00"
38.00"
225.00"
68.00"
36.10"
283.00*
35.20"
82.90"
38.20"
119.00*
35.00*
121.00*
149.00*
205,500.00
9,683.00
§05.00
4.48
294.00"
222.10*
96.60
29.40"
25.00
Sources:   a)    Concentrations hi this column are from the Offshore Development Document2 unless otherwise noted.
         b)    For the purpose of regulatory analysis, these concentrations are substituted using the settling effluent concentrations5 either because no data
              were available hi the Offshore Development Document or because the offshore gas flotation value was greater than the sealing effluent value.
                                                  vm-2i

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previously discussed in Section 5.1.6, are generally utilized to improve the efficiency of the gas flotation
units used for treatment of produced water; these chemicals are surface active agents, coagulating agents,
and polyelectrolytes.  Inorganic chemicals, such as the aluminum or ferric salts and activated silica, can
be used as coagulating agents to bind the particulate matter and to create a structure that can easily entrap
air bubbles.  Various surface active organic chemicals can be used to change the nature of either the air-
liquid interface or the solid-liquid interface, or both.  These compounds usually collect on the interface
to bring about the desired changes.

        Researchers have demonstrated that the  addition of chemicals to the water stream is an effective
means of increasing the efficiencies of gas flotation treatment systems.11'17'18-19  Pearson, 1976, reported
that the use of coagulants can drastically increase the oil removal efficiency of dissolved-gas flotation
units.12 The addition of alum plus polyelectrolyte to a flotation cell treating refinery wastewater increased
the unit efficiency from 40 percent to 90 percent. Luthy, et al., 1978, also demonstrated the effectiveness
of polyelectrolytes for improving  the effluent quality of dissolved-gas  flotation units treating refinery
wastewater.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.

        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
                                            vm-22

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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

       For those few coastal facilities that already have gas flotation in place most modifications to
improve gas flotation 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    Subsurface Injection
       Disposal of produced water by injection into  a subsurface geological formation can serve  the
following purposes:

       •       Provide zero discharge of wastewater pollutants to surface waters.
       •       Increase hydrocarbon recovery by flooding or  pressurizing the oil  bearing  strata
               (waterflooding).
                                            VHI-23

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        •      Stabilize (support) geologic formations which settle during oil and gas extraction (a
               significant problem for older,  i.e onshore and coastal, more depleted reserves).

        Coastal  and onshore produced water injection is a well-established practice for disposal of
produced water.

        As part of the offshore rulemaking process, and in response to industry concerns about the
feasibility of injection due to the receiving  formation characteristics, EPA evaluated the  technical
feasibility of implementing this technology at both existing and new offshore facilities.22  The study
showed that injection is generally technologically feasible in all offshore areas, i.e., suitable formations
and conditions are available for disposal operations. The same is generally true for the coastal regions
in that the geologies of the North Slope and the Gulf Coast consist of formations which can readily accept
injected produced water.  Other locations may experience problems hi being able to inject due to site-
specific formation characteristics or proximity to seismically active areas.

        The following sections present  information on the injection technology as a means to control
produced water discharges.

5.2.2.1  Industrial Practices by Location
        Most of the produced water generated  in the coastal and offshore areas of California is  presently
injected for waterflooding to enable recovery of the heavy crude oil that is typically produced in that part
of the country.  In  the Gulf of Mexico, produced water generated in the coastal region is either  treated
to the BPT limitations and discharged to the surface waters or it is injected for disposal. Coastal injection
experiences  in Texas and Louisiana have shown that the characteristics of the regional geology make it
possible to inject produced water at most locations in the adjacent coastal region. However, in Cook
Inlet, there are no formations onshore directly beneath the treatment facilities to accept the large volumes
of produced waters treated, making injection onsite unfeasible27.

        The data in Table IV-1 show that EPA estimates that there were 853 production facilities in Texas
and Louisiana in 1992 and of those, 325 were discharging produced water to surface waters. The Coastal
Oil and  Gas Questionnaire Summary Statistics showed that of the production facilities  hi the Gulf of
Mexico that dispose of produced water  by injection or surface discharge, an estimated 61 percent were
injecting produced  water hi 1992.1  Thus,  it can be assumed that the majority of the  estimated 528
production facilities not discharging in 1992 were disposing of produced water by subsurface injection.
                                             VHI-24

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As shown in Table IV-1, EPA estimates that the number of coastal facilities discharging produced water
in the Gulf region will drop to 216 by 1996 due to State of Louisiana requirements to cease discharging
of produced water based on water quality standards.

       All of the coastal operations hi the North Slope region of Alaska inject all of their produced water
primarily for waterflooding.  In Cook Inlet, Alaska, produced water is surface discharged after BPT
treatment.  However, waterflooding is being performed using seawater.

5.2.2.2  Well Selection and A vailability
       There are a number of considerations in the planning, design, and operation of a produced water
injection system.  These include important design considerations such as selection of  a  receiving
formation,  preparation  of an injection  well,  and choice of equipment and  materials.   Significant
operational parameters include scaling, corrosion, incompatibility with the receiving stratum, and bacterial
fouling.

5.2.2.2.1  Formation  Characteristics
       Selection of the receiving formation should be based on geologic as well as hydrologic factors.
These factors determine the injection capacity  of the formation and the chemical compatibility of the
injected produced water with the water  within the formation.  The most important regional geologic
characteristics of a  disposal formation  are  area!  extent and  thickness, continuity, and  lithological
character. This information can be obtained or estimated from core analysis, examination of bit cuttings,
drill stem test data, well logs, driller's logs, and injection tests.

       The desirable characteristics for a produced water injection formation are: an injection zone with
adequate permeability, porosity, and thickness; an areal extent sufficient to provide liquid-storage at safe
injection pressures; and an injection zone that is confined by an overlying consolidated layer which is
essentially  impermeable  to  water.   There  are  two common types of intraformation  openings:
(1) intergranular and  (2) solution vugs and fracture channels.  Formations with intergranular openings
are usually made up of sandstone, limestone, and dolomite formations and often have vugulur  or cavity-
type porosity. Limestone, dolomite, and shale formations may be naturally fractured.  Formations with
fracture channels are often preferable for produced water disposal because fracture channels are relatively
large in comparison to intergranular openings.  These larger channels may  allow for fluids with higher
                                            VIII-25

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concentrations of suspended solids to be injected into the receiving formation under minimum pumping
pressure and minimal pretreatment.

       A formation with a large areal extent is desirable for disposal purposes because the fluids within
the disposal formation must be displaced to make room for the incoming fluids. An estimate of the areal
extent of a formation  is best made through a subsurface geological study of the area.  If it is possible to
inject water into the aquifer of some oil- or gas-producing formation, the size of the disposal formation
is not critically important. Under these circumstances, the injected water would displace water from the
aquifer into the producing reservoir from which fluids are being produced.   Thus, the pressure in the
aquifer would only increase hi proportion to the amount that water injection exceeds fluid withdrawals.
Pressure-depleted  aquifers of older  producing reservoirs  are highly desirable as disposal formations,
provided the disposal practice will not adversely affect the producing reservoir.

       Formations capped or sandwiched by impervious strata generally will assure that fluids pumped
into the  formation will remain in place and not migrate to another location.23 Abandoned producing
formations are ideal  for disposal because the original  fluids were trapped in the formation.  Fluids
injected into those formations also will be trapped and will not migrate into other areas.

5.2.2.2.2  Possible  Environmental 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
                                             VHI-26

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bottom was in the vicinity of a fault.  Subsequent analysis showed a direct correlation between the
number of microseisms in the Denver area and well pumping times and rates. Increased pumping caused
a corresponding increase in the number of microseisms.

       Another possible concern is improperly plugged and abandoned wells located near the disposal
well.  This is particularly true for older fields such as those in the Gulf of Mexico coastal region.
Improperly plugged  and abandoned wells that penetrate the disposal formation  within the range of
influence of the disposal well can serve as conduits for migration of the disposed or displaced fluid into
drinking water aquifers or into producing formations where it may damage the formation.  To prevent
this occurrence, most states require as part of the injection well permit application that the operator
conduct an area of review (AOR) investigation to locate any improperly plugged and abandoned wells
within a certain radius of the proposed injection well.  In the state of Texas,  this radius is 0.25  miles
unless otherwise specified by the permitting authority.  Conducting an AOR, at a minimum, involves the
search of public records for suspect wells. Any improperly plugged and abandoned well that is located
within the specified area must be properly plugged prior to the approval of the injection well permit. At
the time of this writing, EPA's Federal Underground Injection Control Program is involved in proposing
additional AOR requirements.

5.2.2.2.3 New Versus Converted Wells
       Whether the objective is enhanced ("secondary") recovery or disposal, a primary requirement for
the proper design of a injection well is that the produced water be delivered to the receiving formation
without leaking or contaminating fresh water or other mineral bearing formations. The injection well may
be installed by either drilling a new hole  or by converting an existing well. The types of existing wells
which may be converted include:  marginal oil producing wells, plugged and abandoned wells, and wells
that were  never completed (dry holes).  If an existing well is  not available for conversion, a new well
must be drilled. Moreover,  for injection from platforms supported on pilings, adequate equipment and
storage space must be provided at the facilities.

       The drilling of a new injection well is very similar in practice to the drilling of production wells
except that injection wells may not need to be drilled as deep as the production wells they serve, if
shallower disposal formations are available.  The advantages of drilling a new  well specifically for
produced  water injection include the following:
                                            VIH-27

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        •       Location can be selected to minimize surface piping.
        •       Location can be selected to utilize optimal geologic formations.
        •       Casing and long string can be sized to handle designed produced water flowrates.
        •       Casing can be properly cemented to meet regulatory requirements.
        •       Desired casing grades and weights may be used.

The disadvantages of drilling new injection wells are:

        •       Costs are higher than converting an existing well.
        •       Geology and downhole conditions may not be known prior to drilling.
      *
        Figure VQI-3 presents a schematic of a typical well drilled for subsurface injection.  EPAs' field
investigations found that the conversion  of existing  production wells to injection wells  is the most
common practice in the coastal  Gulf of Mexico  region  primarily due  to availability  and costs.
Conversions are most commonly performed on depleted production wells using wells whose hydrocarbon
production rates have or soon will diminish to the point where they are no longer economical to operate
as production wells (i.e. depleted wells).  Wells that were never completed (dry holes) and old plugged
and abandoned wells may also be used, but may require more work at greater expense.24

        The most common method of conversion involves recompletion of the well at a shallower depth
into a non-hydrocarbon producing formation. In such a case the lower portion of the well is cemented.

5.2.2.2.4 Regional Geological Considerations
California
        There is little question about the technical feasibility of injecting produced water at the existing
facilities in the coastal region of California because the current practice of this technology is common.
In the coastal and offshore subcategories for California, all of the produced water is injected for the sole
purpose of enhanced recovery by waterflooding. In fact, at the THUMS facilities in Long Beach Harbor,
additional brine to that of the produced water must be injected to provide sufficient pressure maintenance.
Injection of produced water is not practiced in areas where there is potential for seismic activity.40  The
coastal  geological conditions and engineering requirements for  the injection of brines from new sources
in areas expected to be open for oil and gas  development and production, i.e., free of seismic activity,
are expected to be essentially the same as for existing sources.  Consistent with the past and present
                                            vm-28

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                     WeU Head-
                                                    Produced Water
Possible Future
Injection Zones
                                                             Underground Source
                                                               of Drinking Water
Shale
                                  Figure VHI-3
                         Typical Subsurface Injection Well
                                    vra-29

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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 injection
wells, availability of coastal pretreatment technologies, and the transport and onshore disposal of solids
and sludges from new sources pose no additional technical problems beyond those currently encountered
due to the injection of brines from existing sources.

Gulf  of Mexico
        In the Gulf of Mexico, injection of brines from existing coastal sources is common (see Section
5.2.2.1). The two most common disposal practices are either to pretreat and inject or to treat the brines
to the BPT effluent limitations and discharge. Waterflood projects are no longer common in the Gulf of
Mexico; it is estimated that less than ten facilities in the Gulf of Mexico inject  produced water for
pressure maintenance.25   The primary  reason  that waterflooding is  not common is because,  unlike
California, extraction  of the formation fluids  from the reservoirs in the Gulf of  Mexico does not
necessarily require the additional water drive provided by waterflooding.  Secondly, economics prevent
secondary recovery operations hi the Gulf of Mexico.  Additionally, older fields benefit less over time
from  this practice.  The additional oil recovered due to waterflood is not worth the cost of the injection
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.

        Injection of brines for disposal  from existing and new sources in the coastal Gulf of Mexico
region depends on the availability of an adequate number of suitable disposal formations.  In the early
stages of production, there is little need for injection fluids to  enhance recovery and, therefore, the
produced water would be injected only for disposal purposes.  The coastal injection experience hi Texas
and Louisiana has shown that injection of produced water is possible where there are suitable disposable
formations available.  Throughout most of the  coastal region of Louisiana and Texas, the  oil and gas
producing formations are overlaid with alternating sequences  of sand and shale sediments formed by
ancient rivers and oceans and make up a considerable part of the stratigraphic column.22  The advantages
of using these formations for disposal include:

        •       Formation thicknesses, depths,  porosities and permeabilities are usually available from
               logs of the production wells and past experience.
        •       Shallower depths require less drilling and tubing,  thereby reducing construction and
               future remedial well work costs.
                                             vm-so

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               Production wells can be converted to disposal wells without affecting producing reservoir
               dynamics.
       Eight  of the nine non-commercial coastal  injection facilities in the Gulf of Mexico  region
investigated by EPA in 1992 were disposing of produced water into sand formations shallower than the
producing formations.26  Several facilities indicated that additional shallower sand formations existed that
could be used in the  future  by recompleting the disposal wells at a shallower  depth.   The  only
disadvantage of using shallower formations is that the maximum allowable injection pressure will be
reduced. This can result in lower injection pressures and more frequent remedial well work.

Alaska
       In the North Slope region of Alaska, all produced water generated is injected with the major
portion being used for waterflooding. Waterflooding is also practiced hi Cook Inlet, however, seawater
is used rather than the produced water.  The water flooding occurring hi Cook Inlet has reached "parity"
which means that the volume of seawater injected is essentially equal to the combined volume of oil and
produced water that is brought to the surface. Therefore, it is conceivable that the seawater could be
replaced with produced water  with the  difference (equal to the volume of oil extracted) being made up
with seawater.

       A study of the technological feasibility and the economic analysis of subsurface disposal hi Cook
Inlet  was performed for produced water  from the Trading Bay.27  In this report,  three injection
alternatives were considered and evaluated:  1) treatment and injection for waterflooding at the platform;
2) piping produced water to an onshore facility for treatment and return to the platform for injection for
waterflooding; and 3)  piping  produced water to an onshore facility for treatment and injection for
disposal. In this study, alternatives 1 and 2 were reported to be  technically feasible, however, several
operational  problems were  identified  that could affect the system.   These problems,  along  with
preventative remedial measures are discussed below.

       For the third alternative, the study suggests that the available Tyonek sands injection formations
directly beneath the Trading Bay Facility (which discharges 94% of the Cook Inlet produced waters) are
not suitable to accept the large  amounts  of produced water generated at this facility.  Although significant
hi gross pore  volume, these formations are broken up into numerous smaller reservoirs.  Continuous
injection into any one reservoir could cause the reservoir to become overpressurized, threatening to cause
fracturing and migration to shallower potable water aquifers and possibly triggering seismic activity. In
                                            vra-31

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addition, the Tyonek formations contain significant amounts of water-sensitive clays which, when injected
with the relatively fresh produced water from the Trading Bay Facility, could result in severely or
completely restricted permeability.27

5.2.2.3  Technical Problems
        Some of the technical problems that may be associated with subsurface injection of produced
water are described below.  In general, these potential problems can be avoided or remedied through
engineering and operational applications such as the use of treatment chemicals. Possible solutions for
each of the problems are also discussed.

        Formation Plugging and Scaling - Scales and sludges that are commonly found in produced
water disposal systems include:   calcium carbonate, magnesium carbonate,  calcium sulfate, barium
sulfate, strontium sulfate, iron sulfide, iron oxide, and sulfur.  These scales and sludges can form in
collection and distribution lines, treating equipment, well tubulars and at the injection formation.28

        Scale and sludge differ in that scale is a deposit formed in place on surfaces hi contact with water,
while sludge may be formed in one place and deposited hi another.  Sludges may collect in low flow rate
areas of a system such as tanks and vessels, in the bends of lines and on filter surfaces.28

        Scales and sludges  are formed from water  as the waters adjust to  changes hi  equilibrium.
Changes in equilibrium are caused by temperature changes, pressure changes, chemical changes, and the
mixing of two or more stable but incompatible waters. Scale may form as a result of a chemical reaction
between the water, or some impurity hi the water,  and the pipe.  Corrosion products, such as iron oxide
or iron sulfide, may be scales of this type.  Other precipitates, such as sulfur, may form when water with
hydrogen sulfide is mixed with water with a high dissolved oxygen content.28

        The solubility of calcium carbonate (a common component of groundwater) is influenced by the
concentration of dissolved carbon dioxide in water.  If calcium carbonate  is present hi an underground
formation and the concentration of dissolved carbon dioxide hi the formation water is increased, the
amount of dissolved calcium carbonate will increase.  When the dissolved  carbon dioxide concentration
is reduced, such as when carbon dioxide-rich produced water comes to the surface where the pressure
is lower and it conies into contact with air, the reverse occurs,  and the carbon dioxide is  released and
                                            vra-32

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 calcium carbonate will precipitate.29  Also, the solubility of most scales  decreases  with decreasing
 temperatures.

        All of the produced water operations in the 1992 EPA 10 Production Facility Study sampling
 effort maintained closed systems that exclude air using gas blankets.  When the produced water samples
 were cooled and exposed to air, a noticeable increase in turbidity and a color change occurred for most
 samples.  The turbidity was probably the result of calcium carbonate precipitation and the color change
 was probably the result of the oxidation of dissolved iron.

        Scale Prevention - Scale formation is normally preventable.   Once formed, however,  scale
 removal is expensive and may cause some permanent damage.  Individual waters or mixtures of waters
 should be tested prior to the design of the produced water disposal system to determine if scale deposition
 will be a problem.  The waters that are to be added to an existing system should also be tested prior to
 hookup.28

        Scale  deposition of waters can be predicted  with moderate accuracy using conventional water
 analysis and the Stiff-Davis method of predicting the approximate solubility of calcium carbonate and
 calcium sulfate  in produced waters.  Compatibility tests will also indicate if scale formation is to be
 expected.28

        Depending on  the type of scale involved, methods of preventing or removing scale prior to
 injection include: maintaining a closed system using gas blankets; use of scale inhibiting chemicals; use
 of acid treatment; use of settling tanks with chemical addition;  filtration;  and  prevention of  mixing
 incompatible waters.

        In Cook Inlet, Alaska, the operators have expressed concern that the  produced water contains a
 significant amount of  scale-forming ions,  primarily calcium carbonate, and that the use of  treated
produced  water for waterflooding will result in the rapid  plugging of the injection wells.  One problem
 associated with this is that the onshore produced water treatment systems at Trading Bay, Granite Point
and East Forelands do not maintain closed systems with gas blankets throughout the system.  Therefore,
there is a greater potential for produced water from these systems to develop calcium carbonate scale.
However, the  use of the remedies discussed above such as gas blankets and  chemical treatment should
substantially alleviate this problem.
                                            vm-33

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       In addition to scales and sludges, production formation solids such as sands are commonly found
in produced water disposal systems. This is especially true for produced waters from unconsolidated sand
formations which are common hi the Gulf Coast region. Formation solids referred to as produced sand
in this report are most commonly removed using settling tanks and filters in the coastal areas of the Gulf
of Mexico.

       Formation Swelling - The injection of water with a lower total dissolved solids or salt content
than the injection formation water can cause clay particles embedded in the formation to swell.  However,
this is generally not a problem for produced water injection hi the Gulf Coast region because produced
water in the Gulf Coast region generally has a total dissolved solids or salt content which is several tunes
that of seawater.  This swelling in turn increases the necessary injection pressure and may decrease the
injection capacity of the injection well.  This phenomenon was reported by the Campbell Wells facility
at Bourg, Louisiana which injected a high proportion of relatively fresh washwater (about 73 percent)
from  their land treatment operation along with  produced  water from commercial clients  (about 27
percent).30 The result was that higher injection pressures were necessary but injection was not prevented.
In Cook Inlet, the use of seawater for waterfiooding does not appear to have created a swelling problem.
This problem can also occur at facilities that combine a significant quantity of contaminated stormwater
with produced water for disposal.

       Corrosion - A more common problem encountered in combining fresh water, such as stormwater,
with produced water for injection is  corrosion caused by dissolved oxygen. The corrosion of metals in
a produced water disposal system is usually caused by electrochemical reactions. In this type of reaction
an anode (electron donor) and cathode (electron acceptor) must exist hi the presence of an electrolyte
(ionic solution) and an external circuit.  Anodes and cathodes can exist at different points on the steel
surfaces with lie steel providing the  external circuit. A brine solution provides an excellent electrolyte.
Thus, an electric circuit can be set up hi the unprotected, produced water-handling  pipelines with iron
being oxidized at one portion of the system (cathode)  and iron being reduced and corroded away hi
another portion (anode).

        Corrosion damage can occur uniformly as  a gradual thinning of the  anode portion, or it can occur
hi the form of pitting where localized electrolytic cells are set up. It can also occur as galvanic corrosion
when two different metals come into contact and form an electrolytic cell.
                                             VHI-34

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        Dissolved oxygen is a major producer of corrosion.  Oxygen-induced corrosion is the result of
an electrochemical reaction between a metal,  such as iron, and the oxygen where the oxygen accepts
electrons and the metal donates electrons. While oxygen is normally absent in formation waters, it is
unavoidably absorbed by contact with air in open produced liquid handling systems and can also be
introduced with the addition of contaminated stormwater.

        Corrosion Prevention - At three of the ten production facilities that EPA sampled, contaminated
stormwater was periodically added to the produced water for treatment and disposal.26  The dissolved
oxygen in the stormwater can be removed using a chemical (oxygen scavenger) which combines with the
oxygen. In addition, the use of closed systems with gas blankets can prevent the introduction of oxygen
to the system.

        Incompatibility of Injected Produced Waters with Receiving Formation Fluids - In the design
and operation of a produced water injection system, the compatibility of injected produced waters with
the fluids already in the receiving formation is an important consideration. Incompatibility occurs when
one or more of the chemicals hi the produced water reacts with chemicals in the existing  reservoir fluid
to cause an undesirable effect, such as precipitation of scale.  This condition could also  occur if
incompatible waters  from different reservoirs or surface  sources are to be mixed prior to injection.
Precipitation damage resulting from incompatible fluids is usually in the form of plugged pore spaces in
the injection zone.  Precipitates that may  be  associated with incompatible fluids  include calcium
carbonate,  magnesium carbonate, calcium sulfate, barium sulfate, and strontium sulfate.  Both barium
sulfate and strontium sulfate are highly insoluble hi water and are extremely difficult to remove.

        Incompatibility Prevention  - Treating produced water to prevent incompatibility  consists of
reducing the strength of or removing the reactive element or otherwise altering the nature  of the injected
fluid using treatment chemicals.

        Bacteria - The presence of bacteria hi a system may present a corrosion or plugging problem.
Bacteria in oil field waters may be aerobic (active hi presence of oxygen), or anaerobic (active in the
absence of oxygen).

        Iron bacteria are aerobic and are active hi removing iron from water and depositing it hi the form
of hydrated ferric hydroxide.  They are commonly active hi fresh waters but are occasionally found hi
produced  waters  containing oxygen.   The removal of oxygen by the bacteria causes an anaerobic
                                            vra-35

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condition to exist under the ferric hydroxide iron deposits on vessel walls where sulfate reducing bacteria
can grow and corrode the vessel walls. Both types of bacteria are easily controlled with bactericides.28

        Aerobic bacteria, or slime formers,  can grow  in sufficient numbers to cause significant well
plugging. Aerobes are indicators of excessive bacterial activity in oxygen-bearing waters and if present
in a closed  system indicate that air contamination exists. The slimes that are formed shield the metal
surfaces from oxygen and provide an environment for the growth of sulfate reducing bacteria. Control
of aerobic bacteria is generally accomplished by treatment with an organic biocide.28

        Anaerobes are active hi the absence of oxygen but are not killed by the presence of oxygen.
Anaerobes,  except sulfate reducers, multiply slowly and normally are found under slime deposits. They
are effectively killed with bactericides.  Although chlorine could be used, in a closed system chlorine is
not used because it is an oxidizing agent.28

        Sulfate reducing bacteria are the most common and economically significant of the bacteria found
in salt water disposal and injection systems.  Sulfate bacteria are economically significant due to the
corrosion problems associated with them.  Sulfate reducing bacteria are anaerobic and have the ability
to convert sulfate to sulfide. Sulfate reducers are most active in neutral to mildly acidic waters, are
frequently found under slime deposits, and are most prolific under corrosion products, tank bottoms,
filters, oil water interfaces, and dead water areas, such as joints, crevices, and cracks in cement linings.
Sulfate reducers may also exist naturally in some oil  and water producing strata.28

        In addition to being  corrosive, hydrogen sulfide is highly toxic and can cause embrittlement of
steel.  Hydrogen  sulfide is  sometimes present  in significant quantities in the hydrocarbon producing
formations  where  it was  created in the past by  sulfate  reducing bacteria  that were  present  in the
formation.  When brought to the surface, it separates out with the gas phase. This type of natural gas
is referred to as "sour gas" and is a potential health problem for operators. Thus, its presence requires
safely teaming of operators and the use of special safety equipment and preventive measures.  In addition,
the corrosion and embrittlement problem may require  the use of special steel alloys or coatings hi the
production equipment.  The  sour gas must be treated  to remove hydrogen sulfide prior to delivery to the
pipeline.31

        The operators at Cook Inlet have expressed concern that the replacement of seawater with treated
produced water for use in waterflooding will result hi the growth of sulfate reducing bacteria.27 They
                                             VOI-36

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say that the result will be that the bacteria will plug the formation and will generate hydrogen sulfide
which will return to the surface with the produced fluids creating corrosion and safety hazards.  The
reason that this does not currently occur is that the seawater does not contain the nutrients necessary to
promote bacterial growth. However, they claim that the standard treatment chemicals used in processing
the produced water contains nutrients that will promote bacterial growth and that the previous use of
seawater for waterflooding has introduced a substantial quantity of sulfate to the formations.

       Bacteria Prevention - As noted above, the prevention of bacterial growth is primarily remedied
with the use of bactericides which are injected into the  produced water treatment system influent.  In
addition, if process treatment chemicals are the source of nutrients that are conducive to bacterial growth,
the substitution  of these chemicals with ones  that do not contain the nutrients can be an effective
preventive measure.32

       Injection Into Producing Formations - Injection into producing formations is not  extensively
practiced in the  coastal  region of the Gulf of Mexico because of potential problems that waterflooding
can cause by adversely changing the field pressure.22 These pressure changes can cause a production loss
from nearby production wells either by coning at the injection wellbore or, if there  is directional
permeability within the  reservoir, the rapid return of injected water back to the production wellbore.
Increased pressure can also cause movement of the formation fluid containing the oil and gas away from
the production wellbore. These movements may result hi 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 injection into a producing formation.

5.2.2.4 Down-Hole Remedial Measures
       During the life  of an  injection system, formation capacity may  decrease significantly  due to
formation plugging (from suspended solids, precipitation, hydrocarbons,  or  bacteria)  or fouling  of
flowlines  from scale  or biological growth.   Should these problems develop, the following remedial
measures have been used to increase and prolong capacity.28

       Acidizing - In many cases the receptivity of a formation may be improved or restored by acid
treatments.  In carbonate formations, acid will dissolve or etch fluid passageways through the treated area
of the formation, .creating an enlarged effective well bore.  In all formations, foreign materials introduced
while drilling, completing, or injecting into  a well may block or plug the formation.   Acid cleanup
                                            vra-37

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treatments may dissolve, loosen, shrink, or affect these foreign materials so that they may be removed
by swabbing, or dispersed by flushing.  A well should never be left shut-in following acid treatments.
The spent acid and residual products should be removed from the well bore immediately after the reaction
time of the acid.28

       Only one of the 10 injection production facilities in the 1992 EPA coastal sampling effort reported
performing an acid treatment and reported that the well injectivity unproved for only a short period of
time.  One of the commercial  facilities in the 1992 EPA coastal sampling effort reported that they
routinely added  acid to their first equalization tank prior to injection.  This was most likely done to
reduce the quantity of scales and sludges present in the incoming water shipments as well as those that
may form  as  a  result  of the mixing  of water from different  sources.  Scales and sludges that are
effectively  treated with acid include calcium carbonate, magnesium carbonate,  iron oxide, and iron
sulfide.28

       Sand Jetting or Under Reaming - An injection well completed hi open hole (without casing)
may cease to take water because of damage or plugging at the formation face.  The formation can be
reconditioned by removing the face of the formation with a high velocity jet of sand-laden fluid, or by
cutting away the face of the formation using an underreamer.  In cases of insoluble scale damage, these
methods  could be more effective than acid treating.28  None of the nine  non-commercial  or  two
commercial injection facilities in the 1992 EPA Coastal sampling effort reported performing a sand jetting
or underreaming operation on an injection well.33

       Backwashing - Periodically, wells can be backflowed to clean the formation face.  Backwashing
is performed by sparging gas, usually nitrogen, near the bottom of the injection tubing which creates an
upward flow of mjection/formation fluid and solids that are plugging the formation face.  This operation
is similar hi principal to backwashing a filter. The fluids and solids are captured hi tanks and are hauled
offsite for treatment and disposal. In some cases the fluids and solids are treated onsite, and the treated
fluids are injected.  Special strings of tubing are used to facilitate this operation.  One practice that is
becoming increasingly more common is the use of coil tubing. Coil tubing refers to a long flexible metal
tube that is stored on a large spool. The tube is inserted down the well production tubing to perform the
backwash.   The method is replacing the old method of using rigid threaded pipe sections which takes
more time  and manpower to utilize.  This  operation was the most commonly cited remedial measure
conducted by the facilities in the 1992 EPA Coastal sampling effort.33
                                            vra-38

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        Treating with Solvents, Dispersants, and Other Chemicals - In special cases where injection
wells have suffered loss of receptivity from known or identifiable causes, chemical treatments for the
specific cause may be appropriate.  Treatments of this type include solvents to remove asphaltines or
paraffins, converter type treatments for the relatively acid-insoluble  scales such as calcium sulfate or
barium sulfate,  fresh water for the removal  of salt blocks, and emulsion  breakers  for an emulsion
problem.28

5.2.2.5  Pretreatment of Produced Water Prior to Injection
        Pretreatment of produced water may be necessary to prevent scaling, corrosion, precipitation, and
fouling from solids and bacterial  slimes.   Corrosion and scale deposits lead to decreased equipment
performance and to plugging hi the underground formation.  One method to overcome this problem is
to increase  injection pressures.   However, excessive  injection pressure may  fracture the receiving
formation causing the escape of produced water into freshwater or other mineral bearing formations.
Injection well permits specifically identify the maximum allowable injection pressure which is based on
an estimation of the injection formation fracture pressure.  Also, additional energy (fuel) is necessary to
obtain the higher discharge pressures and consequently results hi increased air emissions.

        Most coastal treatment systems  are classified as closed systems which operate hi the absence of
air.  As stated earlier, all of the non-commercial production facilities visited by EPA hi 1992 used closed
systems.33  This alleviates the problems arising from oxygen induced corrosion, scaling, and chemical
precipitation.  In a closed system, a blanket of natural gas  is maintained over the produced water hi
pipelines and tanks.

        Pretreatment for injection can include gravity separation, gas flotation,  and/or filtration.   At
coastal facilities in the Gulf of Mexico region, the most common form of pretreatment used is gravity
separation (settling) and filtration using cartridge or bag filters.  These technologies can be  used as
treatment prior to discharge or injection, and are described hi detail hi Section 5.2.3.1.  The settling tanks
are usually part of the existing BPT treatment system whereas, the filters are usually installed  with the
injection system to prevent the plugging of the injection formation.  Filters are used especially at facilities
located hi water.  Facilities located over land may opt to delete the filtration step and conduct  periodic
well workovers  instead. Well workovers hi water areas are more expensive (see Section XI.3.2.1.2).
Filtration is discussed hi more detail hi the following section.
                                             VHI-39

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5.2.3   Filtration
       Filtration is widely used for produced water treatment as a polishing step for the removal of
suspended solids following the oil separation processes prior to discharger or injection.  Filtration is
generally utilized to improve the injection characteristics of produced water.28 Filtration using cartridge
filters is commonly used at coastal facilities hi the Gulf of Mexico as a pretreatment step prior to injection
to prevent plugging of the injection formation, and was  included in the compliance cost estimates for the
subsurface injection option for produced water in the coastal Gulf of Mexico region (see Section XI).
Filtration can also be used as a treatment step prior to surface disposal.

       Crossfiow membrane  filtration was investigated  hi detail in the development of the Offshore
Effluent Guidelines where it was determined that widespread use is hampered by operational problems.
Therefore, this technology was not selected for consideration in any options for the coastal subcategory.

5.2.3.1  Cartridge Filtration
       Cartridge filtration involves the passage of water through disposable filter elements (cartridges)
to remove solids.  The cartridges are housed hi a filter chamber that can hold from several, and up to
27 or more  cartridges, depending on the flow capacity of the unit.  Figure VHI-4 presents a schematic
diagram of a typical cartridge filtration system. The filter element consists of a hollow cylinder of tightly
wrapped twine that is several  inches hi diameter.  The cartridges come hi various grades ranging from
five micrometers (u) nominal pore size to 50u or greater. The chamber is arranged so that water enters
one end and is forced tangentially through the fibers of the cartridge to the center and out of one end of
the cartridge.  As solids build up within and on the outside of the cartridges, the pressure drop across
the filter increases. The pressure drop is monitored by the operator and when the pressure drop exceeds
a specified amount, usually between 10 psi and 20 psi, the filter chamber is taken out of service, opened
up, and then the cartridges are replaced with new  ones. The frequency of filter changeout is dependant
on  the quality and flowrate of the influent and was observed in the field to range from several days to
a week or more.

       A typical arrangement  is two sets of filters arranged in parallel, with each set  capable of
processing the entire flow so that the flow can  be alternated from one set to the other to allow for
continuous operation during filter changeout. In some  arrangements, each set of filters consist of two
filters in series with finer grade filters  in the downstream position.  This arrangement extends the life of
the finer filter which will clog up more quickly without prefiltration.
                                             vm-40

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        At the 10 production facilities investigated by EPA in 1992, cartridge filtration was used by three
of the four facilities  that utilized filtration as  a pretreatment step  prior to injection.26  Table VIH-7
presents a summary of the produced water influent and effluent data from these three facilities.  The
cartridge filtration systems used at the three production facilities  consisted of the following: Greenhill
Petroleum at Bully Camp used a single stage  40u filter; Texaco at Bayou Sale  and Texaco at Lake
Salvador used a two-stage filtration system with 25u filters followed by lOu filters.  It should be noted
that each of these facilities used gas blanket systems to prevent air from coming into contact with the
produced water.  When the samples were collected, the samples developed an increase in turbidity after
contact with air. This turbidity increase was the  result of the precipitation of scale particles such as
calcium carbonate that formed when the samples came in contact with air.  This resulted hi an increase
in TSS. Therefore, the observed TSS concentrations in Table VHI-6 may not be  representative of the
actual concentrations as they existed in the  closed systems.

        Oil and Grease reduction averaged 28% across the filters from these three sites. However, one
site realized an 8% increase hi oil and grease concentrations. Of these three sites, only one site employed
chemical addition during water separation and this was a surfactant. Oil and grease reduction across this
filter  averaged 30%, however, oil and grease effluent  concentrations averaged  78.5 mg/1 (the highest
average oil and grease level of all 3 sites).34

        A review of other pollutant reductions across the filters for these three sites does not show notable
reductions.  Other  parameters  including TOC, total phenols, aluminum, lead, benzene,  and toluene
showed increases of 1 to 5%.

        A preliminary estimate of oil and grease effluent limitations using these data resulted hi a daily
maximum of 65 mg/1 and a monthly average of 40 mg/1.34 The long term average was estimated to be
24  mg/1.  As a result of this information, EPA does  not consider cartridge filtration as a candidate
technology for BAT or NSPS because not only  do  pollutant concentrations sometimes increase, but for
the pollutants that are removed, the removal is not  as effective as  improved gas flotation.

5.2.3.2  Granular Filtration
        Granular media filtration involves the passage of water through a bed of filter media to remove
solids.  The filter media can be single, dual, or multi-media beds.  When the ability of the bed to remove
suspended solids becomes impaired, cleaning through backwashing is necessary to restore operating head
                                            vm-42

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                     TABLE VIII-7
INFLUENT AND EFFLUENT POLLUTANT CONCENTRATION MEANS
             FROM CARTRIDGE FILTRATION5
Pollutant
Influent Mean
tesft
(JON Vi£N .TIOINAL/ AND NON-(JONV.t
POLLUTANTS
Total Recoverable Oil
and Grease
Total Suspended Solids
Ammonia as Nitrogen
BOD 5-day
Chemical Oxygen
Demand (COD)
Chloride *
Fluoride
Nitrate/Nitrite
Sulfate
Total Dissolved Solids
Total Organic Carbon
(TOC)
Total Phenols
Total Sulfide
(lodometric)
49,903.50
139,916.67
75,946.67
742,833.33
1,239,333.33
70,753,000.00
803.33
536.17
21,366.67
115,377,666.67
325,150.00
2,362.62
1,000.00
Effluent
Mean(ug/l)
.iNTIONAL
31,426.17
136,791.67
73,936.67
• 677,083.33
1,218,250.00
71,423,083.33
1,130.00
530.31
18,608.33
117,719,166.67
328,175.00
2,407.25
2,175.00
PRIORITY FOJLLU'JL'AJNT MJBTALS
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
60.93
139.92
145.78
430.10
281.28
786.67
560.13
1,022.98
651.58
60.86
134.80
144.53
422.33
273.92
820.00
590.21
5,515.33
394.86
OTHER METALS
Aluminum
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Sodium
Sulfur
Tin
Titanium
Vanadium
Yttrium
1,403.17
50,337.67
28,059.33
2,411,483.33
227.87
15,934.83
485,158.33
1,431.45
155.33
39,042,000.00
2,150.00
299.93
24.07
324.28
21.27
1,426.42
51,124.42
28,750.67
2,413,591.67
223.55
15,993.83
490,460.00
1,443.99
153.99
38,845,166.67
2,195.00
311.83
30.92
322.39
43.98
Pollutant
Influent
Mean (ng/1)
PRIORITY POLLUTANT VOLATILE
Benzene
Ethylbenzene
Toluene
6,689.41
63.24
5,190.74
Effluent .
Mean (ug/l}
ORGANICS
6,721.49
63.10
5,227.20
OTHER VOLATILE ORGANICS
Carbon Bisulfide
m-Xylene
o+p Xylene
Vinyl Acetate
2-Butanone
2-Hexanone
2-Propanone
19.93
193.35
118.47
56.42
221.59
54.67
1,513.29
19.87
184.07
111.64
55.37
223.08
52.75
3,401.09
PRIORITY POLLUTANT SEMI- VOLATILE
ORGANICS
Di-n-Butyl Phthalate
Naphthalene
Phenol
39.79
222.04
946.66
32.50
215.07
936.57
OTHER SEMI-VOLATILE ORGANICS
Benzoic Acid
Hexanoic Acid
n-Decane
n-Dodecane
n-Eicosane
n-Hexadecane
n-Octadecane
n-Tetradecane
o-Cresol
p-Cresol
1 ,2: 3 ,4-Diepoxybutane
2Methylnaphthalene
2,4-Dimethylphenol










7,637.95
1,761.82
210.06
155.67
55.17
221.50
52.83
72.88
107.47
312.70
70.77
75.67
183.74










7,355.70
2,064.23
109.34
252.75
50.33
201.25
48.50
72.74
147.06
257.83
76.64
72.67
184.64










                       Vin-43

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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.28  Figure Vm-5 shows the schematic of a multi-media granular filter.

       The offshore three-facility  study evaluated granular filtration systems designed to pretreat
produced water following oil separation and prior to injection.35  These particular operations inject
produced water either because of a zero discharge permit requirement or for enhanced oil recovery. The
three facilities evaluated were: Conoco's Maljamar Oil Field near Hobbs, New Mexico; Shell Western
E&P, Inc. - Beta Complex off Long Beach, California; and the Long Beach Unit -Island Grissom which
is owned by the City of Long Beach, California, and operated by THUMS Long Beach Company.

       EPA statistically analyzed the data from these facilities to determine effluent levels achievable
from add-on granular media filtration technology.  Table VHI-8 presents the performance of granular
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 flocculants to enhance separation, thus improving filtration performance.

5.2.3.3 Crossf/ow Membrane Filtration
       Crossflow membrane filtration  is an  ultrafiltration process.  The process operates  at low
pressures, less than 100 pounds per square inch (psi).  The membrane pore sizes range from 0.03 to 0.8
micrometers.  Crossflow filtration  minimizes  the accumulation of participates on the  surface of the
membrane by flowing the feed stream over the surface of the membrane to sweep away part of the
accumulated layer on the membrane.  Figure Vin-6 presents the flow dynamics of a crossflow filter.
Crossflow filtration requires recirculation of the process stream that may be several orders of magnitude
greater than the rate  of filtration.  The advantage of crossflow filtration is that the membrane's life and
periods between cleaning cycles are  extended through constant membrane scouring by the particulates in
the produced water stream.36  In addition to the high velocities of produced water across the membrane
surface to prevent membrane  fouling, some systems utilize a backflow of permeate (i.e.,  filter effluent)
through the membrane to dislodge any oil or solid particles embedded within the pores of the membrane.

       Several types of crossflow membrane filters have been pilot or field  tested for the treatment of
produced water.  The two common  types of membrane materials are an inorganic ceramic material and
                                            vra-44

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                                        2' 6" Anthracite

                                        3' 2" No. 3 Sand
                                        V 6" Stratified Rock
       Figure VIII-5
Multi-Media Granular Filter
           vra-45

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                                        TABLE Vin-8
                   GRANULAR MEDIA FILTRATION PERFORMANCE35
_
Thums Long Beach
(With Chemical Addition)
Filter Influent
Filter Effluent
% Removal
*
Conoco, Hobbs
(With Chemical Addition)
Filter Influent
Filter Effluent
% Removal
T5SCmg/i)*

43.27
25.65
40.7%

102.84
48.77
53%
O&G (mg/Db

20.75
11.22
46%

34.54
10.90
68%
 * TSS concentrations represent flow weighted averages of paired samples for each day of sampling.
 b Composite sample concentrations estimated by the arithmetic average of sample concentrations within a day.

an organic polymeric material.  Membrane module  designs include hollow fiber,  spiral wound, and
tubular. Many systems require either pre-filtration or chemical treatment to prevent rapid membrane
 fouling and flux  degradation. For flux restoration,,  some systems utilize on-line membrane cleaning,
such as backpulsing, while others require system shutdown and physical cleaning of the membrane. This
technology was investigated during the development of the Offshore Guidelines.

       One type  of crossflow membrane filtration system is currently being operated on two different
platforms located in the Gulf of Mexico.  One is a 5,000 barrel per day full scale unit processing a partial
stream (slip stream) of the produced water for waterflood injection purposes.37  The ceramic membranes
used in these filtration modules are made of porous alumina. The alumina membranes have a pore size
of 0.8 microns.  The produced water stream is chemically pretreated with ferric chloride.  Through a
hydrolysis reaction between the produced water and ferric chloride, a ferric hydroxide floe is formed.
The ferric  hydroxide floe develops a precoat layer on the surface of the membrane and serves as a
"dynamic membrane."  This "dynamic membrane" is unique to this system and allows water to permeate
through the ceramic membrane while reducing the rate of accumulation of oil and oil wet solids on the
membrane surface. A backpulse cycle serves to constantly replace the "dynamic membrane" with a fresh
                                           vra-46

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                                           2
                                           £>


                                           0)
                     VIII-47

-------
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.38

       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
sampling program also analyzed the filtration process for removal efficiencies and potential concentration
of TSS, organic compounds, metals, and radionuclides.  Table Vm-9 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 hi
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.39

       A more detailed description of this technology can be found hi the Offshore Development
Document.2
                                            vra-48

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                                TABLE Vm-9

     MEMBRANE FILTRATION PERFORMANCE DATA FROM THE MEMBRANE
                            FILTRATION STUDY39

Pollutant Parameter
Oil & Grease
Freon (mg/1)
Hexane (mg/1)
Total Petroleum Hydrocarbon
(mg/1)
TSS (mg/1)
Priority and Non-conventional
Organic Pollutants:
Benzene
Benzoic 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
Radionuclides:
Gross Beta (pCi/1)
Radium 226 (pCi/1)
Radium 228 (pCi/1)
Influent {fig except where noted)
MM*

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 {j£g except where noted)
MBS*

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
                                   vm-49

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5.2.4   Activated Carbon Adsorption
       Activated carbon is a material which selectively removes organic contaminants from wastewater
by adsorption. Activated carbon can be used both as an in-plant process for the recovery of organics and
as an end-of-pipe treatment for the removal of dilute concentrations of organics from wastewater prior
to discharge or recycle.  Key design parameters for  an activated carbon unit include the quantity and
quality of wastewater to be treated, the required effluent quality, type and quantity of activated carbon,
the empty bed contact time, and the breakthrough capacity before regeneration is necessary.

       Generally, activated carbon systems are preceded by treatment systems such as chemical treatment
or filtration to remove the suspended  solids  and any other materials which might be present in the
wastewater and which interfere with the adsorption phenomenon.  Presently, activated carbon is not
generally used in the treatment of produced water from oil and gas wells.

       EPA determined that carbon  adsorption is not technologically available to implement as a basis
for BAT or NSPS limitations for the treatment of produced water from coastal oil  and gas production.
This is because of the  lack of treatability information related to the effects of the  brine-like nature of
produced water on the  adsorption process, either from literature or from pilot or full-scale studies.
                                            vni-so

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6.0   REFERENCES

1.     SAIC, Statistical Analysis of the Coastal Oil and Gas Questionnaire. Final Report, January 31,
       1995.

2.     EPA, Development Document for Effluent Limitation Guidelines and New Source Performance
       Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category.
       EPA 821-R-93-003. January 1993.

3.     SAIC, "Oil and Gas Exploration and Production Wastes Handling Methods hi Coastal Alaska,"
       January 6, 1994

4.     Hanchera, D.,  Marathon Oil Corp.,  Letter to Erickson, M., SAIC,  regarding  Production
       Activities information for Platforms in Cook Inlet, April 12, 1994.

5.     SAIC, "Statistical Analysis of Effluent from Coastal Oil and Gas Extraction Facilities (Final
       Report)", September 30, 1994.

6.     Envirosphere Company, Summary Report: Cook Inlet Discharge Monitoring Study: Produced
       Water.  Discharges Number  016, prepared  for  the  Anchorage  Alaska Offices  of  Amoco
       Production Company,  ARCO  Alaska,  Inc.,  Marathon  Oil  Company, Phillips Petroleum
       Company, Shell Western E&P, Inc., Unocal Corporation, and U.S. Environmental Protection
       Agency, Region 10,  September 1988 through August 1989.  (Offshore Rulemaking  Record
       Volume 220)

1.     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 Rulemaking
       Record Volume 138)

8.     Ferraro, J.M. and S.M. Fruh. "Study of Pollution Control Technology for Offshore Oil Drilling
       and Production Platforms,"  Prepared for U.S. Environmental Protection Agency.  Cincinnati,
       1977.  (Offshore Rulemaking Record Volume 24)

9.     Churchill, R.L., "A Critical Analysis of Flotation Performance," American Institute of Chemical
       Engineers, 290-299, 1978.  (Offshore Rulemaking Record Volume 168)

10.    Sport, M.C., "Design and Operation of Dissolved-Gas Flotation Equipment for the Treatment
       of Oilfield Produced Brines,"  Journal of Petroleum Technology. 918-921, 1970. (Offshore
       Rulemaking Record Volume 168)

11.    Leech, C.A., "Oil Flotation Processes for Cleaning Oil Field Produced Water,"  Shell Offshore,
       Inc., Bakersfield, Ca., 1987.  (Offshore Rulemaking Record Volume 168)

12.    Pearson, S.C., "Factors Influencing Oil Removal Efficiency in Dissolved Air Flotation  Units,"
       4th Annual Industrial Pollution Conference, Houston, Texas, 1976. (OffshoreRulemaking Record
       Volume 168)

13.    Kumar, I.J., "Flotation Processes," Lenox Institute for Research Inc.,  Lenox, Mass., 1988.
       NTIS No. PB 88-180302
                                          vni-si

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14.    Paragon Engineering Services, Houston Texas.

15.    Arnold, K.E., "Equipment and Systems Used to Separate Oil From Produced Water on Offshore
       Platforms," Paragon Engineering Services, Inc., Houston, Texas, 1987. (Offshore Rulemaking
       Record Volume 168)

16.    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.

17.    Brown and Root,  Inc., "Determination  of Best Practicable Control  Technology Currently
       Available to Remove Oil and Gas,"  prepared for Sheen Technical Subcommittee,  Offshore
       Operators Committee, New Orleans, March 1974. (Offshore Rulemaking Record Volume 21)

18.    Lysyj, I., et al.,  "Effectiveness of Offshore Produced Water Treatment," API et al.,  Oil Spill
       prevention, Behavior Control and Clean-up Conference (Atlanta, GA) Proceedings, March 1981.
     ' (Offshore Rulemaking Record Volume 37)

19.    Wyer, R.H., et al.,  "Evaluation of Wastewater Treatment Technology for Offshore Oil
       Production Facilities,"  Offshore Technology  Conference,  Dallas, Texas, 1975.  (Offshore
       Rulemaking Record Volume 168)

20.    Luthy, R.C., "Removal of Emulsified Oil with Organic Coagulants and Dissolved Air Flotation,"
       Journal Water Pollution Control Federation. 1978, 331-346.  (Offshore RulemaJdng Record
       Volume 168)

21.    Rochford, D.B.,  "Oily Water Cleanup Using Gas Flotation," Offshore Technology Conference,
       OTC 5247, 1986.  (Offshore Rulemaking Record Volume 168)

22.    ERCE, "An Evaluation of Technical Exceptions for Brine Reinjection for the Offshore Oil and
       Gas  Industry," prepared for  Industrial Technology Division, U.S. Environmental Protection
       Agency, March 1991. (Offshore Rulemaking Record Volume 119)

23.    Walk, Haydel and  Associates, Inc., "Potential Impact of Proposed EPA BAT/NSPS Standards
       for Produced Water Discharges from Offshore Oil and  Gas Extraction Industry,"  Report to
       Offshore Operators Committee, New Orleans,  LA.   1984.  (Offshore Rulemaking Record
       Volume 16)

24.    American Petroleum Institute. Subsurface Saltwater Injection and Disposal. 1978.

25.    Stewart, Maurice, Minerals Management Service,  New Orleans Office, personal communication
       with Joe Dawley, SAIC, regarding reinjection of produced water in the Gulf of Mexico. May  8,
       1992. (Offshore Rulemaking Record Volume 174)

26.    SAIC, Coastal Oil and Gas Production Sampling Summary Report, April 30, 1993.

27.    Marathon Oil Company and Unocal Corp., "Zero Discharge Analysis Trading Bay Production
       Facility, Cook Inlet, Alaska," March 1994.
                                          VHI-52

-------
28.    Burns & Roe.  Technical Feasibility of Brine Reinjection for the Offshore Oil and Gas Industry,
       May 1981. (Offshore Rulemaking Record Volume 2)

29.    Wetzel, "Limnology," W.B. Saunders Company, Philadelphia, Pennsylvania, 1975.

30.    EPA, "Trip Report to Campbell Wells Land Treatment, Bourg Louisiana, March 12,1992." May
       29, 1992.

31.    API, "Introduction to Oil and Gas Production," 1983.

32.    Dawley J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Technical Feasiblity of
       Replacing Seawater with Produced Water for Waterflooding in Cook Inlet, June 21, 1994.

33.    SAIC,  "Produced Water Injection Cost Study for the Development of Coastal Oil and  Gas
       Effluent Limitations Guidelines," January 27, 1995.

34.    Wiedeman, EPA, Memorandum to Marv Rubin, EPA regarding use of cartridge filtration as
       technology basis for effluent limitation options, June 16, 1994.

35.    SAIC,  "Engineering Report on Granular Filtration Based on the Three Facility Study," prepared
       for the Engineering and Analysis Division, U.S. Environmental Protection Agency, April 8,
       1992.  (Offshore Rulemaking Record Volume 174)

36.    Schweitzer, Philip,A., "Handbook of Separation Techniques for Chemical Engineers,"  Second
       Edition, McGraw-Hill Book Co., New York. Chapter 2. 1988

37.    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 of Offshore Rulemaking Record.

38.    Offshore Operators Committee, "Crossflow Membrane Separation Systems Study," prepared by
       Paragon Engineering Services, project No. 90421, December, 1990.  Submitted as comments to
       56 FR 10664 by  C.T.  Sawyer, American Petroleum Institute, Volume 2, Tab 1, May 13, 1991.
       Commenter number 42,  Volume 142 of Offshore Rulemaking Record.

39.    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.

40.    SAIC.  "Oil & Gas Point Source Category: Trip Report of the U.S. EPA's Visit to the THUMS
       Island Grissom Facility on February  7, 1992." July 16, 1992.   (Offshore Rulemaking  Record
       Volume 165)
                                          VIII-53

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                                    SECTION  IX

                           MISCELLANEOUS WASTE-
 CHARACTERIZATION,  CONTROL AND TREATMENT TECHNOLOGIES
1.0    INTRODUCTION

       This section describes the sources, volumes, and characteristics of miscellaneous waste streams

from coastal oil and gas exploration, development, and production activities. The miscellaneous waste
                  *
streams considered for regulation are:


       •     Well treatment, workover, and completion fluids

       •     Deck drainage

       •     Produced sand

       •     Domestic wastes

       •     Sanitary wastes.


       This section also includes a brief description of the minor waste streams associated with coastal

oil and gas drilling and production and a description of the treatment technologies currently available to

reduce the quantities of pollutants associated with these wastes.


2.0    WELL TREATMENT,  WORKOVER, AND COMPLETION FLUIDS

       The definitions for well treatment, workover, and completion fluids (TWC fluids) are as follows:1
             Well Treatment Fluids are "any fluids used to restore or improve productivity by
             chemically  or  physically altering hydrocarbon-bearing strata  after a well  has been
             drilled."

             Workover  Fluids are "salt solutions, weighted brines, polymers, or other specialty
             additives used in a producing well to allow safe repair and maintenance or abandonment
             procedures."

             Completion Fluids are "salt solutions, weighted brines, polymers and various additives
             used to prevent damage to the wellbore during operations which prepare the drilled well
             for hydrocarbon production."
                                          IX-1

-------
       Table IX-1 lists the data used in the compliance cost analysis for TWC fluids, presented in
Section XII.  These  data include the number of wells discharging TWC fluids, the average volume
discharged per job, and the total annual discharge volumes.  The sources and derivation of these data are
described in the following section.

                                        TABLE IX-1
               DATA USED IN TWC FLUID COMPLIANCE COST ANALYSIS
Fluid
Workover/Treatment
Completion
TOTAL
Number of
Discharging Wells
(1992)
350
334
684
Average Volume
Discharged per
Wei!
(bbls/job)
587
209
—
Total Volume
Discharged per
Year

-------
operations.1  Discharge volumes for specific workover, completion and well treatment activities are
presented in Table IX-2. This information indicates that discharges can range from 100 to 1,000 barrels.4

                                        TABLE IX-2
             TYPICAL VOLUMES FROM WELL TREATMENT, WORKOVER,
                            AND COMPLETION  OPERATIONS4
Operation
Completion and Workover
Well Treatment
Type of Material
Packer Fluids
Formation Sand
Metal Cuttings
Completion/Workover Fluids
Filtration Solids
Excess Cement
Neutralized spent Acids
Completion/Workover Fluids
Volume Discharges (barrels)
100 to 1000
ItoSO
<1
100 to 1000
10 to 50
<10
10 to 500
10 to 200
       A statistical analysis of the results of the  1993 Coastal  Questionnaire shows that in 1992,
workover, treatment, and completion operations in the coastal Gulf of Mexico region discharged an
average of 587 barrels of waste workover/treatment fluids and 209 barrels of waste completion fluids.5
Workover and treatment fluids are presented in this document together because they are both used during
production.  Completion fluids are generated separately during completion just prior to production.  For
the purpose of developing compliance cost estimates, these volumes (presented in the survey as volume
per year)  are assumed to be average  discharges per job because the survey results also  indicate a
workover/treatment fluid discharge frequency of between 0.78 and 1.87 times per year.5  The numbers
of wells discharging TWC fluids were derived from survey results and state Discharge Monitoring Report
(DMR) data. The survey results indicate that in 1992, 219 wells discharged workover/treatment fluids
and 209 wells discharged completion fluids.5 A comparison of the number of wells in the survey to the
number of wells for which DMR data are available revealed that the survey count of wells must be
increased by a factor of 1.6 for an accurate count of existing wells.6  Thus, the estimates of 219 wells
discharging workover/treatment fluids and 209 wells discharging completion fluids were increased to 350
and 334, respectively.  These well counts were then used to estimate the total annual volume of TWC
fluids currently  discharged:   205,450 barrels of  workover/treatment  fluid and 69,806  barrels of
completion fluid, for a total of 275,256 barrels of TWC fluids discharged per year.
                                            rx-3

-------
       Volumes of fluids used for workover, completion, and well treatment operations were collected
for a Cook Inlet Discharge Monitoring Study.  Table IX-3 presents the volumes discharged during
specific operations. Volume information was collected for a one year period. Ten discharge events were
sampled during the course of the year. Each of the discharge events was from a single operation (either
well treatment, workover, or completion) but discharges of the fluids may have occurred at several times
during the course of the operations.7 Average discharge of TWC fluids ranged from 80 to 647 barrels
per job.
                                       TABLE IX-3
 VOLUMES DISCHARGED PER JOB DURING WORKOVER, COMPLETION, AND WELL
          TREATMENT OPERATIONS FROM THE COOK INLET DMR STUDY7

Type of Job
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
320.8
132
Clean Out
Tubing
12
148










12
148
80
       The 1993 Coastal Questionnaire also provided data regarding volumes of TWC fluids discharged
in Cook Met, Alaska.8  Volumes of workover/treannent fluids reported in the survey as discharged
ranged from 300 to 18,000 barrels per well per year.  These volumes were reported by two of the 13
active platforms in Cook Met.  The 18,000-bbl discharge volume was a total  of three discharges
throughout the year, so the average per-job discharge volume is 3,150 bbls of workover/treatment fluid.
Discharged completion fluid volumes ranged from 360 to 2,720 barrels per well for the year, and were
reported for four wells on two different platforms. The average per-job discharge volume is 2,243 bbls
of completion fluids.  A total annual TWC discharge volume for all platforms  hi Cook Met was
                                           IX-4

-------
calculated to be 58,574 barrels per year, based on the above per-job volumes and a seven-year schedule
for drilling new wells and recompletions provided by Cook Inlet operators.9  All discharges of TWC
fluids to Cook Inlet reported in the survey were commingled with produced water for treatment prior to
discharge.
2.2   WELL TREATMENT, WORKOVER, AND COMPLETION FLUIDS  CHARACTERISTICS
2.2.1    Well Treatment Fluids
       In general, well treatment fluids are acid solutions. Acids used include: hydrochloric acid (Hcl),
hydrofluoric acid (HF) and acetic acid (QH^^).  Concentrations of HC1 in water range from 15 to 28
percent.  A mixture of hydrochloric and hydrofluoric acid is also used and is referred to as "mud acid. "2
Mud acid mixtures are 12 percent 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.10
       A well treatment job involves a series of several solutions to be pumped down hole: a pre-flush
solution, the acid solution, and a post-flush or "chaser" solution. The pre-flush solution is generally 3-5
percent ammonium chloride (NH4C1) and forces the hydrocarbons back into the formation to prepare for
stimulation. The acid solution is then pumped downhole.  Following the acid solution is a post-flush of
ammonium chloride that forces the acid further into the formation.11  The solutions remain in the
formation for 12 to 24 hours and are then pumped back to the surface.2

       Common well  treatment  fluids  include:  hydrofluoric  acid,  hydrochloric  acid,   ethylene
diaminetetracetic acid (EDTA), ammonium chloride, nitrogen, methanol, xylene, toluene.  Well treatment
fluids may include additives such as corrosion inhibitors, mutual solvents, acid neutralizers, diverters,
sequestering agents, and anti-sludging agents.4 Additives include:  iron sequestering agents, corrosion
inhibitors, surfactants, viscosifiers, and fluid diverters.12  The purpose of the additives can be  for:
reducing the leak-off rate,  increasing the propping agents carried by the fluid, reducing friction,  and
preventing the aggregation and deposition of solid particles.11 A corrosion inhibitor is always used during
an acid  stimulation job because the acids  used   are extremely  corrosive to the steel piping  and
equipment.2-13  Table LX-4 lists some of the typical chemicals used during well treatment.
                                             IX-5

-------
                                        TABLE IX-4
                            WELL TREATMENT CHEMICALS14
•type of Fluid or Purpose
Fracture or matrix
acidizing agent
Acid stimulation agent
Acidizing fluid
Acid fracturing agent
Self breaking acidizing
emulsion
Acid precursor
Acidizing of siliceous strata
Sequestering additive for
iron and aluminum in acid
stimulation
Fracturing agent
High temperature
fracturing agent
Acid stimulation
Acid fracturing
Constituents
Acrylamide polymer
Gelling agent
Reducing agent
Acid
Vinyl pyrolidine copolymer
HC1
Water
Oxyalkylated acrylamidoalkane-
sulfonic acid polymer
Dialkyldimethyl-ammonium chloride
polymers in aci'd solution
Q-Cjg primary amine
Diethanolamide of Cg-C,8 fatty acid
Kerosene
Acid solution
Carbon tetrachloride
Ammonium fluoride
Levulinic acid
Citric acid
HC1 solution
Hydroxypropyl cellulose
Poly (maleic anhydride) alkyl vinyl
ether
Aluminum salt of phosphate ester in
kerosene
Acetic acid
Acid in oil emulsion
,', X,,, ' , JJose ,„
0.1 to 1.5% by weight.
0.5 to 30% by weight of polymer used
200% of stoichiometric amount of gelling agent used
10% by weight
1% by weight
8% by weight
91% by weight
1% by weight in 15% HC1
0.1 to 1% by weight polymer, 5 to 15%
solution
HC1
0.01 to 0.5% by weight
0.02 to 1.0% by weight
25 to 35% by volume
25 to 38% Hcl solution
10% CO,
90% water
1 to 10% by weight fluoride ion concentration
10 to 400 lb/1000 gallon
10 to 400 lb/1000 gallon
15% HC1 solution
1%
3%
1 % by weight in kerosene
20 to 30%
10 to 28%
2.2.2  Workover and Completion Fluids
       Workover and completion fluids are similar in nature and are typically a variety of clear brine.
Packer fluids are workover or completion fluids which are left in the annulus between the well casing and
tubing at the conclusion of the operation.3 Specific  fluids are used during completion and workover
operations to seal off the producing formation to prevent fluids and solids loss to the formation.  The
formation is sealed by the disposition of a thin film of solids over the surface of the formation.  These
solids are called bridging agents.14  The  bridging agents are oil or acid  soluble and dissolve at the
cessation of workover or completion operations to enable oil or gas to be produced from the  well.15
Commonly used bridging agents are:  ground calcium carbonate, sodium chloride, oil soluble resins, and
calcium lignosulfonates.16   The  fluids are selected to be compatible with the formation to minimize
damage to the formation and should perform the following functions.4'16-17
                                            IX-6

-------
        •       Control subsurface pressures
        •       Maintain hole stability
        •       Transport solids to the surface
        •      , Installation of packer fluids
        •       Keep solids hi suspension
        •       Minimize corrosion
        •       Remain stable at elevated temperatures.

        Workover and completion fluids can be divided into two broad classifications: water-based and
oil-based fluids.  There are three types of water-based fluids: brine water solutions, modified drilling
fluids, and specially designed drilling fluids.

        Brine fluids are comprised of inorganic salts dissolved in water. This combination yields a solids-
free fluid with sufficient density to control sub-surface pressures.16  Brine solutions have a density ranging
from 8.5 pounds per gallon (ppg) for seawater to 19.2 ppg for zinc bromide/ calcium bromide  fluids.17
Table IX-5 lists some of the more common  brine solutions and their densities.  Disadvantages of brine
fluids are: expense (which can reach $800/barrel), the generation of precipitates 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.16

        Modified drilling fluids  contain the necessary additives to achieve the basic functions of a
completion or workover fluid. These fluids are economical to use since they are usually readily available.
The disadvantages of modified drilling fluids is their high solids content (both compressible and 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 needed 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.16
                                              IX-7

-------
                                         TABLE IX-5
  COMMON BRINE SOLUTIONS USED IN WORKOVER AND COMPLETION OPERATIONS16
Brine Solution
Potassium Chloride
Sodium Chloride
Sodium Bromide
Calcium Chloride
Calcium Bromide
Calcium Chloride-Calcium Bromide
Zinc Bromide-Calcium Bromide-Calcium Chloride
' Density gaMon)a
9.7
10.0
12.5
11.6
11.6 to 14.2
11.6 to 15.1
15.1 to 19.2
      a Densities given are the maximum density except where a range is provided.

        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.16

        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.2 Solids control must be maintained
 in workover and completion fluids so that the formation is not irreversibly plugged in the vicinity of the
 wellbore.

        World Oil publishes a yearly guide of commercially available drilling, completion and workover
 fluids. The guide lists  specific additives to the basic fluid and includes the product name, tradename,
 description of material,  recommended uses, product function and the company from which they may be
 obtained.  The primary functions of additives hi completion and workover fluids are listed in the guide
 as corrosion inhibitors, viscosifiers, and filtration reducers.  The corrosion inhibitors such as hydrated
 lime and amine salts are added to the fluid to control corrosion.  The viscosifiers are added to increase
 the viscosity.  The filtration reducers are added  to reduce fluid loss to the formation and can include
 bentonite clays, sodium carboxymethylcellulose, and pregelatinized starch.18 Table IX-6 identifies specific
 additives to completion and workover fluids.
                                             IX-8

-------
                                        TABLE IX-6
                ADDITIVES TO COMPLETION AND WORKOVER FLUIDS4
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.12

2.2.3   Chemical Characterization of Well Treatment, Workover, and Completion Fluids
       The most comprehensive source of analytical data for TWC fluids is an ongoing study of
"associated wastes" by the EPA Office of Solid Waste (OSW), Waste Management Division.19-21  The
term "associated wastes" is used in the OSW study to describe miscellaneous and minor wastes associated
with the exploration, development, and production of oil and gas resources.  This study includes data
from samples of TWC fluids collected hi Texas, New Mexico, and Oklahoma during sampling efforts
in 1992.   Table IX-7 provides the average concentrations of pollutants found  in selected TWC fluid
samples from the OSW study.20 In general, the pollutant characteristics of TWC fluids vary considerably
from job to job.  Therefore, the data in Table IX-7 are listed as ranges as well as averages.

       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
                                            IX-9

-------
                      TABLE IX-7
POLLUTANT CONCENTRATIONS IN TREATMENT, WORKOVER, AND
                  COMPLETION FLUIDS19
•
PoButant Parameter
03& Grease
Solids, Total Suspended
Priority Pollutant Organics
Benzene
Bthylbenzene
Methyl Chloride (Chloromethane)
Toluene
Fluoccnc
Naphthalene
Phenanthrene
Phenol
Priority Pollutant Metals
Antimony
Arsenic "
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Other Non-CooTcntioDals
Aluminum
Barium
Boron

Cobalt
Cyanide, Tool
Iron
Manganese
Magnesium
Molybdenum
Sodium

Sulfur
Tm '
Titanium
Vanadium
Yttnum
Acetone
Methyl Ethyl Ketone (2-Butanone)
M-Xylene
CM-P-Xylene
4-McthyI-2-FenQnone
Dibenzofunn
Dibenzothiophene
N-Decane (N-C10)
N-Docosaae (N-C22)
N-Dodecanc (N-C12)
N-Efcosane (N-C20)
N-Hexacosaae (N-C26)
N-Hexadecane (N-C16)
N-Octacosane (N-C28)
N-Octadecane (N-C18)
N-Tetracosane (N-C24)
N-Tetradecane (N-C14)
P-Cymene
Pcotamethylbcnzene
1-Methylfluorene
2-Methylnaphthalene
Pollutant Concentration (pg/1)
v s .. ., Range
15,000.0 - 722,000.0
65,500.0 - 1,620,000.0

477.0 - 2,204.0
154.0 - 2,144.0
0.0 - 57.0
298.0 - 1,484
0.0 - 123.0
0.0 - 1,050.0
0.0 - 128.0
255.0 - 271.0

0.0 - 148.0
0.0 - 693.0
0.0 - 25.1
7.6 - 82.3
48.0 - 1,320.0
0.0 - 1,780.0
0.0 - 6,880.0
0.0 - 467.0
0.0 - 139.0
0.0 - 8.0
0.0 - 67.3
0.0 - 1,330

0.0 - 13,100.0
66.5 - 3,360.0
4,840.0 - 45,200.0
1,070,000.0 - 28,000,000.0
0.0-40.9
0.0 - 52.0
7,190.0 - 906,000.0
187.0 - 18,800.0
10,400.0 - 13,500,000.0
0.0 - 167.0
7,170,000.0 -45,200,000.0
21,100.0 - 343,000.0
72,600.0 - 646,000.0
0.0 - 135.0
0.0 - 283.0
0.0 - 4,850.0
0.0 - 131.0
908.0 - 13,508.0
0.0 - 115.0
335.0 - 3,235.0
161.0 - 1,619.0
198.0 - 5,862.0
136.0 - 138.0
0.0-222.0
0.0 - 550.0
237.0 - 1,304.0
0.0 - 1,152.0
0.0 - 451.0
173.0-789.0
0.0 - 808.0
0.0 - 422.0
281.0 - 1,868.0
312.0 - 1,289.0
513.0 - 1,961.0
0.0 - 144.0
0.0 - 108.0
0.0 - 163.0
0.0 - 1,634.0
Average
231,688.00
520,375.00

1,341.00
1,149.00
29.00
891.00
62.00
525.00
64.00
263.00

29.60
166.00
8.64
26.08
616.82
277.20
1,376.00
115.52
42.94
1.60
13.46
362.94

6,468.40
498.10
15,042.00
10,284,000.00
8.18
52.00
384,412.00
5,146.00
5,052,280.00
63.00
18,886,000.00
142,720.00
245,300.00
27.00
74.58
1,156.00
41.92
7,205.00
58.00
1,785.00
890.00
3,028.00
137.00
111.00
275.00
771.00
576.00
226.00
481.00
404.00
211.00
1,075.00
801.00
1,237.00
72.00
54.00
82.00
817.00
                         IX-10

-------
operations.  Samples were collected of fluids during five workover operations (one using weak acid,
EDTA), two completion operations, and three well treatments using acid.7

       The samples collected during the Cook Inlet Discharge Monitoring Study were analyzed for pH,
oil  and grease, dissolved oxygen, BOD, COD,  TOC,  salinity, zinc, cadmium, chromium, copper,
mercury, and  lead.  Table  IX-8 summarizes the analytical results from the Cook Inlet Discharge
Monitoring Study.

2.3   WELL  TREATMENT,  COMPLETION,  AND WORKOVER  FLUIDS  CONTROL  AND  TREATMENT
       TECHNOLOGIES
2.3.1   BPT Technology
       The current BPT requirement for TWC fluids is  "no discharge of free oil" to receiving waters,
as determined by the static sheen test.  EPA's general permit limiting the discharges from coastal oil and
gas drilling operations in Texas and Louisiana further prohibits discharges of TWC fluids to freshwater
areas (58 PR 49126). Methods for treatment and disposal include:

       •      Treatment and disposal along with the produced water
       •      Neutralization for pH control and discharge to surface waters
       •      Reuse
       •      Onshore disposal and/or treatment.

       Treatment and disposal of well  treatment, workover, and completion fluids  with the produced
water varies depending on how the fluids resurface, their reusability, and their volume in relation to
produced waters they may be commingled with.  The fluids are often commingled  with the produced
waters, especially where the  proportion of produced water to TWC fluids is high  enough to overcome
the interference the TWC fluids may have on the produced water treatment system.  According to one
industry report,  TWC  fluids can be effectively treated in  the produced  water  treatment system if
commingling is  performed in such a  manner that the treatment system is not subjected to  large
concentrated slugs of TWC fluids.11 Operators hi Alaska also treat and dispose of these fluids with their
produced water.8'23  In California, facilities commingle  the workover, completion and well treatment
fluids with the produced water.2
                                            IX-11

-------
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                                               rx-i.2

-------
        TWC fluids may be treated separately from the production fluid stream if they resurface  as a
discrete slug. It is especially advantageous to separately collect them if they are heavily weighted and
can be reused.  Workover and completion fluids can be reused 2 to 3 times depending on the amount of
oil and grease build-up.   Inexpensive workover and completion fluids consisting primarily of filtered
seawater are typically not reused. However, treatment fluids are not reused because they react with the
formation and lose their treatment ability.2

2.3.2   Additional Technologies Considered
        Additional controls considered for this proposed rulemaldng are limitations on oil and grease or
zero discharge. The,technology basis for these other controls on TWC fluids is commingling and treating
with the produced water or sending the fluids separately to commercial disposal facilities.   A detailed
discussion of produced water treatment technology is presented in Section VHL

3.0    DECK DRAINAGE
        For coastal operations hi the Gulf of Mexico, EPA investigated the deck drainage generated from
drilling operations and production operations separately.   Generally, deck drainage generated during
drilling may vary  in volume,  characteristics, and its method of collection from that generated during
production.  Deck drainage from production operations occurs over a long period of time while drilling
operations occur only for a relatively short and finite period of time.  However, this distinction can not
be made in Cook Inlet, since both drilling and production operations occur simultaneously on the same
platform.

3.1     DECK DRAINAGE SOURCES
        Deck drainage includes all water resulting from spills, platform washings, deck washings, tank
cleaning operations and rainfall runoff from curbs, gutters, and drains including drip pans and work
areas.

        For drilling operations this includes drainage from the drilling deck itself.  For land-based drilling
operations, deck drainage includes runoff from the entire area within the levee surrounding  the drilling
operation which often includes parking areas plus office and living quarters.  Deck drainage at land-based
drilling operations is collected in a ditch that surrounds the entire drilling operation.  Just outside of the
ditch is a levee constructed of the material excavated from the ditch.  This combined levee and ditch,
                                             IX-13

-------
referred  to  as the ring levee,  prevents contaminated runoff from exiting the site  and prevents
uncontaminated offsite runoff from entering the site.

       For water-based (e.g., posted-barge) drilling operations, deck drainage includes drainage from
the drilling deck itself plus all process area drains and exposed areas.  Deck drainage is collected in a
sump tank and is  then pumped into a barge for reuse or disposal.   Deck drainage from relatively
uncontaminated areas such as heliports are often collected and discharged separately from other deck
drainage sources.

       For production operations, deck drainage primarily consists of runoff from diked separation and
treatment equipment and storage tank areas. The deck drainage can include oil and produced water from
spills and leaking equipment, wastes from tank and equipment cleaning operations, and spilled process
treatment chemicals.  The deck drainage is usually collected in a sump or skim tank for treatment and
discharge or it is commingled with produced water for treatment and disposal.

3.2   DECK DRAINAGE VOLUMES
3.2.1   Total Volumes
       Table IX-9 presents the overall total volume of deck drainage disposed by both drilling and
production operations hi the Gulf of Mexico and Cook Inlet.
                                        TABLE IX-9
                   ANNUAL VOLUME OF DECK DRAINAGE DISPOSED
Region
Gulf of Mexico
Cook Inlet
Drilling Operations
, flw) 1
937,286
Production
Operations
py)
10,869,618
628,475
11,498,093
3.2.2   Gulf of Mexico-Production Operations
        The predominant source of deck drainage at production facilities in the Gulf coastal region is from
rain falling within bermed and diked areas.  During the 1992 EPA  10 Production Facility Sampling
                                            EX-14

-------
Programs, it was observed that deck drainage collection systems can cover areas ranging from several
hundred square feet for small satellite tank batteries to much larger areas covering tens of thousands of
square feet. The New Orleans area receives  an average annual rainfall of 53.7 inches of ram compared
to 14.7 inches in Anchorage, Alaska.24  The statistical analysis of the 1993  Coastal Oil  and Gas
Questionnaire data estimated that the average  volume of deck drainage from production facilities is 11,644
bpy.5 By multiplying this value with the estimated 853 total number of production facilities,6 the result
is an estimated total annual deck drainage volume of 9,932,332 bbls for all production facilities in the
Gulf coastal region.  Using the average deck  drainage volume of 11,644 bpy and the rainfall reported for
the New Orleans area in 1992 of 60  inches25 the area covered by the average production facility is
estimated  to be 9,806 square feet.

        For most of the facilities, the proportion of deck drainage to produced water volume will be low.
The  estimated average facility produced water volume reported in  the survey was 701,663 bpy for
facilities that inject and 754,762 bpy for facilities that surface discharge.5  The average deck drainage
volume of 11,644 bpy is only 1.7% and 1.5% respectively of these average produced water volumes.

        Although no one reported that they injected deck drainage in Question A42b of the Questionnaire,
the Summary Statistics indicate that, based on the response to Questions A39b,  19.5% of the facilities
that reported deck drainage data do not discharge produced water and at the same time commingle deck
drainage along with the produced water for disposal.  Therefore, EPA estimates that 7,995,527 bbls
(80.5%) of the total estimated volume generated by production operations is being surface discharged.

3.2.3  Gulf of Mexico-Drilling Operations
        Because of the significant differences in the deck drainage collection area covered and  the
deckdrainage handling equipment, EPA investigated deck drainage from  land-based and  water-based
drilling operations as separate sources. The  two data sources  that were investigated to obtain estimates
of the average volumes of deck drainage generated for disposal from land-based and water-based drilling
operations were the 1993 Coastal Questionnaire data and the three coastal  drilling site visits conducted
by EPA in 1992. After a review of the Coastal Questionnaire and the trip reports, it was determined that
a different method for estimating deck drainage volumes would be necessary for land-based versus water-
based operations.  These methods are discussed below.
                                             IX-15

-------
3.2.3.1 Total Deck Drainage Volumes

       Table IX-10 presents the per well and overall total volumes of deck drainage generated by water-

based drilling operations in the Gulf of Mexico region.  Tables IX-11 and IX-12 present the per well and

overall total volumes of deck drainage generated by drilling operations in the Gulf of Mexico region

based on the data and assumptions presented below.
                                   TABLE IX-10

       ANNUAL DECK DRAINAGE VOLUMES CURRENTLY DISCHARGED FROM
    WATER-BASED DRILLING OPERATIONS IN THE COASTAL GULF OF MEXICO
                                     REGION
•type of Wei!
New and Exploratory
Recompletions and
Sidetracks
Total
„ Total Number of Wells?
152.2
182.4
334.6
Volume Discharged per
Wett^bbl^ _
516
567
-
Total Volume Discharged
' (bbl)
78,535
103,421
181,956
a     See Section 3.2.3.3
b     See Section 3.2.3.4
                                   TABLE IX-11

    LAND-BASED DRILLING OPERATIONS DECK DRAINAGE PER WELL VOLUMES
Type of Well
New and Exploratory"
Recorapletion and
Sidetracks*
Drilling Days
30
15
Volume Generated

-------
                                        TABLE IX-12
      LAND-BASED DRILLING OPERATIONS DECK DRAINAGE TOTAL VOLUMES
                                        ALL WELLS
Type of Well
New and Exploratory
Recompletion and
Sidetracks
Total
Total Number of
Wells1
79.8
95.6
175.4
Volume Generated*

-------
                                        TABLE IX-13
                 PROPORTION OF LAND-BASED VERSUS BARGE-BASED
                   OPERATIONS REPORTED IN THE COASTAL SURVEY
Type of
Response
Truck
Barge
Total
Number of
Responses
to Question
AlSa
26
43
69
%of !
Total :
37.7%
62.3%
100%
Number of 1
Responses to ;
Question
B27*
9
17
26
%of \
Total
34.6%
65.4%
100%
Number of
Responses to
Question.
B28C
8
18
26
%of
Total
30.8%
69.2%
100%
Average %
34.4%
65.6%
100%
* Question A18: What was the rig configuration for your injection well?  Land-based, barge-based, or other?
b Question B27: What was the chosen mode of transporting drilling waste and its capacity? Barge, truck, tug, or other?
c Question B28; How many vessels or vehicles were required to dispose of drilling waste?

Gulf of Mexico coastal area that belong in each of these categories are provided in Table IX-14. Since
the sample size was small for "exploratory" and "sidetrack of existing well" (only four for each), these
two categories were combined with "new production" and "recompletion," respectively. In addition, the
"other and service" wells were predominantly "rig workovers" and some "through-tubing plug backs".
Since "other and service" wells mostly were not drilling operations, they are not included in this analysis.
These numbers are used to calculate estimated annual deck drainage volumes for each type of drilling
operation.  Table IX-15 presents the estimated number of wells in these categories that are land-based
and barge-based using the percentage split described in Table EX-13. For the purposes of estimating the
volumes of deck drainage generated, EPA assumed that new production and exploratory wells are similar
in nature and thus are grouped together.  EPA also assumed the  same is true for recompletions and
sidetracks of existing wells.

3.2.3.4  Volumes Generated Per Well
       The data hi Table IX-13 show that, based on a review of the Coastal Questionnaire, the majority
of the responses were from water-based operations. The one water-based drilling operation from the
three EPA coastal drilling site visits was an unusually deep well and did not report the deck drainage
volume because it was combined with and included in the total volume reported for waste drilling mud
and wash water.26 Therefore, the average volume surface discharged from water-based drilling operations
for exploratory and new production wells, which is 516, was selected for use in this analysis based on
responses to the Coastal Survey database.
                                             IX-18

-------
                                     TABLE IX-14
                           ESTIMATED NUMBER OF WELLS
                DRILLED IN 1992 IN COASTAL GULF OF MEXICO AND
                               DURATION OF DRILLING5
Type
Exploratory
New production
New and Exploratory
Recompletion
Sidetrack of existing
Recompletion and Sidetrack
Other and service
Number
45
187
232
241
37
278
177
Days To
Drill
9.8
21.4
19.3
8.5
10.6
19a
                    a Only one well reported days drilling because most of these wells were "rig
                    workovers" and thus were not drilled.
                                     TABLE IX-15

         NUMBER OF WELLS BY LOCATION AND WELL TYPE CATEGORIES
Access
Land
Land
Water
Water
WeHTyjje
New & Exploratory
Recompletion & Sidetracks
New & Exploratory
Recompletion & Sidetracks
Total Wells
; EaehType
232
278
232
278
Land vs.
Water
Proportions
34.4%
34.4%
65.6%
65.6%
Number of
Wells
79.8
95.6
152.2
182.4
       A review of a printout of the Coastal Questionnaire database shows that the majority of the deck
drainage reported in Table B-9 was from water-based drilling operations.8 Only one entry was clearly
land-based and reported that 1,069 bbls of deck drainage were generated and were tracked 30 miles to

a commercial facility.  The average volume of deck drainage discharged to surface waters from water-
based operations, including all exploratory and new production wells except the one land-based well, was
                                         IX-19

-------
516 bbls per drilling job.  The volumes ranged from 60 bbls to 2,318 bbls.  In general, the higher
volumes were for deeper wells which take longer to drill and therefore generate more deck drainage.

        For water-based recompletions  and sidetracks of existing wells, the estimated  average  deck
drainage volumes discharged for these categories are 824 bbls and 310 bbls respectively.5 These volumes
were averaged together to get the volume of 567 bbls discharged because of the low number of survey
responses for each category; two and three, respectively. The values reported in the questionnaire
database are the volumes disposed and thus already take  into account any  reduction in volume due to
reuse of deck drainage as mud make-up water. This may explain why the recompletion volume is greater
even though the drilling time is lower for recompletions.

        A review of the site visit data in Table IX-16 shows that both of the land-based drilling operations
were deeper wells and longer hi duration than the estimated average well hi the Coastal Questionnaire.5
In the survey, the estimated average well depth was 8,429 ft for exploratory wells and 8,487 ft for new
production wells, and the estimated  average drilling duration was  10 days and 21  days, respectively.
Because the site visit data appear to represent greater than average values, a methodology was developed
for estimating the average volume of deck drainage generated by land-based drilling operations rather than
use the site visit data directly. The methodology utilized the drill site dimensions, annual rainfall  data,
estimated  mud make-up  water volume and  average drilling operation  duration.   Based  on this
methodology, EPA estimates that land-based drilling operations dispose of 5,901 bbls of deck drainage
per well.27 The assumptions used are described below.

3.2.3.5 Assumptions for New and Exploratory Wells
        •       Deck drainage and area runoff are collected hi the cellar and ring levee ditch.
        •       The drilling pad area will be 350 ft x 350 ft with a total surface area of 122,500 sq ft.
               These were the dimensions of the ARCO drilling operation hi the Sabine Wildlife Refuge
               and represent the minimum area requirements.28
        •       Drilling tune will be 30 days.  The estimated average drilling time from the Coastal
               Survey was approximately 20 days (see Table IX-14), however this did not include time
               to test the well and to plug and abandon or complete the well. The additional 10 days
               accounts for these activities.
        •       The amount  of  rainfall is  based on the average  30-day rainfall  for New Orleans
               Louisiana using the 1993 annual rainfall amount of 52.7 inches.29 The 30-day average
               rainfall total is 4.33 niches.
                                             IX-20

-------
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                                       IX-21

-------
       •      Rainwater will be used as make up-water for drilling fluids.30 The amount used will be
              equal to the volume of waste mud generated minus the solids content of the mud.  The
              estimated average volume of mud disposed as reported in the Coastal Survey Statistics
              was 3,038.5 bbls.  The drilling fluid solids content ranged from below 10% to around
              35% by volume at the three sampled drilling operations.26-28'30  A solids content of 35%
              will be used as  a conservative estimate since it will result in a lower volume of deck
              drainage that is recycled.  This results in a deck drainage reuse volume of 1,975 bbls.

3.2.3.6 Assumptions  For Recompletion and Sidetrack of Existing Land-based Wells

       •      Table IX-14 shows that for recompletions and sidetracks, the average days to drill were
              8.5 and 10.5 or  roughly one half the time to drill a new well. Therefore, the amount of
              rainwater generated is assumed to be one-half that of newly drilled wells (i.e., one-half
              the average 30-day rainfall; 15 days  duration). Although recompletions may use smaller
              equipment and smaller pads, there is not sufficient information available to estimate the
              size of the reduction hi volume.  The 15-day average rainfall total is 2.16 inches and is
              based on the New Orleans annual 1993 rainfall data.29

       •      Rainwater will be used as make-up water for drilling fluids.30 The amount used will be
              equal to the volume of waste mud generated minus the solids content of the mud.  The
              estimated average volume of mud disposed as reported in the Coastal Survey Statistics
              was 1,803 bbls  (Note that this volume is close to  half the volume reported for newly
              drilled wells). The drilling fluid solids content ranged from the low 20's to around 35%
              by volume at the three sampled drilling operations. A solids content of 35% will be used
              as a conservative estimate.  This results hi a deck drainage reuse volume of 1,172 bbls.
3.2.4   Cook Inlet Alaska

       For Cook Inlet platforms, deck drainage can originate from both drilling and production activities

and thus are different from the Gulf of Mexico operations discussed above.   Table IX-17 presents the

deck drainage volumes  obtained from the Coastal Questionnaire and an EPA site visit.   Of the 10
platforms in Cook Inlet that transfer produced fluids to shore for separation, only four treat and discharge

their deck drainage at the platform. The remaining six commingle deck drainage with production fluids

and transfer the combined stream to shore-based facilities for separation and disposal of the deck drainage

along with the produced water. At the five platforms that separate produced fluids on the platform, deck

drainage is treated along with the produced water and discharged through the skim pile.  The arithmetic

average of four reported discharge volumes (44,891 bpy) was used by EPA hi studying costs and impacts

of deck drainage options.  By adding the reported volumes to the calculated volumes reported in Table

IX-17, the total volume  disposed from Cook Inlet platforms is estimated to be 628,475 bpy.
                                             IX-22

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                                          TABLE IX-17

      ANNUAL DECK DRAINAGE VOLUMES DISPOSED IN COOK INLET, ALASKA
Facility
Trading Bay
Granite Point
E. Foreland
Dillon
Bruce
Anna
Baker
Tyonek "A"
Platform
King Salmon
Dolly Varden
Steelhead
Monopod
Graylingd
Spark
Spurr
Granite Point1
SWEPI "A"d
SWEPI "C"d
Dillon*
Bruce=
Anna"
Baker0
Tyonek "A"'
Total
Deck Drainage Volume (bbl/yr)
Reported
-
4,000a
-
-
~
-
-
-
65,000=
81,000*
-
29,565 (max. 95,630)b
-
-
-
Average*
44,891
-
44,891
44,891
44,891
44,891
0
44,891
-
~
44,891
-
44,891
44,891
44,891
628,475
        Source:  1993 Coastal Oil and Gas Survey (Operators did not claim confidentiality of information for deck drainage data)
        Source:  Wiedeman, May 1, 1993
        Average Volume = (4,000 + 65,000 + 81,000 + 29,565)74 = 44,891 bbl/yr
        These platforms do not commingle deck drainage with produced fluids. Deck drainage is treated and discharged at the
        platforms.
        These platforms commingle deck drainage with produced water and discharge both at the platform after treatment.
3.3    DECK DRAINAGE CHARACTERISTICS

        Oil and grease are the primary pollutants identified in the deck drainage waste stream.  In addition

to oil,  various other  chemicals used in drilling and production operations may be  present hi  deck

drainages.  The chemicals  may  include drilling  fluids, ethylene glycol,  lubricants,  fuels,  biocides,
surfactants, detergents,  corrosion inhibitors, cleaners,  solvents, paint cleaners,  bleach, dispersants,
coagulants, and any other chemical used hi the daily operations of the platform.31
                                               IX-23

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       EPA's analytical data for deck drainage comes from the data acquired during the Offshore Oil
and Gas rulemaking effort. As part of this effort, EPA evaluated Discharge Monitoring Reports (DMRs)
for deck drainage discharges from 32 oil companies located in the Gulf of Mexico.32  The DMR data
spans two years from May 1, 1981 through April 30,1983 and consists of deck drainage monitoring data
from oil and gas production facilities.  The data do not indicate the location of where the samples were
taken, the treatment of the waste stream prior to sampling, or the analytical method of determining oil
and grease.  The DMR data included oil and grease concentrations of deck drainage discharges. Table
IX-18 presents the monthly averages of deck drainage oil and grease concentrations for the two years
evaluated. The DMR data reports monthly samples taken by the operators. The data do not indicate the
location of where the samples were taken, the treatment of the waste stream prior to sampling, or the
analytical method of determining oil and grease.
                                        TABLE IX-18
    CHARACTERISTICS OF DECK DRAINAGE FROM OFFSHORE GULF OF MEXICO
                                       PLATFORMS32
Oil and Grease In Deck Drainage
(mg/I)

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
       Also, as part of the Offshore Oil and Gas rulemaking effort, EPA conducted a comprehensive
4-day sampling program at three oil and gas production facilities in June of 1989, to  evaluate the
performance of granular filtration technology and to characterize produced water and other miscellaneous
discharges such as produced sand, well treatment fluids and deck drainage.  EPA selected facilities for
the three facility study based on: (1) their use of granular filtration, and (2) the oil and grease level being
comparable to the BPT level prior to filtration.  The facilities selected were from three separate oil and
gas subcategories. The three facilities selected for this study were:  Thums Long Beach Island Grissom
(coastal subcategory), Shell Western, E & P, Inc. - Beta Complex (offshore subcategory), and Conoco's
Maljamar Oil Field (onshore subcategory).33'34'35
                                            IX-24

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       Samples of treated and untreated deck drainage were collected at two of the facilities; the THUMS
facility and the Shell Beta Complex. The range of pollutant concentrations in untreated deck drainage
are presented hi Table IX-19. As can  be seen from the data hi Tables  IX-18  and IX-19,  the pollutant
concentrations can vary widely from place-to-place and over time.  In these samples, eight toxic metals
were detected,  most notably  lead (ranging in concentration from 25  -  325 ug/1) and zinc (ranging hi
concentration from 2,970 - 6,980 ug/1).  The presence of lead,  copper  and zinc may be related to the
presence of these  metals in standard drill pipe thread compound.  Organics were also present including
benzene, toluene, xylene and naphthalene. These organic pollutants are commonly found in oil.

       The content and concentrations of contaminants hi deck drainage can also depend on chemicals
used and stored at the oil and gas facilities. An additional study on deck drainage hi Cook Inlet reviewed
during the development of the Offshore Guidelines showed that discharges from this wastestream may
also contain paraffins, sodium hydroxide, ethylene glycol methanol and  isopropanol.36

3.4   DECK DRAINAGE  CONTROL AND TREATMENT TECHNOLOGIES
3.4.1    BPT Technology
       BPT limitations for deck drainage prohibit the discharge of free oil. Typical BPT technology for
compliance with this limitation is a sump, or skim tank or skim pile which facilitates gravity separation
of any floating  oil prior to  discharge of the deck drainage.  Deck drainage treatment systems typically
use gravity flow to convey the flow, and the skim tanks generally do not require a constant power source
for operation.  Thus, deck drainage generated at facilities located hi powerless remote locations (such as
satellite tank batteries) can be effectively treated.

3.4.1.1   Cook Inlet
       Typical platforms such as those hi Cook Inlet are equipped with drip pans and gutters to collect
deck drainage.  The drainage flows by gravity to a sump where the water and oil are separated  by a
gravity separation process.   Oil hi the  sump tank is recovered and transferred to the oil treater of the
produced water treatment system.  Figure IX-1 is a schematic of a generic production platform flow
system.  The water from the sump is discharged to the surface via a submerged outfall or a skim pile.
Skim piles which  are common only to relatively deep water platforms, such as hi Cook Inlet, remove that
portion of oil which quickly and easily  separates from water (see Figure VDI-1).  They are constructed
of large diameter pipes containing internal baffled sections and an outlet at the bottom. During the period
of no flow, oil will rise to the quiescent areas below the underside of inclined baffled plates where it
                                             IX-25

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                                     TABLE IX-19
        POLLUTANT CONCENTRATIONS IN UNTREATED DECK DRAINAGE33'34

Pollutant
Temperature (°C)
Conventionals (mg/1)
pH
BOD
TSS
Oil & Grease
Nonconventionals
TOC (mg/1)
Aluminum (pg/1)
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Sodium
Tin
Titanium
Vanadium
Yttrium
Priority Metals Otg/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
151xl04-568xl04
<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 (/tg/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.

of no flow, oil will rise to the quiescent areas below the underside of inclined baffled plates where it
coalesces.  Due to the differences in specific gravity, oil floats upward through oil risers from baffle to
baffle.  The oil is collected at the surface and removed by a submerged pump.  These pumps operate
intermittently and will move the separated oil  to a sump tank. Oil recovered hi the sump is combined
                                         IX-26

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                                          a
                                        ^ as
IX-27

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with production oil. At some facilities deck drainage contaminated with oil is commingled with produced
water and is treated in the produced water treatment system.

       One of the platforms examined hi the Cook Met 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 hi batches.
Chemicals are added and circulated to extract the hydrocarbon from the  water.  The mixture is retained
in the tank for a period of time to allow the oil and water to  separate by gravity.  The water is discharged
to the sea.  The remaining liquid is transferred  to  another slop tank for holding and reprocessing.
Sampling results indicated a mean average oil and grease content of 3.8  milligrams per liter.36
                    %

       Some platforms ha Cook Inlet collect crank-case oil separately and oil-based muds are diverted
from the platform dram systems for onshore separation and treatment. Deck drainage is either piped to
shore with the produced water waste stream and treated by gas flotation or gravity separated on the
platform and treated by  gas flotation to an average of 25 mg/1 oil and grease.36

       At the Bruce Platform hi Cook Inlet, deck drainage from diked areas flows to a 300-bbl skim tank
where oil is skimmed off and pumped to the oil processing system. The effluent from the skim tank is
then commingled with produced water hi two 600-bbl settling tanks. The combined effluent is discharged
10 feet below  the water surface.23

       On the jackup drilling rig, Adriatic 8, contaminated deck drainage is retained hi the drilling deck
area using four inch collars.   The deck drainage is collected in a 20-bbl skim  tank that can hold
approximately one week's worth of deck drainage.  The water then passes through a 7-ft high by 2-ft
diameter separator and is then discharged.23

3.4.1.2  Gulf of Mexico-Production Operations
       Typical production operations hi the Gulf area that use elevated platforms are equipped with drip
pans and gutters to collect deck drainage and direct it to  a sump where oil sldmmhig occurs prior to
discharge below the water surface.  Skim piles are not used because of the generally shallow water.
Figure IX-2 presents a schematic diagram of a sump/skim tank.  In this  tank, deck drainage enters near
the bottom at one end and passes over a baffle into a quiescent zone where oil floats to the surface. The
separated oil passes over a weir and is pumped to the  oil-water treatment unit such as a gun barrel.
                                             IX-28

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               Deck
               drainage
               collected in
               diked area
Pumped
back to
oil/water
separation
in production
system
                                                   Valve
                                                  normally
                                                   open
                              Sump Tank
Pumped back
  to oil/water
separation in
  production
     system
              Surface of surrounding water
                                           Skim Pile
                                          (deep water
                                        platforms only)
                                                       Water
                                                     discharge
                                   Figure IX-2
                         Deck Drainage Treatment System
                                      IK-29

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Treated deck drainage exits the skim tank from a port near the bottom of the tank and passes through an
inverted "U" shaped pipe and  is discharged below the water surface.  The inverted "U" shaped pipe
controls the liquid depth in the tank and is referred to as the water leg. These tanks are usually installed
below the deck near  the water surface to  take advantage of using gravity flow in the deck drainage
collection system.

        Operations that are located on land or fill are usually equipped with earthen or concrete beams
with a depression in one area that acts as a sump to collect drainage.  The collected water may be either
sent to a treatment system, commingled with produced water for treatment and disposal, or discharged
without treatment. Three of the 10 coastal facilities sampled by EPA in 1992 commingled deck drainage
with produced water prior to treatment and subsurface injection.37  Three facilities used skim tanks prior
to surface discharge and the remaining five discharged deck drainage without treatment, if no sheen was
visible.

3.4.1.3 Gulf of Mexico-Drilling Operations
        Deck drainage is periodically pumped from the ring levee ditch or collection sump and is disposed
by one or more of the following four methods: (1) hauled offsite in vacuum trucks or barges for disposal,
(2) reused as make-up water in drilling fluids, (3) subsurface injection through the annulus  of the
intermediate casing of the well being drilled or (4) surface discharge.

        Deck drainage from  the drilling deck contains a considerable amount of  drilling fluid and is
almost always collected, treated, and disposed in the same manner as waste drilling fluids.  For many
land-based drilling operations in the Gulf region, at least a portion of the deck drainage, particularly site
runoff,  is used as make-up water for drilling fluid.  For deck drainage that is not reused in this manner
and does not meet the state discharge limitations, the treatment and disposal method is either annular
injection or transportation to and disposal at  an offsite commercial  facility.   For water-based drilling
operations, deck drainage is  collected in a sump tank and can be combined with waste mud for  offsite
disposal.   Although  deck drainage from oil-base  drilling  operations can be  treated using gravity
separation, EPA observed that the common practice is to dispose of the untreated water by injection or
transport it to a commercial disposal facility.26'28'30
                                              rx-30

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3.4.2   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"  (SWEPI "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. It was found,
through a telephone conversation with a senior process engineer in Cook Inlet, that mixing of the deck
drainage and produced water is only conducted when the deck drainage stream fails the visual sheen test,
while some operators diverted deck drainage to a sump tank to be treated and discharged.38  As noted
earlier, three  of the ten Gulf coastal production facilities visited by EPA in 1992 commingled deck
drainage with produced water prior to treatment and disposal by subsurface injection.  For platforms that
use shore-based oil/water separation, the deck drainage wastewater that fails the sheen test is diverted and
pumped to shore along with produced water for treatment.  A  corrosion inhibitor and/or an oxygen
scavenger is usually added to compensate for the introduction of the oxygen-enriched deck  drainage
water.

        Difficulties encountered in commingling the whole deck drainage waste stream with the produced
waste water stream include:12

        •       The resulting flow variations could seriously upset the produced water treatment facility.
        •       Deck drainage water, saturated with oxygen, when combined with the salt content
               of the produced water could result in higher corrosion rates in the equipment.
               Also, the oxygen may combine with iron and sulfide in the produced water can
               causing the formation of solids which foul treatment equipment;
        •       Detergents, used for washing oil off the decks, cause emulsification of oil and
               seriously upset the produced water treatment processes.

        While the total volume of deck drainage is less than the total volume of produced water generated
annually,  the  deck drainage sent to the  produced water  treatment system could  create hydraulic
overloading of the equipment because of the highly variable nature of the flow rate.  An add-on treatment
specifically designed to capture and treat deck  drainage, other than the type of sump/skim pile systems
typically used, is not technologically feasible.  Deck drainage discharges are not continuous discharges
and they vary  significantly in volume. At tunes 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
                                             IX-31

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drainage would have to have a large treatment capacity, be idle at most times, and have rapid startup
capability.

       Since zero discharge for all deck drainage poses problems with storage and handling capacity
during severe storm events, EPA considered the capturing of only the first 500 bbls (first flush) and
commingling it with produced water for disposal at production operations and commingling it with
drilling wastes for disposal at drilling operations.  Rainfall in excess of the 500 bbl volume would be
subject to BPT limitations.  The volume of 500 bbls was selected because it is a standard storage tank
volume and would capture approximately 3.5 inches of rainfall at an average production operation (see
Section Xffl.3.2).  The installation of larger tanks was considered to be too costly.

       The current BPT limitations allows for use of non-powered systems that utilize gravity to collect
and treat deck drainage.  The commingling of the first flush volume has several technical problems
including:

       •      Above-deck storage tanks would require the installation of a sump and high capacity
               pumps  (e.g.,two 200-gpm pumps) to handle sudden surges in flow.
       •      Many coastal  facilities are unmanned and have no power source available to them.
               Generators or fuel powered pumps would be required at these locations that otherwise
               would not need them.
       •      Facilities that do not have a power source capable of driving high capacity pumps would
               need to use gravity to direct the first flush volume to the storage tank.  This would
               require the installation of the tank below the deck which may not be feasible in many
               instances.
       •      Control systems that would prevent the overflow of an already full tank, during severe
               or back-to-back storms would be required.
       •      The storage tanks would require additional deck space that would add significant costs,
               especially for water-based facilities.
       •      Isolating the first flush at land-based drilling operations, that use ring levees, would be
               difficult because the first flush volume could become mixed with deck drainage already
               in the ring levee at the time of a storm event.  The installation of a separate collection
               system, including pumps and tanks, would add significant cost.

       The volume of contaminated deck drainage can be  reduced by segregating the clean area of the
site from the potentially contaminated area.39  This involves using a segregation berm to separate the
office trailer and parking/truck maneuvering areas which generate relatively little pollution from the
                                             DM2

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drilling equipment, pipe racks, and waste storage areas. Such a set up which also recycled the dirty water
into the mud system was  reported to result in a 40% savings to location and waste management costs.39
Direct measurement of Figure 6 in the Longwell and Akers article indicated that 44 % of the drill pad was
segregated as the clean area and that the storage .volume in the ditch (ditch length) was also reduced by
44%. The storm water from the non-contaminated side of the drilling site is assumed to be clean enough
to be discharged without treatment.  Other ways of reducing rainfall contamination are methods of "Best
Management Practices" which are described in Section XVII of this document.

4.0   PRODUCED SAND
       Produced sand consists of the accumulated formation sands and other particles (including scale)
generated during production as well as the slurried particles used in hydraulic fracturing.  This waste
stream also includes sludges generated by chemical flocculation used in solids separation processes for
produced water such as filtration or sedimentation.  The following sections describe the sources, volumes,
characteristics, and treatment methods for produced sand.

4.1    PRODUCED SAND SOURCES
       Produced sand is generated during oil and gas production by the movement of sand particles in
producing reservoirs into the wellbore, by silica material spilling off the face of the producing formation
and by the precipitation  of scale  and other solid  particles.  The generation of produced sand usually
occurs hi reservoirs comprised of young, unconsolidated sand formations.40 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).41

       Produced sand is  carried from the reservoir to the surface by the fluids produced from the well.
The well fluids stream consists  of hydrocarbons (oil and/or gas), water, and sand. At the surface, the
production fluids are processed to segregate the specific components.  The produced sand drops out of
the well  fluids stream during the separation  process  due to the force of gravity as the velocity of the
stream is decreased during passage through the treatment vessels.  The sand accumulates at low points
in the equipment and is removed periodically through sand drams, manually during equipment shut-downs
for cleaning, or by periodic blowdowns as a wet  sludge containing both water and oil.42  One source
indicates that desanders or desilters (hydrocyclones) are used to remove  sand if the volume produced is
high.41  However,  observations during the EPA  1992 Production Sampling Program indicate that for
                                             IX-33

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lower production volumes more typical of coastal situations, sand removal is primarily achieved by tank
cleanouts and that desanders are seldom used.37 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.43

4.2   PRODUCED SAND VOLUMES
       The generation rate of produced sand will vary between wells and is a function of the amount of
total fluid produced, location of the well, type of formation, production rate and completion methods.41'42
Oil producing reservoirs will typically generate more produced sand than gas producing reservoirs.  This
is because oil reservoirs generate more liquids (both oil and water) which are more viscous than gas and
thus the liquids will remove and carry the sand more easily to  the surface than gas.  Also, the greater
water volumes associated with oil reservoirs will create more scale particles. Another reason is because
gas producing wells have sensors that detect sand flowing with the gas stream to prevent erosion on the
production equipment due to sand flowing with the gas  at high velocities.44  Table IX-20 presents a
summary of the produced sand volumes data.
                                        TABLE IX-20
                        PRODUCED SAND VOLUMES GENERATED

Source
Oil & Gas
Questionnaire
Trip Reports
Giflf of Mexico
Produced Sand
Generated
74 bblsa
106 bbls37
400 bbls37
Frequency
1/2.9 yr3
1/1 yr37
1/1 yr37
, , , Cook Inlet
Produced Sand
Generated
365 bbl8
Ibbl8
Ibbl8
Ibbl8
600 bbl23
Frequency
—
1/2+yr23
a:
Estimated average from SAIC, September 30, 1994.5
4.2.1    Gulf of Mexico
       224 production separation facilities in the Gulf of Mexico provided produced sand data in the
1993 Coastal Questionnaire.8 Of these 224, a total of 37 facilities reported produced sand generation
                                            IX-34

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volumes.  The average volume generated was 74 bbls.  Since produced sand is not collected from process
equipment every year, the survey only represents a snapshot of produced sand collection for the year of
1992.  The average frequency of generation of produced sand for these 37 facilities ranged between 2.2
times per year and once every 2.9 years. Although only 16.5 % of the facilities reported produced sand
volume data, this does not indicate that  83.5% of the facilities did not generate any produced sand that
year. It indicates that either these facilities did not generate any produced sand, or no produced sand was
collected from the process equipment for that year, or that the volume was unknown.

        The annual sand generation rates obtained during EPA's 1992 10 production facility study ranged
from 106 to 400 bbls for facilities with produced water flowrates of 6,462 and 7,000 bpd respectively.37
In addition, one of the two commercial produced water injection facilities sampled by EPA in  1992
reported an annual sand generation rate of 50 bbls with an average produced water flowrate of 5,000
bpd.45  It  is likely that some of the produced sand in the produced water received by the commercial
facility would have settled out in the production equipment and produced water storage tanks prior to
being sent to commercial disposal.

        The questionnaire indicates that  only one of the operators surveyed discharged produced sand at
three of their facilities in 1992.  The operator indicated that this practice would be discontinued in the
near future.46  All other operators dispose of produced sands via landfarming,  underground injection,
landfilling, or onsite storage.  The total sand production from the three sites discharging sand was 144
bbls which is a small proportion of produced sand generated hi the region.

4.2.2   Cook inlet
        Four of the  platforms in Cook Inlet reported produced sand generation volumes hi the  1993
Coastal Questionnaire.8  One reported generating 365 bbls  hi 1992 while the remaining three reported
only one bbl for 1992.  Operators of the Bruce Platform hi Cook Inlet reported that they had removed
600-bbls of produced sand for disposal from then: two 600-bbl produced water settling tanks two years
prior to EPA's visit  in August 1993.23 Therefore, the amount generated per platform can vary greatly.
The current produced sand disposal practice in Cook Inlet is zero discharge via land disposal and storage
for future land disposal.47-48   In the past, produced sand from the Bruce Platform had been sent to the
Kenai Gas Field for storage.  This produced sand has recently been ground and injected as part of a pilot
project to grind and  inject stored wastes and the contents of old reserve pits.23
                                             IX-35

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4.3    PRODUCED SAND CHARACTERIZATION
        Produced sand is generally contaminated with crude oil from oil production or condensate from
gas production.  The primary contaminant associated with produced sand is oil.12  The oil content of
unwashed produced sand can range from a trace (expected in sand from blowdown) to as much as 19
percent by volume.

        During the EPA 1992 Production Sampling effort, samples of settling tank bottoms were collected
at four facilities and analyzed for conventional, non-conventional, organic pollutants and metals  and
radionuclides.37  These samples are considered representative of produced sand. Table IX-21 presents
the maximum and mmimum concentrations detected hi these samples.  Due to a limited volume available
at some,of these sites, not all analytes were analyzed for all  of the samples.  For the two samples that
were analyzed for oil content, the concentration ranged from 12.7 to 19 percent. All toxic metals were
present except silver, with most notable contributions from copper  (32.15 mg/kg) and  lead (171.94
mg/kg).49 The toxic organic pollutants present were similar to those found in produced water including
benzene, ethylbenzene, toluene, xylene, propanone, and phenanthrene.

4.4    PRODUCED SAND CONTROL AND TREATMENT TECHNOLOGIES
        The primary control and treatment technology for produced sand is preventing the sand from
exiting  the formation.  Sand control is determined by the  type of  well  completion.  A specialized
completion can prevent sand from being brought into the production line with the fluids.44 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 D£-3 presents a schematic diagram of a closed hole perforated
completion with gravel packing.
                                            IX-36

-------
                    TABLE IX-21
RANGE OF POLLUTANT CONCENTRATIONS IN PRODUCED SAND
FROM THE 1992 COASTAL PRODUCTION SAMPLING PROGRAM49
Pollutant
Unite
Number of
Samples
Number of
Detects
Minimum
Vaiae
Maximum
Value
CONYKN ilONAL AN& NON-COSTVifilNXlONAL
Total Recoverable Oil & Grease
Oil Content
Total Solids
BOD 5-day (Carbonaceous)
Total Organic Carbon (TOC)
Ph
Chloride
Fluoride
Nitrate/Nitrite
Total Releasable Sulfide
Total Sulfide (Isometric)
Aig/kg
%
Mg/kg
A«/kg
Jig/kg
Ph
Jig/kg
Pg/kg
Atg/kg
ftg/kg
Pg/kg
3
2
3
3
3
3
3
3
3
3
3
3
2
3
3
3
3
3
3
1
1
2
84,000.00
12.70
76.00
16,000.00
20,000.00
6.70
1,360.78
1.30
9.30
120.00
26.14
328,562.87
19.00
1,052,084.21
161,413.51
285,693.11
10.50
25,000.00
368.25
19.00
200.00
2,000.00
, KaORlTYPOLIJU'rANrMEXAJLS
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Thallium
Zinc
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
NQN-PKIOR]
Aluminum
Barium
Boron
Calcium
Cobalt
Iron
Magnesium
Manganese
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
4
4
4
4
4
4
4
4
4
4
4
4
1
2
3
2
4
4
4
1 •
4
1
1
4
0.30
8.30
0.10
0.93
3.70
6.50
25.70
0.10
4.90
4.00
2.70
63.80
4.50
34.0*
0
0.20
2.20
26.60
72.00
510.00
0.20
12.50
4.00
2.70
11,700.00
TY POLLUTANT METALS
4
4
4
4
4
4
4
4
4
4
2
4
4
4
4
4
4
4
4
4
4
4
4
4
2
4
2
4
3
4
4
4
879.00
201.00
26.80
6,020.00
1.70
4,650.00
602.00
54.50
1.60
13,300.00
131.00
1,570.00
3.80
14.60
2.90
2.30
71,100.00
3,680.00
328.00
23,500.00
3.50
14,300.00
3,030.00
121.00
15.70
32,800.00
256.00
5,890.00
349.00
60.80
18.60
5.80
PRIORITY JPOJLUJX&m' V«LA'ttU£ QSGAMCS
Benzene
Ethylbenzene
fg/kg
Ag/kg
3
3
3
3
55,352.86
33,170.00
283,445.00
296,995.00
                       IX-37

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                    TABLE ES-21
RANGE OF POLLUTANT CONCENTRATIONS IN PRODUCED SAND
FROM THE 1992 COASTAL PRODUCTION SAMPLING PROGRAM49
Pollutant
Methylene Chloride
Toluene
Trichlorofluoromethane
Units
Atg/kg
Ag/kg
Mg/kg
KEumber of
Samples
3
3
3
Number of
Detects
2
3
2
Minimum
' Value
193.37
89,417.14
30,707.14
Maximum
Value
54,140.35
355,835.00
250,754.39
NON-PRIORITY POJLLUTANT VOLATILE QKti-AINUJS
M-Xylene
O-t-P Xylene
2-Propanone
Pg/kg
/•tg/kg
Pg/kg
3
3
3
3
2 .
1
18,827.14
70,039.68
222,183.05
161,610.00
116,645.00
222,183.05
PRIORITY POLLUTANT SEM-VOLATILE ORSjANICS
Acenaphthene
Anthracene
Bluorene
Naphthalene
Phenanthrene
2,4,6-Trichlorophenol
Mg/kg
Pg/kg
/tg/kg
Pg/kg
Jig/kg
Ag/kg
3
3
3
3
3
3
1
1
2
3
2
1
8,511.33
10,442.33
12,115.33
46,547.00
19,739.00
139,153.33
8,511.33
10,442.33
19,521.00
57,003.33
26,779.67
139,533.33
NON-PMOmTYPOJXtTTAIWSEMI-VOLATIOE ORGANICS „;
Acetophenone
Biphenyl
Dibenzofuran
Dibenzothiophene
n-Decane
n-Docosane
n-Dodecane
n-Eicosanc
n-Hexacosane
n-Hexadecane
n-Octacosane
n-Octadecane
n-Tetracosane
n-Tetradecane
n-Triacontane
1-Methylfluorene
1-Methylphenanthrene
1-Phenylnaphthalene
2-lsopropylnaphthalene
2-Jyiethylnaphthalene
2-Pnenylnaphthalene
3,6-Dimethylphenanthrene
4-Aminobiphenyl
Pg/kg
ftg/kg
Atg/kg
Aig/kg
/tg/kg
/tg/kg
/tg/kg
^g/kg
^g/kg
/*g/kg
Pg/kg
Atg/kg
/tg/kg
/tg^g
/tg/kg
^g/kg
/*g/kg
/ig/kg
Atg/kg
fg/kg
Mg/kg
/tg/kg
Aig/kg
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
1
2
1
2
3
3
3
3
3
3
3
3
3
3
3
3
2
1
1
2
2
1
1
50,996.67
25,620.33
15,397.00
4,873.33
7,302.67
53,659.33
50,642.33
139,153.33
20,380.00
250,070.00
5,543.67
225,183.33
64,200.00
253,220.00
16,789.00
31,473.33
10,717.33
5,124.00
39,190.00
96,533.33
6,012.00
19,858.33
31,025.67
50,996.67
50,769.33
15,397.00
6,826.33
169,263.33
199,183.33
716,843.33
333,090.00
123,716.67
554,033.33
150,746.67
463,686.67
187,440.00
439,433.33
393,873.33
88,670.00
38,270.00
5,124.00
39,190.00
155,923.33
6,871.33
62,333.33
31,025.67
RAMONUCLIBES
Gross Alpha
Gross Beta
Lead 210
Radium 226
Radium 228
pCi/g
pCi/g
pCi/g
pCi/g
pCi/g
4
4
4
5
5
1
4
3
4
3
834.00
12.00
4.20
2.60
2.70
872.00
668.00
11.70
6.90
6.50
                       EX-38

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                                          Production
                                            Tubing
                                                 Cement
                                                  Casing
Hanger
                                                          Liner Cemented
                                                               and
                                                            Perforated
                                                           Sands


                                                            Gravel  Pack

                                                           Screen
                               Figure IX-3
            Closed Hole Perforated Completion (With Gravel Pack)
                                 IX-39

-------
        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.44 In addition,
produced sand contained in liquids such as oil and water do not pose as great a physical erosion problem
due to the lower velocities of these fluids and the lubricating properties of the liquids.

4.4.1    BPT Technology
        The management of produced sand wastes involves either treating the sand to meet the no free
oil limitations and discharge to the surface waters or land application or hauling the sand to a commercial
facility for final disposal.

        Of the 10 coastal production facilities in the Gulf of Mexico region visited by EPA in 1992, only
one reported  onsite disposal of produced  sand.  At this  facility located in Texas, produced sand is
removed from the produced water treatment tanks and deposited on the ground within the diked area.
Samples are collected for oil and grease analysis and if the concentration is below 1.0 percent, they are
allowed to dispose of the produced sand by spreading it on their sand and gravel roads.50 The remaining
nine production facilities reported that they transport produced sand to commercial disposal facilities.

        Data from the  1993 Coastal Questionnaire indicate that 4.6 percent of the coastal facilities in the
Gulf of Mexico inject produced sand and that the remainder is either landfilled, stored onsite for future
disposal, hauled offsite for disposal or is encapsulated and disposed in abandoned wells.5

        Since only one operator  in the Gulf of Mexico reported discharge of  produced sand and that
operator reported their intention to discontinue this practice in the near future, this information indicates
that the current practice  of the industry is zero discharge.  The one operator that reported discharge of
produced sand indicated that the  sand was  first treated by sand washing prior to disposal.46  A detailed
discussion of sand washing technology and its capabilities is presented below.
                                              IX-40

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4.4.2   Additional Technologies
        Several methods other than zero discharge via land disposal 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, thermal treatment
and air flotation.  Most of the sources consulted did not provide data or cleaning efficiencies for the
treatment of produced sand.

        The only technology for which performance data are available is sand washing with detergents.
Data submitted from an industry supported study for the offshore subcategory demonstrate the variability
of oil content in washed sand.  The oil content of washed produced sand in the study ranged from 0.99
to 4.6  percent  by weight.51   Data submitted by the industry regarding sand washing  technology
performance at offshore sites demonstrates that even in the case of a sand washing system that generates
sand capable of meeting a no free oil limitation, residual liquids and solids (by-products from washing)
remain which are unable to meet the no free oil limitation and must be disposed in a matter other than
surface discharge.52

        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.53 Actual data were not presented.
        •      A  sand cleaning system consisting of two vertical  two-phase separators.   The initial
               separator is baffled and sand falls through to the second separator. The  second separator
               contains a solvent layer to absorb oil from the sand grains.53 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.54

        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 and therefore the
addition of extra platform space would be required.   Sand washing  does not always guarantee one-
hundred percent discharge of the sand.  Sands containing heavy oils cannot always be washed thoroughly
enough to meet the permit discharge prohibition on free oil.  In these cases, the  sand cannot be
                                             IX-41

-------
discharged and must be transported offsite for disposal.  Since sand washing is designed to only reduce
the oil content, produced sand that contains certain levels of Naturally Occurring Radioactive Material
(NORM) must be transported to shore for disposal depending on state requirements. In addition, sand
washing can generate additional wastes, such as oily solids and oily water,  which require  further
treatment and disposal.

5.0   DOMESTIC WASTES
5.1    DOMESTIC WASTE SOURCES
       Domestic wastes (gray water) originate from sinks, showers, laundry, food preparation areas, and
galleys on the larger facilities. Domestic wastes also include solid materials such as paper, boxes, etc.

5.2   DOMESTIC WASTE VOLUME AND CHARACTERISTICS
       The volume of domestic waste discharged has been estimated to range from 50 to 100 gallons per
person per day, with a BOD of 0.2 pound per day per person.36-55  For drilling rigs, rather than require
flow measurement, the State of  Louisiana requires operators to report the estimated domestic waste
volume as equal to 0.7 bbs/day (30 gal/day) per person occupying the rig.26  The  1993 Coastal
Questionnaire statistics estimate that 76 percent of production facilities discharge domestic/sanitary wastes
with an average volume of 2,049 bpy (282  bpd).5   It often is necessary to utilize macerators with
domestic wastes to prevent the release of floating solids.  Chlorination is not necessary since these wastes
do not contain coliforms.  Tables IX-22 and IX-23 summarize the volume and characteristics of domestic
wastes for offshore platforms which would reflect domestic waste in Cook Inlet.

5.3   DOMESTIC WASTE CONTROL AND TREATMENT TECHNOLOGIES
       Because domestic wastes do not contain fecal coliform, no chlorination  is required.  Domestic
wastes must only be ground up so as to comply with the NPDES permit prohibitions on discharges of
floating solids. Maceration by cornminutor should be sufficient treatment.  Treatment such as macerators
will guarantee that this discharge will not result hi any floating solids. In addition, many existing NPDES
and State permits prohibit discharges of foam (as no visible foam).  Where existing discharges may be
experiencing discharges of foam, measures taken to remediate the situation can include the relocation of
the discharge to  a standpipe with a subsurface discharge location and careful selection and use of
detergents.
                                             K-42

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                                     TABLE IX-22
    TYPICAL UNTREATED COMBINED SANITARY AND DOMESTIC WASTES FROM
                               OFFSHORE FACILITIES56
Number of
Persons
76
66
67
42
10-40
Hew
(gal/day>
5,500
1,060
1,875
2,155
2,900
BOD
(mg/1)
Average
460
875
460
225
920
Range
270-770




Suspended Solids

10-180




                                    TABLE IX-23
    TYPICAL OFFSHORE SANITARY AND DOMESTIC WASTE CHARACTERISTICS57
Waste Type
Sanitary Waste
(treated)
Domestic Waste
(direct discharge)
Discharge
State
{n^/eapftfay)
0.075
0.110
Loading
BOD
{kg/fiap/day)
0.002
0.022
S.S
Ikgfcap/day)
0.003
0.016
Concentration
BOD
(fflgfl)
30
195
S,S
(tag/1)
40
140
Residual
Cfdorine

-------
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 MAKPOL 73/78 as part of its  pollution regulations (33 CFR-Part 151) governing U.S.
waters.

       Disposal from drilling rigs are dealt with in Regulation 4 of Annex V of MARPOL.  It states that:
       (1)    Fixed or floating platforms engaged in the exploration, exploitation,  and
              associated offshore processing of sea-bed mineral resources, and all other ships
              alongside such platforms or within 500 meters of such platforms, are forbidden
              to dispose of any materials regulated by this Annex,  except as permitted by
              paragraph (2) of this Regulation.
       (2)    The disposal into the sea of food wastes when passed through a comminutor or
              grinder from such fixed or floating drilling rigs located more than 12 nautical
              miles from land and all other ships when positioned as above. Such comminuted
              or ground food wastes shall be capable of passing through a screen with openings
              no greater than 25 mm.
       Table IX-24 summarizes the garbage discharge restrictions from fixed or floating platforms.

       In summary, under the Coast Guard Regulations, discharges of garbage, including plastics, from
fixed and floating platforms engaged in the exploration, exploitation and associated offshore processing
of seabed mineral resources are prohibited with the exception that food wastes may be discharged from
fixed and floating platforms located beyond 12 nautical miles from the nearest land (33 CFR 151.75).

6.0   SANITARY WASTES
6.1    SANITARY WASTE SOURCES,  VOLUMES AND CHARACTERISTICS
       The sanitary wastes from offshore oil and gas facilities are comprised of human body wastes from
toilets and urinals.  The volume and concentration of these wastes vary widely with time, occupancy,
platform characteristics, and operational situation.

       EPA compiled U.S. and international regulations governing the discharge of sanitary waste into
ocean waters from manned ships and manned fixed or floating platforms.  International waters are
governed by MARPOL 73/78, Annex IV which deals specifically with the disposal of sewage from ships.
The Federal Water Pollution Control Act (FWPCA) §312 (33 U.S.C. 1322) administered/implemented
                                            IX-44

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                                           TABLE IX-24
                           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 Vessels^ (33 CFR 151.73)
Disposal prohibited (33 CFR 151.67)
Disposal prohibited
Disposal prohibited
Disposal prohibited
Disposal prohibited
Disposal prohibited less than 12 miles from
nearest land and in navigable waters of the U.S.
See note 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.
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.58  Monthly average sanitary waste flow from Gulf Coast platforms was 35 gallons per day
based on discharge monitoring reports.59  For drilling rigs, rather than require flow measurement, the
State of Louisiana requires operators to report the estimated sanitary waste volume as equal to 0.00006
MGD/day (60 gal/day) per person occupying the rig.26 The EPA 1993 Coastal Oil and Gas Questionnaire
statistics estimate that  76 percent of production facilities discharge domestic/sanitary  wastes with an
average volume of 2,049 bpy (282 bpd).5
                                               IX-45

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6.2   SANITARY WASTE CONTROL AND TREATMENT TECHNOLOGIES
       There are two alternatives to handling of sanitary wastes from coastal facilities.  The wastes can
be treated at the 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
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 feed 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 wastestream.
                                              IX-46

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7.0   MINOR DISCHARGES
       The term "minor" discharges is used to describe all point sources originating from coastal oil and
gas drilling and production operations, other than produced water, drilling fluids, drill cuttings, deck
drainage, produced sand, well treatment, completion and workover fluids, and sanitary and domestic
wastes. The following sections identify these discharges followed by a brief description.

7.1    BLOWOUT  PREVENTER  (BOP) FLUID
       An oil (vegetable or mineral) or antifreeze solution (glycol) is used as hydraulic fluid in blowout
preventer (BOP) stacks during drilling of a well.  The blowout preventer is designed to maintain the
pressure in the well that cannot be controlled by the drilling mud. Small quantities of BOP fluid are
discharged periodically to the sea floor during testing of the blowout preventer device.  Such discharges
are limited to deep water operations such  as in Cook Inlet.   BOP fluid released  from above water
applications would be captured as deck drainage and treated and disposed accordingly.

7.2    DESALINATION UNIT DISCHARGE
       This is the residual high-concentration brine discharged from distillation or reverse osmosis units
used for producing potable water and high quality process water.  The concentrate is similar to sea water
in chemical composition. However, as the name implies, anions and cations concentrations are higher.
This waste  is discharged directly to the surface as a separate waste stream.

7.3    FIRE CONTROL SYSTEM TEST WATER
       The local water source which may be treated with a biocide,  is used as test water for  the fire
control system on platforms and other facilities. This test water is discharged directly  as a separate waste
stream.

7.4    NON-CONTACT COOLING WATER
       Non-contact, once-through water is  used to cool crude oil, produced water,  power generators,
and various other pieces of machinery at production and drilling operations.  Biocides can be  used to
control biofouling in heat exchanger units. Non-contact cooling waters are kept separately and discharged
directly to the surface.
                                            IX-47

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7.5    BALLAST AND STORAGE DISPLACEMENT WATER
        Two types of ballast water are found in production and drilling operations: tanker and platform
ballast. Tanker ballast water can be either salt/brackish water or fresh water from the area where ballast
was pumped into the vessel. It may be contaminated with crude oil (or possibly some other cargo such
as fuel oil),  if the vessel is not equipped for segregated cargo and does not have segregated ballast tanks.

        Unlike tank ballast water, which may be from  multiple sources  and  may contain added
contaminants, platform stabilization (ballast) water is taken on from the waters adjacent to the platform
and will, at  worst, be contaminated with stored crude oil and platform oily slop water.  Newly designed
and constructed floating storage platforms use permanent ballast tanks that become contaminated with oil
only in.emergency situations when excess ballast must be taken on.  Oily water can be treated through
the oil/water separation process prior to discharge.

7.6    BILGE WATER
        Bilge water is a minor waste for floating platforms.   Bilge  water  is seawater that becomes
contaminated with oil and grease and with solids such as rust, when it collects at low points in the bilges.
This bilge water is usually directed to the oil/water separator system used for the treatment of ballast or
produced water, or is discharged intermittently.

7.7    BOILER SLOWDOWN
        Purges from boilers circulation waters necessary to minimize solids build-up are intermittently
discharged to the surface.

7.8    TEST FLUIDS
        Test fluids are discharges that would occur if hydrocarbons are located during exploratory drilling
and tested for formation pressure and content.

7.9    DlATOMACEOUS  EARTH FILTER MEDIA
        Diatomaceous earth filter media are used to filter seawater or other authorized completion fluids
and then washed from the filtration unit.
                                             IX-48

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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 hi Cook Inlet 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 hi 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 analyzed.
The volume of this waste stream is relatively small and is not expected to pose significant environmental
problems. Freon may be present in laboratory waste. Because freon is highly volatile, it will not remain
                                            IX-49

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in aqueous state for very long. The Agency is discouraging the discharge of chlorofluorocarbon to air
or water media.

7.15   CARTRIDGE FILTERS
        Filtration using cartridge filters is commonly used at coastal facilities as a pretreatment step prior
to injection to prevent plugging of the injection formation and was included as  a pretreatment in the
subsurface injection option for produced  water in the Gulf of Mexico region. Cartridge filters are not
reusable and must be disposed as solid waste when replaced. The waste filters are typically disposed in
sanitary landfills.

7.16   NATURAL GAS GLYCOL DEHYDRATION WASTES
        A common step in processing natural  gas  is dehydration using a desiccant such as  triethylene
glycol.  In this process natural gas is brought into contact with a glycol stream which has an affinity for
and adsorbs water vapor.  The glycol is then passed through a reboiler where the water is distilled out
of the solution.  This vaporized water is then condensed into a liquid waste stream.  This  waste stream
may be returned to the produced water treatment and disposal system or it may be surface discharged.
Sometimes impurities will build up in the glycol solution requiring that it be replaced. Spent glycol can
be regenerated onsite through distillation or it is hauled offsite for regeneration or disposal.

7.17   MINOR  WASTES VOLUMES AND CHARACTERISTICS
        Information concerning the characteristics, discharge volumes, and the frequency of discharge
of these minor  waste streams is limited.   Table IX-25 provides a range of discharge volumes for the
minor waste streams that were identified for the offshore category. Data concerning the characteristics
and  volumes of test fluids,  diatomaceous earth filter media, bulk transfer operations,  and painting
operations are not available.
                                             rx-so

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           TABLE IX-25
MINOR WASTE DISCHARGE VOLUMES15
Waste
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
Cartridge filters
Glycol dehydration condensate
Discharge Volume
10 - 500 gal/day
0 - 5 bbl/day
typically <238 bbl/day
24 bbl/test
7 - 124,000 bbl/day
70 - 620 bbl/day
up to 4,030 Ib solids/month
Unknown
Unknown
Unknown
Unknown
Unknown
1,300 - 2,500 cartridges/year
Unknown
              rx-51

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8.0   REFERENCES

1,     EPA, "Development Document for Effluent Limitations Guidelines and New Source Performance
       Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category
       (Final)," January 1993.

2.     Memorandum  from Allison Wiedeman, Project  Officer to Marv Rubin, Branch  Chief.
       "Supplementary Information to  the  1991 Rulemaking  on Treatment/Workover/Completion
       Fluids," December 10, 1992.

3.     American Petroleum Institute.  "Detailed Comments on EPA Supporting Documents For Well
       Treatment and Workover/Completion Fluids."

4.     Parker, M.E.,  "Completion, Workover, and Well Treatment Fluids," June 29, 1989.

5.     SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31, 1995.

6.     Jones, A., ERG Memorandum to Niel Patel, EPA, regarding "Estimates for total numbers of
       coastal wells, operators, and production," September 26,1994.

7.     Envirosphere Company. Summary Report: Cook Inlet Discharge Monitoring Study: Workover,
       Completion and Well Treatment Fluids, Discharge Numbers 017, 018 and 019, prepared for the
       Anchorage, Alaska Offices of Amoco Production Company, ARCO Alaska, Inc., Marathon Oil
       Company, Phillips Petroleum Company, Shell Western E&P Inc.,  Texaco  Inc.,  Unocal
       Corporation, and the U.S. EPA Region X, Seattle Washington, April 10, 1987 - September 10,
       1987. (Offshore Rulemaking Record Volume 116)

8.     EPA, Responses to the "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160, July 1993.
       (Confidential Business Information)

9.     Mclntyre, Jamie, SAIC, Memorandum to Allison Wiedeman, U.S. EPA, regarding "Calculation
       of total annual TWC discharge volume for all platforms in Cook Met," December 5, 1994.

10.    Wilkins, Glynda E., Radian Corporation.  "Industrial Process Profiles for Environmental Use
       Chapter 2: Oil and Gas Production Industry,"  for U.S. EPA, EPA-600/2-77-023b.  February
       1977.

11. •   Hudgins, Charles M., Jr., "Chemical Treatments and Usage in Offshore Oil and Gas Production
       Systems."  Prepared for American Petroleum Institute, Offshore Effluent Guidelines Steering
       Committee.  September, 1989.

12.    Arctic Laboratories Limited, et. al., "Offshore Oil and Gas Production Waste Characteristics,
       Treatment Methods, Biological Effects and Their Applications to Canadian Regions," prepared
       for Environmental Protection Services, April 1983. (Offshore Rulemaking Record Volume 110)

13.    EPA, "Report to Congress, Management of Wastes from the Exploration, Development and
       Production of Crude Oil, Natural Gas, and Geothermal Energy, Volume 1, EPA/530-SW-88-003.
       December 1987. (Offshore Rulemaking Record Volume 119)
                                           IX-52

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14.    Walk, Haydel and Associates, Industrial Process Profiles to Support PMN Review:  Oil Field
       Chemicals, prepared for EPA,  undated but received by EPA on June 24, 1983. (Offshore
       Rulemaking Record Volume 26)

15.    SAIC, "Summary of Data Relating to Miscellaneous and Minor Discharges from Offshore Oil
       and Gas Structures," prepared for Industrial Technology Division, U.S. Environmental Protection
       Agency, February 1990.  (Offshore Rulemaking Record Volume 118)

16.    Meyer, Robert L. and Rene Higueras Vargas.  "Process of Selecting Completion or Workover
       Fluids Requires Series of Tradeoffs."  Oil and Gas Journal.  January 30, 1984. (Offshore
       Rulemaking Record Volume 30)

17.    Acosta, Dan.   "Special Completion Fluids Outperform Drilling Muds."  Oil and Gas Journal.
       March 2, 1981.

18.    "World Oil's 1987 Guide to Drilling, Completion and Workover Fluids," World Oil.  June 1994.

19.    Straus, Matthew A., Director,  Waste  Management  Division, EPA Office  of Solid Waste,
       Memorandum to Thomas P. O'Farrell, Director, Engineering and Analysis Division, EPA Office
       of Water,  regarding "Use of OSW Oil and Gas Exploration and Production Associated Waste
       Sampling and Analytical Data,"  October 4,  1994.

20.    Sunda, J., SAIC, Memorandum  to Allison Wiedeman, U.S. EPA,  regarding "The exclusion of
       certain samples from compilation of OSW TWC data," December 1, 1994.

21.    Souders, Steve, EPA Office of Solid Waste, Memorandum to Allison Wiedeman, EPA Office of
       Water, regarding "1992  OSW  Oil and Gas  Exploration and Production Associated Wastes
       Sampling - Facility Trip Reports," October 27, 1994.

22.    Sunda, J., SAIC  Memorandum to Allison Wiedeman, U.S. EPA, regarding "The exclusion of
       certain samples from compilation of OSW TWC data," December 1, 1994.

23.    Wiedeman, "Report to Alaska-Cook Inlet and North Slope Oil and Gas Facilities, August 25-29,
       1994," August 31, 1994.

24.    Miller, A., and Thompson, J.,  "Elements of Meteorology 2nd.   Ed.".  Charles  E. Merrill
       Publishing Company. Columbus, Ohio. 1975.

25.    Sunda, J., SAIC, Communication with WVUZ-TV, New Orleans, regarding rainfall data for the
       New Orleans area, May 13, 1994.

26.    U.S. EPA. "Trip Report to Unocal City, Louisiana, September 8-9, 1993," Freshwater Bayou,
       Vermillion Parish, La. January 25, 1994.

27.    Sunda, J., SAIC, Memorandum  to Allison Wiedeman, U.S. EPA,  concerning the estimation of
       deck drainage volumes generated by land-based drilling operations, December 15, 1994.

28.    U.S. EPA. "Sampling Trip Report to ARCO Oil and Gas Drill Site, Black Bayou Field, Sabine
       Wildlife Refuge,  Lake Charles, Louisiana, July 21 & 22, 1993." October 21,  1994.
                                           IX-53

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29.    Britton, S., Louisiana Office of State Climatology, Louisiana State University. Facsimile to
       J.Sunda regarding daily precipitation data for New Orleans, Lake Charles, and Galveston for
       1993 and 1994. October 18, 1994.

30.    U.S. EPA. "Sampling Trip Report to Gap Energy Drill Site, Holmwood, Louisiana, June 16 &
       17, 1993." June 8, 1994.

31.    Dalton, Dalton, and Newport, Assessment of Environmental Fate and Effects of Discharges From
       Oil and Gas Operations, March 1985.

32.    Burns and Roe Industrial Services Corp., "Review of USEPA Region VI Discharge Monitoring
       Report, Offshore Oil and Gas Industry," draft 1984.

33.    ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
       Wastes at the THUMS Long Beach Company Agent for the Field Contractor Long beach Unit -
       Island Grissom City of Long  Beach - Operator,"  Draft, prepared  for Industrial Technology
       Division, U.S. Environmental  Protection Agency, March 1990. (Offshore Rulemaking Record
       Volume 113)

34.    ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
       Wastes at the  Shell Western E & P, Inc.  - Beta Complex," Draft, prepared for Industrial
       Technology Division, U.S. Environmental Protection Agency, March 1990. (Offshore Rulemaking
       Record Volume 114)

35.    ERCE, "The Results of the Sampling of Produced Water Treatment System and Miscellaneous
       Wastes at  the Conoco, Inc. - Maljamar Oil Field," Draft, prepared for Industrial Technology
       Division, U.S. Environmental Protection Agency, revised January 1990.  (Offshore Rulemaking
       Record Volume 115)

36.    Envirosphere Co., Cook Inlet Discharge Monitoring Study: Deck Drainage.  (Discharge 003),
       10 April 1987 to  10 April 1988, prepared for the U.S.  EPA  Region X. No date. (Offshore
       Rulemaking Record Volume 117)

37.    SAIC, Coastal Oil and Gas Production Sampling Summary Report. April 30, 1993.

38.    Hoppy, Brian K., SAIC, telephone correspondence with Fred Duthweiler, UNOCAL,  12 June
       1992 concerning deck drainage treatment practices in Cook Inlet, AK. June 12, 1992. (Offshore
       Rulemaking Record Volume 174)

39.    Longwell, H.J., and Akers, T.J., Exxon Co. U.S.A.,  "Economic Environmental Management
       of Drilling Operations." Prepared for presentation at the  1992  IADC/SPE Drilling Conference
       held in New Orleans, Louisiana, February 18-21, 1992.

40.    ERT, Exploration and Production  Industry Associated  Wastes  Report, prepared for API,
       Document No. 0300-004-008, May 1988.  (Offshore Rulemaking Record Volume 158)

41.    Stephenson,  Dr.  M.,  "Produced Sand: A Presentation  for  U.S.  Environmental Protection
       Agency."  June 29, 1989.
                                           EX-54

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42.    University of Tulsa, Chemical Engineering Department, "Effluent Limitations for Onshore and
       Offshore Oil and Gas Facilities - A Literature Survey," prepared for U.S. EPA Division of Oil
       and Special Materials Control. May 1974. (Offshore Rulemaking Record Volume 22)

43.    OOC, 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. (Offshore Rulemaking Record Volume 155)

44.    Parker, M., Exxon, New Orleans, personal communication with Joe Dawley, SAIC, regarding
       Produced sand generation  volumes  and  washing costs.   September 16,  1992. (Offshore
       Rulemaking Record Volume 174)

45.    EPA, Trip Report to Houma Saltwater in Louisiana.  March 12, 1992. May 29, 1992.

46.    Sunda, J.,  Telephone correspondence with  Dave LeBlanc, Texaco, regarding discharge of
       produced sand. March 24, 1994.

47.    Erickson, M., Telephone Correspondence with Lori Litzen, Shell Western E&P. June 6, 1994
       regarding current practices for produced  sand disposal.

48.    Erickson, M., Telephone Correspondence with Dan Hanchera,  Marathon Oil, June 6, 1994
       regarding current practices for produced  sand disposal.

49.    SAIC, Statistical Analysis of  Effluent from  Coastal Oil and Gas Extraction Facilities.  Final
       Report. September 30, 1994.

50.    U.S. EPA, Trip Report:  Exxon Corporation,  Clam Lake, Texas. September 15,  1993.

51.    Vallejo, R. J., Shell Offshore Inc. Letter to D.J. Bourgeois, Minerals Management Service.
       "Produced Sand Discharge Monitoring Study Interim Data Submittal."  June 11, 1991. (Offshore
       Rulemaking Record Volume 147)

52.    American Petroleum Institute.  "Comments of the American Petroleum Institute in Response to
       U.S. Environmental Protection Agency's Proposed Effluent Limitations Guidelines and New
       Source Performance Standards for the Offshore Subcategory of the Oil  and Gas Extraction Point
       Source Category 56 Federal Register 10664-10715 (March 13,1991)."  May 13, 1991. (Offshore
       Rulemaking Record Volume 142)

53.    Frankenberg,  W.G., and J.H. Allred. "Design, Installation, and Operation of a Large Offshore
       Production  Complex," 1st Annual Offshore  Technology Conference, (Houston, 8/18-21/69).
       Reprint No. OTC 1082, pp. H 117 - H 122, 1969 (V.2).

54.    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.

55.    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. (Offshore Rulemaking Record Volume 32)
                                           IX-55

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56.    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.

57.    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.

58.    Envirosphere Company,  Summary Report Cook Inlet Discharge Monitoring Study:   Excess
       Cement Slurry and Mud, Cuttings and Cement at the Sea Floor (Discharge Numbers 013 & 014)
       10 April 1987 - 10 April 1988, Specific Drilling Events Monitored 4-28-88 - 9-12-89 (Prepared
       for U.S. EPA Region X), no date. (Offshore Rulemaking Record Volume 117)

59.    OSS, Attachment to memo from Division Operations Manager Coastal Division, OSS 2280 to
       Production Superintendents Coastal Division.  "Cleaning  Oily Tank Solids." September  17,
       1990.
                                           IX-56

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                                      SECTION X
          COST AND POLLUTANT  LOADING DETERMINATION OF
                   DRILLING FLUIDS AND  DRILL CUTTINGS
1.0   INTRODUCTION
       This section presents incremental costs and pollutant reductions for the proposed regulatory
options for drilling fluids and drill cuttings. Incremental compliance costs beyond BPT were developed
for each disposal/control option for Cook Inlet, Alaska only.  Compliance costs were not developed for
the other coastal regions where oil and gas activity exists, because, as discussed in earlier sections of this
report, discharges of drilling fluids and drill cuttings do not occur in these areas.

2.0   OPTIONS CONSIDERED AND TOTAL COSTS
       Three disposal options were considered for control and treatment of drilling fluids and  drill
cuttings for this rule.  These options are:
       Option 1:      Zero discharge for all areas except Cook Inlet where discharge limitations require
                     toxicity of no less than 30,000 ppm (SPP), no discharge of free oil and diesel oil
                     and no more than 1 mg/1 mercury and 3 mg/1 cadmium hi the stock barite (these
                     limitations are reflective of current practice in Cook Inlet and are similar to the
                     offshore limitations).
       Option 2:      Zero discharge for all areas except Cook Inlet where discharge limitations would
                     be the  same as Option 1, except toxicity would be set at a limitation between
                     100,000 ppm (SPP) and 1 million ppm (SPP).
       Option 3:      Zero discharge for all areas.
       Costs for any of the options are applicable only to Cook Inlet operators (since they are the only
coastal operators currently not meeting zero discharge). Since Option 1 is reflective of current practice
hi Cook Inlet, no  costs are  attributed to  this option.  Thus, costs and pollutant removals that are
incremental to current practice were only determined for Option 2 and 3. Incremental costs and loadings
above BPT-level limitations were determined for Options 1 and 2 as part the BCT cost test analysis for
those options (see Section 6.0).
                                            X-l

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        Option 1 consists of four basic requirements: (1) a 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 100,000 to 1,000,000 ppm toxicity limitation in Option 2 would
replace the 30,000 ppm requirement hi Option 1.  Options 1 and 2 apply to the drill cuttings as well as
drilling fluids since drilling fluid adheres to cuttings and is discharged along with the drill cuttings.1  The
same pollutants found in drilling fluids are thus found on the wet drill cuttings.

        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 future
entry.2  The toxicity limitation would apply to any periodic blowdown of drilling fluid as well as to bulk
discharges of drilling fluid systems and cuttings.  The term "drilling fluid systems" refers to particular
types of drilling fluids used during the drilling of a  single well.   As an example,  the drilling of a
particular well  may use a spud mud for the first 200 feet, a seawater gel mud to a depth of 1,000 feet,
a lightly treated lignosulfonate mud to 5,000 feet, and finally a freshwater lignosulfonate mud system to
a bottom hole depth of 15,000 feet.  Typically, bulk discharges of spent drilling fluids occur when such
systems are changed during the drilling of a well or at the completion of a well.

        For the purpose of self monitoring and reporting requirements hi 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 tune after 80 percent of actual well footage (not total vertical depth) has been
drilled and up to and including the tune of discharge. This would allow time for a sample to be collected
and analyzed by bioassay and for the operator to evaluate the bioassay results so that the operator will
have adequate time to plan  for the  final disposition of the spent drilling fluid system.  For example, if
the bioassay test is failed, the operator could then anticipate and plan for either land disposal or injection
of the spent drilling fluid system to comply with the effluent limitations.  However, the operator is not
                                               X-2

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precluded  from discharging a spent mud  system prior to  receiving analytical  results,  although the
operation would be subject to compliance with the effluent limitations regardless of when self monitoring
analyses are performed.  The prohibition on discharges of free oil and diesel oil would apply to all
discharges of drilling fluid and cuttings at any time.

        For Options 1 and 2, diesel oil and free oil would serve as "indicators" of toxic pollutants, and
thus these discharges would be prohibited by this rule.  The discharge of diesel oil, either as a component
in an oil-based drilling fluid or as an additive to a water-based drilling fluid, would be prohibited under
these limitations. Diesel oil would be regulated as a toxic pollutant because it contains such toxic organic
pollutants as benzene, toluene, ethylbenzene, naphthalene, and phenanthrene.  The method of compliance
with this prohibition is to: (1) use mineral oil instead of diesel oil for lubricity and spotting purposes;
(2) transport to shore for recovery of the oil, reconditioning of the drilling fluid for reuse, and land
disposal of the drill cuttings; or (3) grind and inject the drilling wastes. 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 polyolefin, vegetable
oil and synthetic hydrocarbon-based fluids,  are available as substitutes for diesel oil and continue to be
developed  for use in drilling systems.  Free oil is being used as an  "indicator" pollutant for control of
priority pollutants, including benzene, toluene, ethylbenzene, and naphthalene.

        Cadmium and mercury would be regulated at a level of 3 and 1 mg/kg, respectively, 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 would be regulated to control
the metals  content of the barite component of  any  drilling fluid discharges.   Compliance with this
requirement would involve use of barite  from sources that either do  not contain these metals or contain
the metals  at levels below the limitation.

        Option 2 would require all operators to meet  the same zero discharge limitation for the drilling
fluids and  cuttings hi all areas except for Cook Inlet.  In Cook Inlet, the drilling fluids and cuttings
discharges  would be required to meet the same limitations as in Option 1 except that a more stringent
toxicity limitation would be imposed.  Instead of meeting a toxicity limitation of 30,000 ppm (SPP), a
toxicity limitation between 100,000 ppm (SPP) and 1  million ppm (SPP) would be met.
                                               X-3

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       The toxicity limitation range of between 100,000 ppm (SPP) and one million ppm (SPP) reflects
the range of toxicity measurements resulting from EPA's evaluation of the current practice for drilling
in Cook Inlet. As discussed previously in section V, an attempt was made in this evaluation to determine
the volumes of drilling wastes being discharged and their respective toxicity levels. Because of the lack
of identified discharge volumes for some of the toxicity test results, this determination could not be
completed.  Using the 83 percent of drilling wastes which reflects the fraction of test results less toxic
than 100,000 ppm (SPP), and coincidentally also reflects the fraction of identified volumes less toxic than
one million ppm (SPP), costs and discharge loadings were developed for this option.  (The method used
to derive this range is separate and distinct from the statistical methodologies generally used by EPA in
effluent guidelines regulations to derive 30-day average and daily maximum limitations calculated from
the 95tK and 99th percentiles, respectively.)  However, due to the above discussed limitations with the
data base, EPA is currently only able to estimate an achievable toxicity limit in the range of 100,000 ppm
(SPP) to one million ppm (SPP). EPA is continuing to evaluate toxicity test results and volumes and any
other data for drilling fluids used and discharged in Cook Inlet in  an effort to derive a more specific
limitation and resulting revisions of costs and loadings. A  supplemental notice presenting the  data and
revised results and soliciting comment may be necessary prior to promulgation.

       For Option 2, the 100,000 to 1 million ppm (SPP) toxicity limitation would  be based on a
combination of recycling and reuse, onshore disposal  or grinding and injection where the limit is  not
attained, and product substitution to attain the limit.  Option 3 would prohibit the discharge of drilling
fluids and cuttings from all coastal oil and gas drilling operations.  This option utilizes grinding and
injection and onshore disposal as a basis for complying with zero discharge of drilling fluids and  cuttings.
The technology option alternatives for Cook Inlet have been developed taking into consideration that Cook
Inlet operations are unique to the industry due to a combination of climate, transportation logistics, and
structural and space limitations.

       Table X-l presents the estimated total costs and annual costs  attributed to each of the three
options presented above.  The derivation of these costs are described hi detail hi the remainder of this
section.

3.0    OVERVIEW OF METHODOLOGY
       To evaluate the incremental compliance costs and pollutant removals associated with regulatory
options considered in this rulemaking, the following information was used:
                                               X-4

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                                          TABLE X-l
            COST OF DRILLING FLUIDS AND CUTTINGS CONTROL OPTIONS
Option
Option 1
Zero discharge for all areas except Cook Inlet where
discharge limitations require toxicity of no less than 30,000
ppm (SPP), no discharge of free oil and diesel oil and no
more than 1 mg/1 mercury and 3 mg/1 cadmium in the stock
barite.
Option 2
Zero discharge for all areas except for Cook Inlet where
discharge limitations would be the same as Option 1, except
toxicity would be set to meet a limitation between 100,000
ppm (SPP) and 1 million ppm (SPP).
Option 3
Zero Discharge for all areas.
Total Costs*
$0
$6,991,463
$23,380,320
Annual Cost
$0
$1,370,685
$3,889,386
       All costs were calculated based on the drilling activity plans or schedules as provided by the industry which
       actually covered a 7-year period, from 1996 through 2002.
       •       Number of new coastal wells that will be drilled and number of existing coastal wells that
               will be recompleted in the 7-year period following promulgation of this rule in the Cook
               Inlet region of Alaska;
       •       Typical volumes of drilling wastes which will be generated from drilling a new well or
               a recompletion;
       •       Characteristics of the drilling waste including additives, volumes and composition; and
       •       Drilling waste disposal equipment, transportation, methods, and costs.

       A set of detailed spreadsheets was  developed for predicting industry-wide compliance costs and
pollutant removals for each regulatory option considered. All costs are for BAT or BCT, and no costs
will be attributed to NSPS since there are no plans for construction of any new development wells from
new platforms in Cook Inlet.  (All well drilling will be from existing platforms and is therefore defined
as existing sources.)  In characterizing the coastal Alaska drilling industry, EPA used the drilling activity
plans or schedules as provided by the industry which actually covered  only a 7-year period, from 1996
through 2002, because no information on drilling beyond this time was available.3 The typical volumes
                                              X-5

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of drilling fluids and cuttings generated during a drilling event were estimated based on information
provided by the industry in the 1993 Coastal Oil and Gas Industry Questionnaires (see Worksheet 1 in
Appendix X-l). The disposal costs were estimated based on the cost and operation information provided
by the industry (see Worksheets 2 to 5 and 2T to 5T in Appendix X-l).

        EPA also considered the logistical difficulties of transporting drilling wastes in the Cook Inlet as
part of its costing analysis of the options.  To achieve zero discharge, certain platforms would transport
drill wastes to  a transfer and storage station on the eastern side of Cook Inlet by  supply boat where it
would be transferred to barges for transport to  an existing landfill  facility on the west side of the Inlet.
During the summer months, during ice conditions, the wastes would be stored at the transfer station until
they could be transported.

3.1     CURRENT PRACTICE
        BPT  effluent limitations for coastal drilling fluids  and cuttings prohibit the discharge of free oil
(using the visual sheen test).  However, because  of either EPA general permits, state requirements,  or
operational preference, no drilling fluids and cuttings discharges are occurring in the North Slope, the
Gulf coast states, or California.  The only coastal operators discharging drilling fluids and cuttings are
located in Cook Inlet.  In Cook Inlet,  neither diesel nor mineral-oil-based drilling fluids or resultant
cuttings may  be discharged to surface waters because they have been shown to cause a visible sheen upon
the receiving waters.  Compliance with the  BPT  limitations may be achieved  either by product
substitution (substituting a water-based fluid for an oil-based fluid), recycle and/or reuse of the drilling
fluid, grinding and injection, or by onshore disposal  of the drilling fluids and cuttings at an approved
facility.

        NPDES permits issued  by EPA  for Cook Inlet  drilling  operations have also included BAT
limitations based on "best professional judgement" (BPJ).  The  permit requirements allow discharges of
drilling fluids  and drill cuttings provided certain limitations are met  including a prohibition on the
discharges of free oil and diesel oil, as well as limitations on mercury, cadmium, toxicity and oil content
(see Section  O for a summary  of the permits).  Operators may employ  any number  of the following
waste management practices to meet those permit limitations:

        •       Product substitution- to meet prohibitions on free oil and diesel oil discharges, as well
                as the toxicity and/or clean barite limitations,
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        «      Onshore treatment and/or disposal of drilling fluids and drill cuttings that do not meet the

               toxicity and clean barite limitations,

        •      Waste minimization - enhanced solids control to  reduce the overall volume of drilling

               fluids and drill cuttings,

        •      Conservation and recycling/reuse of drilling fluids, and

        •      Grinding and injection.


4.0    BASIS FOR ANALYSIS AND ASSUMPTIONS

        The following sections describe the assumptions and input data used to develop compliance costs
                    «
and pollutant reductions for drilling wastes in the Cook Inlet region. These sections include the following

topics:
               Drilling Activity:  The volumes of generated drilling waste were calculated based on the
               number of drilling events and the average volume of waste generated from each drilling
               event.  The generated drilling waste volumes were used in both compliance  cost and
               pollutant loadings analysis.

               Drilling Waste Volumes: The drilling waste volumes were the major component of the
               compliance cost and pollutant loading calculations.  The compliance costs and pollutant
               loadings  were calculated from drilling waste volumes and the unit disposal costs, and
               pollutant concentrations in drilling waste.

               Drilling Fluid Characteristics: The drilling fluid characteristics such as density, percent
               solids, density of dry solids, and concentration of barite were used for the purpose of
               calculating the pollutant loadings.

               Drill Cuttings Characteristics:  The density of drill -cuttings was used to calculate the
               total suspended solids (TSS) loading from the spent drill cuttings.

               Mineral  Oil Content:  The major source of organic pollutants hi the drilling waste was
               assumed  to be the mineral oil pills used to free stuck pipe. The average reported usage
               of mineral oil pills and concentration of organic pollutants present hi the mineral oil were
               the bases for calculating the organic pollutants loadings.

               Barite Characteristics: The major source of metals in the drilling wastes was  assumed
               to be barite.  The amount and characteristics of the raw barite used will determine the
               concentrations of metals hi the drilling fluids.  Stock barite that meets regulated metals
               limitations is referred to as  "clean barite."  For the purpose of calculating the metals
               concentrations in drilling fluids, the metals concentrations of clean barite was used.

               Toxicity  Test Failure Rates: The volume of drilling waste brought to shore for disposal
               is a function of the compliance failure rates. In order to calculate the compliance costs
               and pollutant loadings of Option 1 (30,000 ppm toxicity limit) and Option 2 (1,000,000
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               ppm toxicity limit), the estimated toxicity test failure  rates for these limitations were
               used.
               Grinding and Injection:  For the Cook Inlet operators for whom landfilling of wastes
               is not economical to meet the zero discharge requirement of Option 3, EPA investigated
               the option to grind and inject their drilling waste.
               Transportation and Onshore Disposal Costs:  Local landfill disposal of the generated
               drilling waste in Cook Inlet requires transportation to a transfer station or a temporary
               onshore storage facility via V-hulled supply boats because of sea ice conditions in winter
               time and highly fluctuating tides hi summer.  Barges and/or trucks are used to transport
               the generated drilling waste to a landfill disposal facility from the  transfer station. The
               unit cost of onshore disposal of  the generated drilling waste  was calculated for each
               operator based on information obtained from the industry. These unit disposal costs were
               used to calculate the total compliance costs for Options 2 and 3 based.
       Sources of information and data used to develop compliance costs and pollutant  reductions
include: (1) the Development Document for offshore oil and gas regulations2, (2) the 1993 Coastal Oil
and Gas Questionnaires, (3) correspondence with operators  hi Cook Inlet, (4) communications with
vendors and suppliers serving operation in Cook Inlet, and (5) EPA trip reports. Details of much of the
input data are presented in Section VH.  The following information is specific to this costing effort.

4.1    DRILLING ACTIVITY
       As stated in Section 2.0, the Agency based the incremental cost analysis and pollutant removal
estimations on the total volume of drilling waste generated hi Cook Inlet for the 7-year period following
the promulgation of this rule from 1996 through 2002. The total volume of muds and cuttings generated
was estimated from the projection of the number  of wells  to be drilled by the industry and the average
volume of waste generated from each  well. Table X--2 presents the projected drilling activities of the
operators in Cook Inlet based on information provided by the industry.  Due to the confidential nature
of some of the information provided by the industry, a detailed discussion of the estimates listed in Table
X-2 is provided in a supporting document.3

       Out of the five Cook Inlet operators, information obtained by EPA in 1993 indicated that one of
them had no plans to drill in the Inlet.  Recent (1995) information from an additional Cook Inlet operator
relates that this operator also no longer has plans to drill in the Inlet.3  EPA conservatively estimated that
this operator ("C") would have drilled 6  new wells (out of a total of 36 for all of the Cook Inlet
operators) in the next 7 years.  Due to the fact that this is very recent information, the cost and economic
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                                         TABLE X-2
                  SUMMARY SCHEDULE OF DRILLING ACTIVITIES BY
                          OPERATORS IN COOK INLET, ALASKA
                          FOR 7 YEARS AFTER PROMULGATION3
Operator*
A
B
C
Number of New Wells
to be Drilled
3
27
6
Number of Existing WeHs
to be Recomputed
1
18
0
       Operator identities are confidential.3 Operator B is actually a combination of two companies, but are operated
       by one.
analysis was  performed assuming only one operator, instead of two operators, will not be drilling.
However, retaining the six drillings of Operator "C" in the analysis will not only provide a conservative
estimate of the costs and economic impacts, but may serve to cover future changes in oil and gas activity
should decisions be made to resume drilling.

4.2    DRILLING WASTE VOLUMES
       EPA estimates that the total amount of drilling fluids and cuttings annually generated from the
drilling activities listed above is 79,776 barrels per year.  The volumes of drilling fluid and drill cuttings
generated per drilling event, including new wells and recompletions, were calculated based on the drilling
schedules in Table X-2, and the muds and cuttings generation rates for three well depth intervals as
reported by the industry in the 1993 Oil and Gas Questionnaires. Details of calculations and assumptions
used to determine waste volumes are provided in Appendix X-l.  The methodology used in determining
the typical well depth and the total drill waste generated per drilling event are presented in  the following
paragraphs.

       The methodology used for estimating the industry-wide volume of drilling fluids and drill cuttings
discharged is  based on the volumes generated from production wells drilled in Cook Inlet.  Drilling data
from the 1993 Questionnaires for seven wells were entered in a spreadsheet and the average depths and
volumes of waste generated were calculated. All wells considered hi this estimation were drilled in three
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intervals to an average total depth of 11,765 feet.  The volume of drilling waste (drilling muds and
cuttings) generated from an average 11,765-foot well was estimated to be 14,354 barrels with an average
dry cuttings content of 19 percent by volume (Appendix X-l).  Since no information was available on
the volumes of drilling waste generated during recompletion of existing wells, EPA assumed that the
volume of muds and cuttings generated during an average recompletion is equal to the average volume
of muds and cuttings generated during the last drilling interval of a new well.  This volume was estimated
to be 2,194 barrels and was assumed to contain 19 percent dry cuttings by volume (Appendix X-l). This
volume is a conservative estimate when compared to the volumes estimated for recompletions in the Gulf
of Mexico:  1,803 barrels of fluid and 72 barrels of cuttings per job.4
                     %
        The estimated drilling waste generation rate and the percent dry cuttings were used to estimate
the total volumes of waste fluids and cuttings generated for each operator. The estimated total industry-
wide volume of fluids and cuttings generated is the sum of all volumes estimated for each operator. An
industry source stated that currently, the volume of non-complying drilling waste is generally less than
1 percent of the total generated  waste  volume.5  Therefore, EPA  estimates that one percent  of  all
generated drilling waste in Cook Inlet is currently not meeting the existing permit limitations hi this
region and therefore  cannot be discharged.5  Since all disposal costs are directly proportional to the
amount of fluids and cuttings that are currently generated, all estimated total volumes were reduced  by
one percent (1 %) to reflect current practice.  Thus, the amount of drilling fluids and cuttings discharged
is estimated to be 1% less than the ambient generated. Based on this information, EPA's estimates are
that  approximately 78,978 bbls per year (or a total of 552,846 over the next seven years) are  being
discharged in Cook Inlet.

4.3     DRILLING FLUID CHARACTERISTICS
        Since the drilling fluid characteristics change as drilling proceeds to  greater depths, an average
mud density was assumed  for the purposes of determining  the pollutant loadings.  Based on the
information provided by the industry hi the 1993 Coastal Oil and Gas Questionnaire and information
obtained through sampling trips, EPA assumed a 10 pound per gallon mud with 11 percent solids  by
volume to have the average characteristics (density) of the mud system used over  the entire drilling
project.6  Using the same bases of information, the density of dry solids and concentration of barite in
this mud were estimated to be 1,025 pounds per gallon and 24 pounds per gallon, respectively.7 The
drilling fluid characteristics are also discussed in Section VTI of this document.
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4.4    DRILL CUTTINGS CHARACTERISTICS
        In order to calculate the total suspended solids (TSS) loading due to spent drill cuttings, the
density of drill cuttings was estimated.   Based on a geological stratigraphic profile provided by the
industry, drill cuttings were estimated to have a density of 980 pounds per barrel on a dry weight basis.8
For the purpose of the pollutant loading analysis for this rule,  the volume of dry cuttings was also
estimated based on 19 percent of total volume of drilling wastes.9  Since  dry cuttings are generally
comprised of inert material, no hydrocarbons or metals were assumed  to be present in the dry drill
cuttings.  Drill cuttings characteristics are also discussed in Section VII of this document.

4.5    MINERAL OIL CONTENT
        Based on  information obtained from the 1993 Oil and Gas  Questionnaires, EPA assumed a
mineral oil content of 0.02 percent by volume in the entire volume  of  drilling waste generated from
drilling operations in Cook Inlet.10 Since there are no significant sources of organic pollutants in the
drilling waste other than any oil based lubricant added to the drilling fluid system, it is assumed that the
mineral oil is the only source of organic pollutants in the spend drilling fluid and drill cuttings.  Table
X-3 presents the organic constituents  in the mineral oil used to calculate the pollutant loadings for this
rulemaking.  The concentrations hi Table X-3 are averages of concentrations for three types of mineral
oil presented in the Offshore Development Document.2

4.6    BARITE CHARACTERISTICS
        Barite is the  primary source of metals  (cadmium, mercury, and other priority pollutants of
concern) hi drilling fluids. The characteristics of the raw barite used will determine the concentrations
of metals hi the drilling fluid and thus, provide EPA with the bases to determine pollutant reductions for
each technology option.   The concentrations  of cadmium and mercury are  directly related to  the
concentrations of other priority pollutants of concern in barite.11 The current individual NPDES permits
in Cook Inlet have limitations on the concentrations of cadmium and mercury in the raw (or stock) barite.
 Stock barite that meets regulated metals limitations is referred to as  "clean" barite. For the purposes of
calculating the BAT metals concentrations in drilling fluids, the metals concentrations of clean barite was
used.

        The mean metals concentrations for "clean"  barite are presented hi Table X-4.  The metals
concentrations represent averages  of data from Region 10 Discharge Monitoring Report Data.11   The
                                              X-ll

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                                           TABLE X-3

                        ORGANIC CONSTITUENTS IN MINERAL OIL
                                 (rag/ml, unless noted otherwise)
Organic Constituent
Benzene
Ethylbenzene
Naphthalene
Fluorene
Phenanthrene
Phenol (ug/1)
Alkylated benzenes (a)
Alkylated naphthalene (b)
Alkylated fluorenes (b)
Alkylated phenanthrenes (b)
Alkylated phenols (c)
Total biphenyls (b)
Total dibenzothiophenes (ug/g)
Concentration (mg/ml)
ND
ND
0.05
0.08
0.12
ND
30.0
0.49
1.74
0.14
ND
1.94
370
Notes:  The above data are averages of data presented in Table VH-9 of the 1993 Offshore Development Document for three types
       of mineral oil.2 Averages include only detected values.
       ND = Not Detected for all three types
       (a)  Includes C, through C6 alkyl homologues
       (b)  Includes C, through C5 alkyl homologues
       (c)  Includes cresol and Cj through Q alkyl homologues
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 15 Rig Study from the Gulf of Mexico was incorporated."  The barium concentration reported in

Table X-4 was calculated from the total pounds of barite in the drilling fluid.7  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.2 For the purposes of calculating the pollutant loadings for the BAT options, use of clean

barite was assumed for drilling operations in Cook Inlet, Alaska.
                                              X-12

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                                       TABLE X-4

                        METALS CONCENTRATIONS IN BARITE
Metal
Cadmium
Mercury
Aluminum
Antimony
Arsenic
Barium
Beryllium
Chromium
Copper
Iron
Lead
Nickel
Selenium
Silver
Thallium
Tin
Titanium
Zinc
TICleaa" Barite Concentration
(mg/kg)
l.la
O.la
9,069.9b
5.7"
7.1a
33,000.07
0.7"
240.0a
18.7a
15,344.3"
35. la
13.5.
l.lb
0.7"
1.2b
14.6b
87.5"
200.5b
a  Region 10 DMR Data11
b  15 Rig Study11
4.7    TOXICITY TEST FAILURE RATES

       The volumes of drilling wastes that do not meet discharge limitations were calculated according

to each option considered. EPA assumed that all oil-based drilling fluids would fail the sheen test.
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       Based on the information obtained from the industry, approximately one percent of drilling waste
generated during 1993 failed the current limitations which include the 30,000 toxicity limitation.5 Thus,
discharges resulting from Option 1 were estimated by calculating the total volume of drilling wastes
generated, and assuming one percent of that volume is not discharged while the remaining 99 percent is
discharged.

       For Option 2, statistical analysis of toxicity data from Cook Inlet drilling fluids showed that
"approximately 83 percent of the volume of known drilling fluid discharges to Cook Inlet are associated
with toxicity measurements equal to 1,000,000 ppm" .4 This result indicates that 17 percent of the drilling
fluids tested for discharge would fail a 1 million ppm  toxicity limitation and thus would either be sent
onshore for disposal, or ground and injected.

4.8   GRINDING  AND  INJECTION
       To meet the zero discharge  requirement of Option 3, those Cook Inlet operators for whom
landfilling of wastes is not economical might elect to grind and inject their drilling waste.  Disposal of
drilling wastes by injection requires:  (1) installation of processing equipment to grind the solids into a
slurry liquid with fine  particles; (2)  installation of injection equipment for delivery  of the processed
wastes into a subsurface formation; and (3) installation of injection wells to allow injection into suitable
subsurface formations.

       Because of limited space available on production or drilling platforms, EPA assumed that all
platforms  in  question  require retrofitting for  installation of processing and  injection equipment.
According to  industry, operators with multiple platforms do not need to purchase or lease  injection
equipment for each platform since such equipment could be shared between platforms.12

       Processing and injection equipment for use on platforms can be constructed in package units in
such a way that the entire unit could be transported and placed on a platform when needed, provided that
adequate space is available on that platform.

       Operators in Cook Inlet have the  option of either purchasing or leasing  the processing and
injection equipment.  EPA evaluated both the costs of leasing and purchasing of these equipment for the
purpose of compliance cost calculations. According to the industry sources, the unit cost of purchasing
a processing and injection equipment is approximately $1,000,000 and the unit rental cost of the same
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equipment is approximately $1,400 per day.3  The total equipment purchase and rental costs for each
operator were calculated and presented in Worksheets 4 and 4T hi Appendix X-l.  The calculated total
purchasing costs of grinding and injection equipment were greater than total rental costs for all operators
included in this  compliance cost calculations.   However, EPA conservatively assumed the higher
purchasing costs for all operators except Operator A,  for which the lower rental costs were used.  The
lower rental cost was used for Operator A since this operator currently grinds and injects its spent drilling
waste using rented grinding and injection equipment.3

        Injection of processed drilling waste also requires access to a suitable subsurface formation.  Such
access can be facilitated through installation of injection wells (i.e., dedicated  injection wells) or by
leaving the annulus of the wells being drilled open to allow annular injection. According to industry, a
suitable formation in Cook Inlet can be found at approximately 4,000 feet.3  Thus, EPA assumed that
dedicated  injection wells drilled to that depth would be adequate for injection of drilling waste.

        Injection of drilling waste through the annulus  of wells being drilled can substantially reduce the
costs  of injection  by eliminating the need  to  install  dedicated  injection wells.    However,  EPA
conservatively assessed the costs of grinding and  injection through the use of dedicated injection wells.
The total assessed  costs of grinding and  injection  of generated drilling waste  were $2,405,573,
$45,834,740, and $4,486,346 for Operators A, B, and C, respectively (see Worksheet 4 in Appendix X-
1).  However, the use of this disposal method  was found to be economical only for Operators A and C
(see Worksheet 5 in Appendix X-l). These costs are discussed in detail hi Section 5.3.

        The cost analysis, described later in Section 5.0 (Table X-6) resulted in overall for costs for
grinding and injection for all operators hi Cook Inlet of $458 per barrel for Option 2 and $95 per barrel
for Option 3.

4.9    TRANSPORTATION AND ONSHORE DISPOSAL COSTS OF DRILLING WASTES
        In addition to grinding and injection, EPA has also investigated the feasibility of onshore disposal
of generated drilling waste.  On-land disposal sites in Alaska are available only to Operator B or two out
of the four operators in Cook Inlet (see also Table X-2). Using projected drilling schedules provided by
industry, EPA estimated that these two operators would generate approximately 76 percent of the drilling
wastes produced by the Cook Inlet Operators over the next 7 years (see Worksheet 2 hi Appendix X-l).
These two operators jointly operate an oil and gas landfill disposal site on the west side of the Inlet.  EPA
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has determined that there is sufficient on-land disposal capacity to accept all of the drilling fluids and
cuttings generated by these operators at this disposal facility.3 EPA investigated the logistical difficulties
of storing and transporting drilling wastes in the Cook Inlet, due to the extensive tidal fluctuations, strong
currents,, and ice formation during whiter months.   However, while these climatological and tidal
situations may cause complications, EPA determined that they do not pose insurmountable technical
barriers.   EPA  has  taken  into  consideration  supplementary costs incurred by additional  winter
transportation and storage of drilling wastes in its cost evaluation of this option.

       Based on information provided by the industry3, EPA determined that Operator B would use
supply boats to transport generated drilling fluid and drill cuttings to a transfer station and temporary
storage facility on the east side of Cook Inlet for transfer into barges during the summer months,  or
temporary storage during winter months when barge traffic is not possible due to sea ice conditions.  For
example, the upper Cook Inlet would be covered by solid ice in winter if it were not for large tidal ranges
(frequently in excess of 30 feet). Because these large tidal ranges produce very strong currents, moving
broken ice is a common occurrence in Cook Inlet.13  Ice typically covers upper Cook Inlet for about four
months during the year and portions of the lower Cook Inlet for about three months during the year.13
Furthermore, barges available  in Cook Inlet are  not constructed  to operate in sea ice conditions.
Therefore, during ice conditions, only V-hulled vessels can be used to transport drilling wastes. Because
of tidal fluctuations sometimes in excess of 30 feet in summer and ice conditions in winter, V-hulled
supply vessels rather than barges are used for transporting supplies and wastes to and from platforms.
Therefore, supply boats are used by this operator during the summer and whiter months to transport the
drilling waste to  the transfer station on  the east  side of the Cook Inlet where the waste materials are
transferred onto barges for transportation to the west side landfill facility. Barges are used to transport
wastes to the west side of Cook Inlet because during low tide the water depth prohibits access by V-hulled
vessels.14

       EPA determined that since no docking  facility is available on  the  west  side of the inlet, the
offloading of barges is accomplished by building earthen ramps onto the beach to provide access to the
barge. Barges are then maneuvered to the earthen ramps during the high tide.  When the tide recedes,
the barges are beached near the  ramps and unloading resumes.

       An onshore disposal cost of $39 per barrel was calculated for Operator B. This unit cost takes
into account the costs of all transportation, purchasing waste containers, temporary storage, and landfill
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gate fees. Detailed calculations of the $39 per barrel disposal cost are presented in Appendix X-2. This

unit cost was calculated based on the following assumptions:
        8-barrel fluid/cuttings boxes (4 feet x 4 feet x 4 feet) are used for transporting the drilling waste
        with a purchase cost of $125 per box.3'14

        Supply boats are used to transport the drilling waste to a temporary onshore storage facility on
        the east side of the inlet at the rate of $4,000 per day per boat including loading and unloading
        costs.15

        Each boat will have 130 feet by  28 feet deck space or a capacity of 227 of 8-barrel boxes
        arranged on deck in one layer.14'15

        Transportation for a supply boat load of drilling waste to the temporary storage area will include
        1 day boat trip from platform to onshore docking area including loading boxes on deck and 1 day
        unloading boxes  and transportation to temporary storage area.14

        Trucks are used  to transport fluid/cuttings to the temporary onshore storage area at the rate of
        $300 per load  where each load could include 12 boxes.3

        Barges are used for transportation of drilling waste from the east Cook Inlet docking area to the
        existing landfill facility on the west side of the inlet at the rate of $6,000 per day per barge, with
        the capacity of 340 boxes.3'14'15'16

        Transportation from temporary storage to west side Cook Inlet landfill will include 1 day from
        storage area to docking facility and loading onto barges.14

        Trucks are used to transport the drilling waste from barges to the landfill area.3

        Transportation of one barge load of waste from east side docking facility to west side landfill will
        include  1 day  barge  trip to  west side unloading shore area  and one day unloading boxes and
        transportation to  the landfill.14

        Onshore disposal cost (gate fee) is  $14 per barrel.26

        Storage at the temporary storage facility costs $663,418 (at a rate of $0.10 per square foot per month
        for a total of 42 months and $157,957 per square foot of storage space) (see Appendix X-2).
        No on-land oil and gas waste disposal facilities are available hi Alaska to the other Cook Inlet
operators.  EPA investigated the possibility of disposing of drilling wastes at another on-land oil and gas

waste disposal site available to Cook Inlet operators located in Idaho.  This disposal site was identified

in responses to the 1993 Oil and Gas Questionnaires.9  Depending on the volume of wastes, it may be
more economical to dispose of smaller volumes of wastes in the Idaho landfill rather than install injection

wells.  To be conservative, EPA chose the more expensive grinding and injection for the disposal of the
                                              X-17

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drill wastes to comply with a zero discharge all option (Option 3), and determined this to be economically
achievable for these two operators. However, disposal of the lesser volumes of drilling wastes, those hot
meeting the toxicity at all limitations, under Option 2, would be shipped to the Idaho site.

       For operators other than Operator B, a unit disposal cost of $203 per barrel was assumed. This
value was  reported by the industry in the 1993  Questionnaires, and includes transportation of the
generated waste to the state of Idaho for disposal.9

5.0   COMPLIANCE COSTS AND POLLUTANT REMOVALS
       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 or grinding and
              injection.
       •      Reduction of pollutants discharged to surface waters.

Table X-5 presents a summary of the drilling waste compliance costs and pollutant removals for Options
2 and 3.

       Worksheets 1 through 5 and  IT through 5T, located in Appendix X-l, include the lists of all
assumptions made and sources of all data and information used in the compliance cost calculations. The
remainder of this section discusses the calculation of costs and pollutant loadings for each regulatory
option considered.

       The BAT incremental compliance  costs and pollutant removals were determined based on a
volume of muds  and cuttings equal to 99 percent of the total  volume of drilling waste generated during
the 7-year period following promulgation (see Section 2.0 for explanation of this time period).  The one
percent (1 %) reduction in total volume of drilling waste generation represents the volume of waste which
does not meet the discharge limitations under the current practices hi  Cook Inlet.5  The generated total
volume of drilling waste calculated for the 7-year period following promulgation is 558,430 barrels from
which 552,846 barrels is discharged under the current practices.

       The BAT incremental compliance costs and pollutant removals were evaluated for Options 2 and
3.  The BAT incremental compliance cost calculations for the zero  discharge and toxicity limitation
                                             X-18

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                                         TABLE X-5
            SUMMARY RESULTS OF DRILLING WASTE COMPLIANCE COSTS
                    AND POLLUTANT REMOVALS FOR COOK INLET
Optical
Zero discharge for all areas except Cook Inlet where discharge limitations require toxicity of no
less than 30,000 ppm (SPP), no discharge of free oil and diesel oil and no more than i mg/1
mercury and 3 mg/I cadmium in the stock barite.
Total Cost (Annual)
Conventional Pollutant Removals (pounds per year)
Priority Pollutant Removals (pounds per year)
Non-Conventional Pollutant Removals (pounds per year)
Total Pollutant Removals (pounds per year)
Percent Reduction From Current Loadings (%)
Option 3
Zero Discharge for all Areas
Total Cost (Annual)
Conventional Pollutant Removals (pounds per year)
Priority Pollutant Removals (pounds per year)
Non-Conventional Pollutant Removals (pounds per year)
Total Pollutant Removals (pounds per year)
Percent Reduction From Current Loadings (%)
$1,370,685
3,692,669
642
175,584
3,868,896
17
'
$3,889,386
21,703,156
3,757
1,032,105
22,739,018
100
*      All costs and pollutants removals were calculated based on the drilling activity plans or schedules as provided
       by the industry which actually covered a 7-year period, from 1996 through 2002.
options are presented in Worksheets 1 through 5 and IT through 5T, respectively.  The BAT incremental
pollutant removals for these two options are presented hi Worksheets 10  and  11, respectively (see
Appendix X-2).   The following paragraphs describe  the methodologies  and  assumptions used in
calculating the compliance costs and pollutant removals for each option.

       Since all compliance cost estimates are based on the volume of drilling waste generated, the first
step in cost evaluation was to estimate the average volume of drilling fluids and cuttings generated from
an average drilling event. These averages were determined to be 14,354 barrels  and 2,194 barrels for
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new wells and completions, respectively.  Estimation of drilling waste volumes was discussed earlier in
Section 4.2.  Detailed calculations are presented in Worksheet 1  or IT, Appendix X-l.

        Worksheet 1 and Worksheet IT are identical and present the same information, but are duplicated
this  way because  all subsequent compliance cost  calculations for both options are linked to the  data
presented in this worksheet. Worksheet 1 incorporates the drilling information of seven recently drilled
wells in the Cook Inlet area.  These wells were the only wells recently drilled in Cook Inlet for which
complete drilling information was available. The drilling data and cost information were used to calculate
the average depth of wells drilled (11,765 feet), the average volume of drilling muds  and drill cuttings
generated from an average  drilling event,  average  cost  of  drilling a  4,000-foot injection  well
($1,197,173), and the average number of drilling days spent for each drilling event (57 days for a new
well and 20 days for a recompletion). Worksheet 1 lists the raw data for three drilling depth intervals
as reported by the industry.  The average depth of each interval and the average  volume of waste
generated from each interval were also calculated and presented in this worksheet. The depth and volume
of waste generation for an average well was then estimated from the averages calculated for each interval.

        Also included in this worksheet are drilling costs from which the cost of drilling a 4,000-foot
injection well was estimated.  An industry source stated that a depth of 4,000 feet for an injection well
is an average depth where a suitable formation can be found for injection of drilling wastes12 (see also
Section 4.8).

        Four types of drilling  waste disposal methods were considered for estimating the industry-wide
compliance costs of each option:

        Method 1.      Land disposal without the use of high efficiency solids separation units (closed-
                       loop system) to minimize the amount of drilling waste generated.
        Method 2.      Land disposal with closed-loop system to reduce the volume of drilling waste
                       generated.

        Method 3.      Subsurface injection of spent drilling waste through dedicated  injection wells.
        Method 4.      A combination of methods (1) through (4).

Worksheets 2 through 5 and 2T through 5T present the calculations and  assumptions used to develop
waste volumes and disposal costs for each of these four disposal methods.
                                              X-20

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       It is important to note that the total compliance costs reported in Appendix X-l are for drilling
projects expected over the seven years from 1996 through 2002, in which all industry projected drilling
schedules occur (these are not annual costs). Table X-6 lists the total compliance cost estimates calculated
for each disposal method.

       The following subsections provide detailed discussions of each of these disposal methods and their
respective worksheets.

5.1    LAND DISPOSAL WITHOUT CLOSED-LOOP SYSTEMS
       This disposal method assumes that there will be no high efficiency solids separation units or
closed-loop systems installed and the drilling waste generation rates will be similar to the wells recently
drilled in Cook Inlet.   This disposal method  involves possible temporary storage on the platform or
onshore and transportation from the platform or onshore temporary storage area to an onshore disposal
facility.  As discussed earlier hi Section 4.9,  EPA developed two unit onshore disposal costs for the
operators  in Cook Inlet. A unit landfill disposal cost of $39 per barrel was calculated for Operator B
which has access to an Alaska-based landfill, and a unit cost of $203 per barrel for the other operators
which would use an Idaho-based disposal facility,  if landfill was the chosen disposal method. These unit
disposal costs are the same for Options 2 and 3 (see Worksheet 2 and 2T).

       The industry-wide compliance costs were estimated  for both  Options 2 and 3 based on the
volumes of drilling wastes generated and the unit disposal costs indicated above. The volumes of drilling
waste were estimated for each option based on the requirements of that option, average volume  of waste
generated from an average drilling event, and the projected drilling activity schedules.

       Worksheets 2 and 2T present the estimated individual and industry-wide incremental compliance
costs of Options 3 and 2 by land disposal without closed-loop system, respectively.  The total industry-
wide compliance costs based on this disposal method was estimated to be $7,291,613 or $78 per barrel
of waste for Option 2 and $42,891,839  or $78 per barrel of waste for Option 3.  In the  analysis that
selected the most cost-effective disposal methods for each  operator, land disposal without closed-loop
systems was selected for all operators under Option 2, and  for Operator B under Option 3 (see Section
5.4). While closed-loop systems offer advantages in less make-up fluid requirements and less drilling
waste produced, the platform retrofit, equipment  and operating costs of these systems made them more
costly than non-closed-loop  systems for the Cook Inlet platforms.
                                              X-21

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                                           TABLE X-6
                       Industry-Wide Compliance Cost Estimates (1992 $)a
Disposal
Method
Worksheet No,
in Appendix X-I
Total Compliance
Cost*
Cost is $/bbl
; Waste Disposed
Annual Compliance
Cost'
, _,_ m f JZero-Bisc|iaarge Opfioa
Land Disposal
Without Closed-Loop
Land Disposal
With Closed-Loop
Dedicated Well
Injection
Combined
Disposal5
2
3
4
5
$42,891,839
$40,158,169
$52,726,659
$23,380,320
$78
$105
$95
$42
NC"
NC1
NC"
$3,889,386
100jQ004,OOa,0aO ppra SPP Tosacitj; Option
Land Disposal
Without Closed-Loop
Land Disposal
With Closed-Loop
Dedicated Well
Injection
Combined
Disposal'
2T
3T
4T
5T
$6,991,463
$15,594,013
$43,008,286
$6,991,463
$74
$240
$458
$74
NCd
NC"
NC"
$1,370,685
a Source:  Appendix X-l
b Total costs are for all projected drilling from 1996 through 2002
c Source:  ERG, November 11, 1994"
d Not calculated
e Assumes landfill without closed-loop system for Operator B and dedicated well injection for Operators A and C
f Assumes landfill without closed-loop system for all operators
5.2    LAND DISPOSAL WITH CLOSED-LOOP SYSTEMS
        Land disposal with the closed-loop systems method assumes installation of high efficiency solids
separation units to minimize the volume of drill  waste generated.  The components of a closed-loop
system considered by EPA include high efficiency shale shakers, mud cleaners, chemically enhanced
centrifugation (CEC), waste storage tanks, and transfer equipment.  Installation of closed-loop systems
reduces the overall landfill and transportation costs  but will incur additional costs  of retrofitting the
platform, purchasing or leasing of high efficiency  separation equipment,  and operating the equipment.
                                              X-22

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        Installation of closed-loop systems will enable the operator to reuse the same mud for a longer
period of time and therefore reduce the need to introduce fresh mud into the system.  Data from the 1993
Questionnaires indicate that in Cook Inlet, high efficiency solids separation units on average reduce the
volume of spent drilling waste by 69 percent.18 However, a platform may not have adequate deck space
for installation of additional solids separation systems and may require retrofitting. The Agency estimated
an average retrofitting cost of $270,000 and assumed that all platforms need retrofitting. This retrofitting
cost was estimated based on the need for 450 square feet of additional deck space at the rate of $600 per
square foot.12'19

        Based on information obtained from Gulf of Mexico industry sources, EPA estimated an average
cost of $1,900 per day for leasing high efficiency solids separation systems.19 The estimated $1,900 per
day costs include all maintenance costs.  However, the Agency added an additional cost of $1,000 per
day for any additional operating costs that may be needed hi Cook Inlet.  The $1,000 per day operating
cost was  reported by  Cook Inlet industry  sources  for operation of waste processing and injecting
equipment.20  Since a closed-loop system is comparable to a processing and injecting system in terms of
labor requirements, the Agency assumed the unit operating cost determined for operation of injection
systems as the unit operating cost for operation  of closed-loop systems.  The total equipment  and
operating costs of a closed-loop system were calculated from the total number of drilling events for each
operator,  the average drilling period estimated for each drilling event, the unit equipment cost, and the
unit operating cost.  The same $39 per barrel and $203 per barrel land disposal unit costs specified for
Method 1 were also used for this disposal method.

        The industry-wide disposal cost based on this disposal method was estimated to be $15,594,013
or $240 per barrel of waste for Option 2 and $40,158,169 or $105 per barrel of waste for Option 3.
These costs are listed in Worksheet 3 and 3T, Appendix X-l.  Thus, use of closed-loop technology is not
less expensive for existing rigs associated with the  Cook Inlet platforms because of retrofit costs.

5.3    SUBSURFACE INJECTION THROUGH DEDICATED  WELLS
        Subsurface injection of drilling waste through a dedicated injection well involves the installation
of dedicated injection wells to a suitable underground formation, grinding of the mud and cuttings solids
into a slurry liquid with fine particles, and injection of processed waste into the subsurface formation.
                                              X-23

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       The total industry-wide disposal cost for this method includes the costs of dedicated injection
wells, platform retrofitting, injection equipment, and injection equipment operation.  The unit cost of
installing a 4,000-foot injection well was estimated to be $1,197,173 per well in Worksheet 1.  For the
zero discharge option (Option 3), the number of dedicated wells was estimated for each operator based
on the assumption that one injection well is needed for every 4 new drillings21 and one for every  16
recompletions.  The assumption for one  injection well for every  16 recompletions was based on the
approximate ratio of 4:1 between the estimated volumes of drilling waste generated from a new well and
a recompletion which was shown hi the 1993 Questionnaire data.9 For Option 2 however, one injection
well was assumed for every 8 new drillings  and  one well for every 32 recompletions, since  only  17
percent of the total volume will be injected under this option.

       The cost of retrofitting platforms was assumed to be $750,000 per platform based on information
provided by the industry.3 The Agency assumes that all platforms would need retrofitting.  Based  on
information obtained from the industry, it was further assumed that operators with multiple platforms  do
not need to install injection equipment at each platform, because injection equipment could be shared as
long as space is available at each platform.3 Based on information provided by the industry, it was
assumed that 4 injection units would be adequate for Operator B which operates 12 platforms  in Cook
Inlet. For the other operators with only one platform, one injection unit was assumed for each platform.

       The costs of injection equipment were estimated for both purchasing and leasing of the equipment
based on $1,000,000 per system3  for purchasing or $1,400 per day for leasing.3 The Agency assumed
operators would purchase the injection equipment except where the additional purchasing cost versus the
lower leasing cost could not be justified. For example, for Operator A it was assumed that the injection
equipment would be leased at the total cost of $267,400 since purchasing the equipment at total cost of
$1,000,000 could not be justified.  However, the estimated total purchasing cost of $4,000,000 was
assumed for Operator B over the estimated $3,150,000 total leasing cost because leasing of processing
and injection equipment may not be justified for this operator if the salvage value of the purchased
equipment is considered.

       Additional costs of operating the injection equipment were also included in total costs for  all
operators.  Operating costs included labor, maintenance,  and chemicals used (see Section VII213). For
Operators A and C, an additional cost of $1,000 per day was included based on the information obtained
from the industry.3  For Operator B, a much greater unit operating cost of $9,260 per day was estimated
                                             X-24

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based on the total volume of drilling waste generated for this operator and a unit operating cost of $200
per cubic yard of waste,  as reported by the industry.23

       The total industry-wide costs  for Options 2 and 3 using injection through dedicated wells are
presented hi Worksheets 4T and 4, respectively.  The total injection costs for Option 2 were estimated
to be $43,008,286 or $458 per barrel of waste and for Option 3, $52,726,695 or $95 per barrel of waste.
The estimated unit  disposal cost for Option 2 is substantially greater than the unit cost estimated for
Option 3 since a relatively much lower volume of drilling waste will be injected for this option at almost
the same capital cost as Option 3.

5.4   COMBINED DISPOSAL METHOD
       This disposal method compares the estimated disposal costs of the landfill, and dedicated well
injection, disposal methods of each operator and selects the most cost-effective method for each operator.
The total industry-wide disposal costs  are then the sum of the least costly disposal method per operator,
per option.  The combined method cost estimations are presented in Worksheets 5T and 5 for Options
2 and 3,  respectively.

       The total industry-wide cost for Option 2 was estimated to be $6,991,463 or $74 per barrel. The
disposal methods assumed to generate this cost were landfill without closed-loop system for all operators.
Similarly, the total  industry-wide cost for Option 3 was estimated to be $23,380,320 or $42 per barrel
of waste. The disposal methods assumed to generate this estimated cost were landfill without closed-loop
system for Operator B and dedicated well injection for Operators A and C (see Table X-6).  Costs for
the two operators under Option 3 to dispose of their wastes in the Alaskan landfill average $39/barrel.
Costs for the other two operators (one operator has no future plans to drill) to dispose of their wastes by
grinding and injection average $53/bbl.  A weighted average for disposal of 76 percent of the drilling
wastes by Alaskan landfills and 24 percent by grinding and injection equates to $42/bbl.  On a per well
basis, this amounts to approximately $425,000 and $600,000 for each recompletion and new well drilled,
respectively.

       As discussed hi Section 4.9, it is estimated that Operator B would generate 422,780 bpy or 76
percent of all drilling wastes in Cook Inlet over the seven years following promulgation of this rule (see
Appendix X-l). Operators A and C are estimated to generate 44,803 bpy and 85,263 bpy, respectively,
or the remaining 24 percent.  Thus,  for the combined disposal method under Option 2,  in which 17
                                              X-25

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percent of the drilling waste generated must be disposed, Operator B would dispose of 13 percent (76%
x 17%) via landfill in Alaska while Operators A and C would collectively dispose of 4 percent (24% x
17%) via landfill in Idaho. Under the combined disposal method of Option 3, in which all wastes must
be disposed, 76 percent would be landfilled in Alaska and 24 percent would be injected.

5.5    INCREMENTAL POLLUTANT REMOVALS
        The total industry-wide incremental pollutant removals were estimated for Options 2 and 3 based
on the total incremental volume and pollutant concentrations in the generated drilling muds and drill
cuttings.  Table X-7 presents the pollutant loadings resulting from the application of Options 2 and 3.
Loadings are the product  of the pollutant concentrations and the waste volume discharged following a
particular treatment. A shown hi Table X-7, the loading resulting from zero-discharge (Options 3) are
all 0 barrels per year because no  discharge would be allowed.  For the toxicity limitation (Options 2),
the loadings are based on 83 % of the current waste volume being discharged because this is the volume
of waste discharged as a result of the toxicity limitation. The pollutant reductions, listed in Table X-8,
are the difference between the loadings from current practice and the loadings resulting from each option.
Table X-8 presents a summary of the estimated pollutant removals for both options. Detailed calculations
for each option are presented in Appendix X-l.

        For both options,  the pollutant reductions were calculated by multiplying the concentrations of
pollutants in currently discharged wastes (Column  2 in both worksheets 10 and 11) by the volume of
wastes that would not be discharged according to each option. This volume reduction is  the difference
between the'currently discharged  volumes and the volumes discharged after application of each option
(Columns 3 and 5 in both Worksheets). Worksheet 10 provides  the pollutant reductions for Option 3,
the zero-discharge option.  The overall reductions for this option (Column 7 of the worksheet) are equal
to the total loadings calculated for current discharges (Column 4) because the application of zero
discharge essentially removes all pollutants currently being discharged.  Worksheet 11 provides the
pollutant reductions for Option 2, the  100,000 - 1,000,000 ppm SPP toxicity limitation option.  The
reductions listed hi Column 7 of this worksheet represent 83 percent of the current volumes being
discharged, because it has been determined that 17 percent could not meet a toxicity limitation of 100,000
-1,000,000 ppm.

        The values  hi Column 3 of Worksheets  10 and 11, "Amount of Total Drilling Waste Currently
Discharged," are presented on page 1 of the worksheets. The value by which heavy metal concentrations
                                             X-26

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                                       TABLE X-7

            DRILLING WASTE POLLUTANT LOADINGS IN COOK INLET
Pollutant
•.

Conventionals
TSS (Total)
Oil Content (Total)
Total Conventionals
Priority Pollutant Organics
Naphthalene
Fluorene
Phenanthrene
TotaTP.P, Organics
Priority Pollutant Metals
Cadmium
Mercury
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total P.P. Metals
Non-Conventionals
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes0
Alkylated naphthalenes0
Aikylated fluorenes0
Alkylated phenanthrenes
Total biphenyls0
Total dibenzothiophenes
Total Non»Conventionals
Total Loadings
Total Animal Loadings
Based on Current :
Practices3

21,699,381
3,775
21,703,156

0.2
3.6
0.5
4.2

7.9
0.7
40.7
50.7
5.0
1,713.8
133.6
250.6
96.4
7.9
7.0
8.6
1,431.7
3,752.5;

64,765.7
856,888.1
109,569.6'
104.3
624.8
133.1
2.2
7.7
0.9
8.6
1,431.7
1,032,1054,
22,739,017.7
Total Annual Loading
Based on Toxicity limit
*Qj>tJOtt2}b

18,010,486
0
18,010*485

0
0
0
0

6.5
0.6
33.8
42.1
4.1
1,422.4
710.8
208.0
80.0
6.5
4.1
7.1
1,188.3
3*114.5

53,755.6
711,217.1
90,942.7
86.5
518.6
0
0
0
0
0
0
*56,520.«
18,870,121,6
Total Annual Loading
Based on Zero Discharge
{Option 3)c

0
0
0

0
0
0
0

0
0
0
0
0
0
0
0
0
0
0
0
0
0

0
0
0
0
0
0
0
0
0
0
0
Q
0
Values are from Column 4 of both Worksheets 10 and 11, divided by 7 years (See Appendix X-3)
Values are from Column 6 of Worksheet 11, divided by 7 years (See Appendix X-3)
Values are from Column 6 of Worksheet 10, divided by 7 years (See Appendix X-3)
                                           X-27

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                                          TABLE X-8

              DRILLING WASTES POLLUTANT LOADINGS IN COOK INLET
Pollutant



,
Conventionals
TSS CTotal)
Oil Content (Total)
Total Conventionals ;
Priority Pollutant Organics
Naphthalene
Huorene
Phenanthrene
Total P.P. Organics
Priority Pollutant Metals
Cadmium
Mercury
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
Total PJ?» Metals
Non-Conventionals
Aluminum
Barium
Iron
Tin
Titanium
Alkylated benzenes0
Alkylated naphthalenes0
Alkylated fluorenes0
Alkylated phenanthrenes
Total biphenyls0
Total dibenzothiophenes
Total Non-Conventionals
Total Reductions - ;
Percent Reduction from Current
Practice
' Option 2
t MM ppm SPP Toxiclty
Total Cumulative
RednCfionS {pfisj'f


25,822,263.7
26,422.3
25,848,686.0

1.6
25.0
3.7
;. '30.3:

9.3
0.8
48.4
60.3
5.9
2,039.4
158.9
298.3
114.7
9.3
5.9
10.2
1,703.7
4,465.1

77,071.2
1,019,696.9
130,387.8
124.1
743.5
931.7
15.3
54.0
6.3
60.3
0.2
1,229,091,3
27,082,272,7;
17%

Annual Reductions
(lbs/yr)
,

3,688,894.8
3,774.6
3,692,669.4

0.2
3.6
0.5
4,3

1.3
0.1
6.9
8.6
0.8
291.3
22.7
42.6
16.4
1.3
0.8
1.5
243.4
637.9

11,010.2
145,671.0
18,626.8
17.7
106.2
133.1
2.2
7.7
0.9
8.6
0.0
175,584.5
33868,&>6a
17%

Option 3
Zero Discharge
Total Cumulative
Reductions {lbs)1>


151,895,668.6
26,422.3
15^922,090.9

1.6
25.0
3.7
30.3

55.5
5.0
284.9
354.9
35.0
11,996.4
934.7
1,754.5
674.8
55.0
35.0
60.0
10,022.0
36,267.2

453,360.2
5,998,217.1
766,987.0
729.8
4,373.7
931.7
15.3
54.0
6.3
60.3
0.2
7,224^735.6
159,173,124,0
100®

Annual
Reductions
(Ibs/yr)

21,699,381.2
3,774.6
2Jr703,155.8

0.2
3.6
0.5
4.3

7.9
0.7
40.7
50.7
5.0
1,713.8
133.5
250.6
96.4
7.9
5.0
8.6
1,431.7
3,752.5

64,765.7
856,888.2
109,569.6
104.3
624.8
133.1
2.2
7.7
0.9
8.6
0.0
1,032,105,1
2i,739i017»7
iBo%
.
* Source: Appendix X-l
b Total cumulative reductions cover the 7-year period from 1996 through 2002.
c These analyte groups contain both priority pollutants and non-conventional pollutants, but were not distinguished in the source
document.
                                              X-28

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 are multiplied (50,490,043 Ibs) is the dry weight of muds currently discharged. This value is used in
Column 3 because the metals concentrations are given on a dry weight basis, and because it is assumed
that metal contaminants are associated only with barite in the drilling fluid (see Section 4.6).  The value
by which organic and total oil concentrations are multiplied (447,805 bbls) is the volume of drilling muds
currently discharged.  The concentrations of these pollutants are given on a volumetric basis.

        Column 5 of Worksheets 10 and 11 presents the percentage of the amounts reported in Column
3  that will be discharged following application of each option.  Worksheet 10 shows 0% discharged
following the zero-discharge option, and Worksheet  11  shows 83%  discharged as  a result of the 17%
toxicity test failure rate (see Section 4.7).

        Page  1 of Worksheets 10 and 11 provides the calculations for the total suspended solids (TSS)
values in the  cuttings and the muds. The TSS value for the cuttings is equal to the total weight of dry
cuttings, calculated from the known volume  of cuttings discharged and the density. The TSS value for
the drilling muds, referred to as the "total dry weight of muds currently discharged," is the product of
the known volume of muds discharged, the percent of dry solids in the mud by volume, and the density.
The TSS value for drilling muds is also the value of the dry-basis amount of waste discharged, listed hi
Column 3 of the worksheets.

6.0    BCT Compliance  Costs and Pollutant Removals Development
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 PR 24974).  These rules set forth a
procedure which includes two tests to determine the reasonableness of costs incurred to  comply with
candidate  BCT technology options.  If all candidate options fail any of the tests, or if  no candidate
technologies more stringent than BPT are identified, then BCT effluent limitations guidelines must be set
at a level equal to BPT effluent limitations.  The cost reasonableness methodology compares the cost of
conventional pollutant removal under the BCT options considered to be the cost of conventional pollutant
removal at publicly owned treatment works (POTWs).

        BCT  limitations for conventional pollutants that are more stringent than BPT limitations are
appropriate in instances where the cost of such limitations meet the following criteria:
                                            X-29

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               The POTW Test:   The POTW test compares  the  cost per pound of conventional
               pollutants removed by industrial dischargers hi 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 $0.534 per pound ($0.25 per
               pound hi 1976 dollars indexed to 1992 dollars).

               The Industry Cost-Effectiveness Test: This test  computes the ratio of two incremental
               costs.  The ratio is also referred to as the industry cost test.  The numerator is the cost
               per  pound  of conventional pollutants removed in upgrading from BPT to the BCT
               candidate technology; the denominator is the cost per  pound of conventional pollutants
               removed by BPT relative to no treatment (i.e., this value compares raw wasteload to
               pollutant load after application of BPT).  The industry cost test is a measure of the
               candidate technology's  cost-effectiveness.  This ratio  is compared to an industry cost
               benchmark, which is based on POTW cost and pollutant removal data. The benchmark
               is a ratio of two incremental costs:   the cost per pound to upgrade a POTW from
               secondary treatment to advanced secondary treatment  divided by the cost per pound to
               initially achieve secondary treatment from raw wasteload.  The result of the industry cost
               test is compared to the industry Tier I benchmark of 1.29. If the industry cost test result
               for a considered BCT technology is less than the  benchmark, the candidate technology
               passes the industry cost-effectiveness test.  In calculating the industry cost test, any BCT
               cost per pound less than $0.01 is considered to be the equivalent of de minimis or zero
               costs.  In such an instance, the numerator of the industry cost test and therefore the entire
               ratio are taken to be zero and the result passes the industry cost test.
       These two criteria represent the two-part BCT cost reasonableness test.  Each of the regulatory

options was analyzed according to this cost test to determine if BCT limitations are appropriate.


6.2   BPT BASELINE

       In order to estimate the incremental costs and the incremental conventional pollutant removals

for the BCT options, BPT baseline compliance costs and pollutant removals for drilling fluids and drill

cuttings determined. BPT limitations for drilling fluids and drill cuttings prohibit the discharge of drilling

fluids and the associated cuttings with free oil, as determined by the visual sheen test.  The estimated
costs incurred by industry to comply with the BPT limitations consist of: (1) transportation and onshore
disposal costs for all oil-based drilling fluids and the associated cuttings and (2)  a product substitution cost

to replace diesel oil with mineral oil to comply with the BPT no discharge of free oil limitation.


       Prior to 1988, drilling wastes generated hi Cook Inlet that were not allowed to be discharged were

transported to shore for disposal at the Sterling Special Waste Site (SSWS)  on the Kenai Peninsula.13

Because this landfill was permitted to accept drilling wastes and was available to all operators hi Cook
                                             X-30

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Inlet, the BPT cost for disposal is based on all drilling wastes such as oil-based drilling fluids and the
associated cuttings being transported to shore for disposal at SSWS at the 1988-time period cost of $26.99
per bbl for cuttings and $29.29 per bbl for drilling fluids.2

       Before BPT effluent limitations were promulgated, the general industry practice was to use diesel
oil for lubricity and as a pill to free stuck pipe. After promulgation of the BPT limitation of no discharge
of "free oil" and because diesel oil was shown to form a visible sheen even in small concentrations, the
industry replaced diesel oil with mineral oil as a lubricant and hi many instances, as a pill hi order to be
able to discharge the drilling fluids and cuttings.2 Therefore, a diesel-to-mineral oil substitution cost is
also attributed to compliance with BPT discharge limitations.

       Before the 1985 proposed BAT limitations, water-based drilling fluids could be formulated with
a higher mineral oil content for lubricity and still pass the "no free oil" limitation.  Therefore, for the
purpose of estimating BPT compliance costs,  it is assumed that a typical water-based drilling fluid used
prior to 1985 contained 3 % mineral oil by volume  for lubricity.2  The current mineral oil content, by
comparison is generally hi the area of 0.02% .9

       The average well depth was calculated from the 1993  Coastal Oil and Gas Questionnaire to be
11,765 feet.8 Before  1985, oil-based muds were used beyond 10,000 ft for all new wells.2  Under the
BPT "no free oil" limitation, the volume of drilling fluids and the associated cuttings beyond 10,000 ft
could not be discharged, and were hauled to shore for disposal.

       The compliance costs and conventional pollutant removals for the BPT baseline for coastal wells
were estimated using the model well characteristics developed for drilling wastes hi the Alaska region for
the offshore regulation.2 The volume of drilling fluids and cuttings requiring disposal under the BPT
limitation were calculated for an average well depth of 11,765 feet. Only the volume of drilling fluids
and cuttings generated beyond 10,000 feet were assumed to require onshore disposal due to the BPT
limitations. The drilling fluids and cuttings volume per well for Cook Inlet were obtained from the 1993
Coastal Oil and Gas Questionnaire (Appendix X-l).  Table X-9 presents the calculations for the volume
of drilling fluids and drill cuttings generated for the coastal model well. As shown in Table X-9, a total
of 2,076 bbl/well of drilling fluids and cuttings would require onshore disposal under the BPT limitations.
Of the 2,076 bbl of drilling wastes generated beyond  10,000 feet, the drilling fluid represents 81 % (1,682
bbl) and the cuttings represent 19% (394 bbl) (Appendix X-l).
                                              X-31

-------
                                         TABLE X-9
                     VOLUME OF DRILLING FLUIDS AND CUTTINGS
                    GENERATED FROM THE COASTAL MODEL WELL
Depth
Interval
Average
Depth
(feet)
Muds&
Cuttings
Volume
(bbl/wefl)
Muds
VolumeCa)
(bbl/well)
Cuttings
Volume(a) •
(bbl/well)
Drilling
Rate
(bbl/ft)
Coastal Well Waste Generation Data (a)
0-2,553
2,553-9,901
9,901-11,765
Total:
2,553
7,348
1,865
3,497
8,703
2,194
14,394
2,833
7,049
1,777
11,659
664
1,654
417
2;735
1.370
1.184
1.176
Recalculated Coastal Well Data (b)
0-.2553
2,553-8,000
8,000-9,901
9,901-10,000
10,000-11,765
Total:
2,553
5,447
1,901
99
1,765
3,497
6,449
2,251
116
2,076
14,389
—
—
—
Recalculated Coastal WeD Waste Generation Volumes (c) ' , ,
0-8,000
8,000-10,000
10,000-11,765
Total:
8,000
2,000
1,765
9,946
2,367
2,076
14,389
8,057
1,917
1,682
11,656
1,889
450
394
2,734
—
(a) Source: Appendix X-l
(b) Coastal well data subdivided to fit the offshore model well depth intervals.
(c) Calculated using offshore model well depth intervals and coastal well volumes per interval.

       Due to the solids control system, a portion of the drilling fluid is disposed with the cuttings, and
a portion of cuttings is disposed with the drilling fluid.  In order to estimate these fractions, it was
assumed that the typical solids control system used in drilling operations in Cook Inlet is an intermediate
efficiency system, i.e., 62%  solids removal efficiency (55 FR 23348).  It was also assumed that drilling
fluid lost to cuttings represents 2.13 times the cuttings volume removed from the mud system by the
solids separation equipment (55 FR 23348).  Table X-10 summarizes the volumes of drilling fluids and
cuttings calculated for each depth interval based on the solids control system separation efficiency. As
                                             X-32

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                                        TABLE X-10
                     VOLUME OF DRILLING FLUIDS AND CUTTINGS
                  GENERATED FROM THE SOLIDS CONTROL SYSTEM
                            OF THE COASTAL MODEL WELL3
Volume of Drilling FMds {frbl/well)
Bepffif
Interval"
0-8,000
8,000-10,000
10,000-11,765
Total:

Generated
8,057
1,917
1,682
%
11,656

PHI
— *
100
—
100

Total
8,057
2,017
1,682
11,756
Mod i
Lost to
Cuttings
2,494
594
520
3,680
Mud
System
5,563
1,423
1,162
8,148
Cutfings
Lost to -
Mad
718
171
150
1,039
Total
to
JMscard
6,281"
1,594"
1,312°
9,187
Volume of Cuttings (bbl/weU)

Depth
Interval
0-8,000
8,000-10,000
10,000-11,765
Total:

Generated
1,889
450
394
2,733

Removed
1,171
279
244
1,694
Cuttings
Lost to
Mud
718
171
150
1,039
Mod
Lost to
Cnttisgs
2,494
594
520
3,608
Total
To
Discard:
3,665a
873a
764"
5,302





a  Assumed solids removal efficiency: 62% (55 FR 23348)
b  To surface discharge or recycle
c  To disposal
shown in Table X-10, a total of 2,076 bbl/well of drilling fluids and cuttings (generated at greater than
10,000 feet) would require onshore disposal under the BPT limitations.  Of the 2,076 bbl of drilling
wastes generated beyond 10,000 feet, 1,312 bbls of drilling fluid and 764 bbls of cuttings are generated
following the solids control system.

       To develop the BPT compliance cost and conventional pollutant removals for Cook Inlet, several
assumptions were also made about the drilling operations. The assumptions used to characterize a typical
drilling scenario before 1985 in Cook Inlet are presented hi Table X-ll, including diesel and mineral oil
usage, disposal and product substitution costs, and typical drilling mud composition.

       Table X-ll  also includes the calculations for the disposal costs and  conventional  pollutant
removals.  The total disposal costs associated with compliance with the BPT limitations for the coastal
                                            X-33

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model well include the diesel-to-mineral oil substitution cost plus the disposal cost for oil-based drilling
fluid  and associated cuttings.  The substitution cost was calculated for the  volume of drilling fluid
generated (9,977 bbl) plus the volume of pill added (100 bbl) in the first 10,000 feet of drilling.
       The following calculations present the results of the unit BPT costs for drilling fluids, cuttings,
and for the drilling wastes combined.  The values used hi these calculations were extracted from the
information presented in Table X-ll.
            BPT Cost for Drilling Fluids =
                                                  40,275  $/well
                                            (264,911  + 207,584) Ib/well
    = 0.085 $//&
                BPT Cost for Cuttings =
                                                22,355 $/well
                                         (297,880 + 92,895) Ib/well
= 0.057 $flb
                                            -                           •
6.3    BCT OPTIONS
        The two BCT candidate options for drilling fluids and cuttings hi Cook Inlet are:

        •      Option 2 (previously described): Zero discharge except for Cook Inlet where discharges
               of drilling fluids and cuttings are allowed if they meet limitations on the cadmium and
               mercury  concentrations hi stock barite, no discharge of diesel oil  and of free oil as
               determined by the static sheen test, and a toxicity limitation set between 100,000 and
               1,000,000 ppm(SPP).

        •      Option 3: Zero Discharge: All discharges of drilling fluids and cuttings under this option
               would be prohibited.

        Option 1 which is zero discharge  everywhere except for Cook Inlet which would be subject to
the same as offshore limitations, including a toxicity limitation of 30,000 ppm (SPP) is not considered
a BCT option.  No additional removal of conventional pollutants due to the toxicity limitation of 30,000
ppm (SPP) over that removed by BPT (free oil discharge prohibition) could be determined.  However,
a  more  stringent toxicity limitation,  imposed under Option 2, would  indirectly  remove  additional
conventional pollutants, whether the final rule sets the toxicity limitation at 100,000 ppm (SPP) or at
1,000,000 ppm (SPP), or somewhere hi between.  The industry has indicated that under the current
                                              X-34

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                                                 TABLE X-ll
                                     BPT DRILLING ASSUMPTIONS
                                          I) Typical BFT Drilling Scenario
  a)  12% of all wells used water-based drilling fluids with mineral oil lubricity for the first 10,000 feet.2
  b)  22% of all wells experienced stuck pipe between 8,000 feet and 10,000 feet of well depth.2
  c)  All wells used oil-based drilling fluids beyond 10,000 feet.2
  d)  All rigs used intermediate efficiency solids control systems.
                                            2) Diesel/Mineral Oil Usage
  a)  Diesel oil was used pre-BPT for both lubricity and as a pill.2
  b)  Mineral/diesel oil for lubricity equals 3% of drilling fluid volume.2
  c)  One mineral/diesel oil pill equals 100 bbl.2
  d)  Oil-based drilling fluids contain 60% by volume mineral oil.2
  e)  Cost to substitute mineral oil for diesel oil equals $2.00/gal ($84.00/bbl).2
                                            3} Typical Mod Composition
  a)  Drilling fluids contain a total of 113 lb/bbl total suspended solids (TSS) (Appendix X-l).
  b)  Density of cuttings removed by solids control system is 980 lb/bbl  (Appendix X-l).
  c)  Cuttings retained in the mud system are low gravity solids with a density of 910.7 lb/bbl.24
  d)  Specific gravity of mineral oil is 0.85.2 This converts to a density  of 297.74 Ibs/bbl (0.85 x 350 Ibs water/bbl).
                                                 4} Disposal Cast
  a)  Cuttings disposal cost is $29.26/bbl.2
  b)  Drilling fluids disposal cost is $26.99/bbl.2
  c)  Mineral oil substitution cost (BPT):
                [(9,977 bbl mud/well) x (0.03x0.12) + (100 bbl pill/well) x (0.22)] x $84/bbl = $4,864/well
  d)  Total cuttings disposal cost (BPT):
                                 (764 bbl cuttings/well) x (29.26 $/bbl) = $22,395/well
  e)  Total drilling fluids disposal cost (BPT):
                          [(1,312 bbl mud/well) x (26.99 $/bbl)] -I- $4,864/well = $40,275/well
                                        5) Conventional Poflutant Removals3
  a)  TSS in drilling fluid disposed (BPT):
              (113 lb/bbl) x (1,162 bbl mud/well) + (150 bbl cuttings/well) x (910.7 lb/bbl) = 267,911 Ib/well
  b)  Oil in drilling fluid disposed (BPT):
                            (1,162 bbl mud/well) x (0.6) x (297.74 lb/bbl) = 207,584 Ib/well
  c)  TSS in cuttings disposed (BPT):
                (244 bbl cuttings/well) x (980 lb/bbl) + (520 bbl mud/well) x (113 lb/bbl) = 297,880 Ib/well
  d)  Oil in cuttings disposed (BPT):
                              (520 bbl mud/well) x (0.6) x (297.74 lb/bbl) = 92,895 lb/bbl
* Results of calculations are derived from spreadsheets that include automatic rounding.


practices (Option  1),  only  about 1 % of all  drilling  wastes  are not discharged.5  For the purpose of

calculating results  of the BCT cost  tests, a compliance rate of 83 percent was used, based on evaluating

the volume of drill wastes identified as being discharged in a summary database from operations in Cook
Inlet.18  Tables X-4.1 and X-4.2 in Appendix X-4 contain a description of the data excluded from the data

used in this evaluation.


         For each BCT candidate option, an analysis was performed to determine:
                                                      X-35

-------
        •       Cost incurred by the industry to comply.
        •       Volume of drilling fluids and cuttings not discharged.
        •       The amount of conventional pollutants not discharged.
        •       BCT cost reasonableness tests.

6.3.1    BCT Compliance Costs and Pollutant Removals
        BCT compliance costs and conventional pollutant removals were estimated for Options 2 and 3
using several assumptions, an average drilling fluid and cuttings volume generated per well, industry-
projected numbers of new and recompletion wells that will be drilled from 1996 through 2002, a model
drilling fluid composition, and a drilling waste disposal cost based on a combination of disposal methods
(landfill for those operators that have access to a landfill, and disposal into a dedicated injection well for
the remaining operators).  The disposal scenarios were established through the BAT cost analysis
presented in Section 5.1.

        To develop the BCT compliance cost and conventional pollutant removals for Cook Inlet, several
assumptions were made about the drilling operations. The assumptions  used to characterize  a typical
drilling scenario in Cook Inlet, disposal costs, and conventional pollutant removals hi drilling fluids and
cuttings are presented in Table X-12.  Because the mineral oil content in  drilling fluids may vary up to
2% by volume when a pill is used25, two versions of  a typical drilling fluid composition have been
developed. The BCT cost analysis presented in the following section is based on a typical drilling fluid
containing 0.02% by volume of mineral oil,  referred to  as Version 1.  Appendix X-5 presents the BCT
cost analysis based on a typical drilling fluid containing 2% by volume mineral oil, referred to as Version
2.

        The incremental costs and pollutant removals  as measured from BPT-level treatment are based
on the additional volume of drilling wastes above  10,000 ft that require disposal due to the BCT
limitations.  This volume was estimated as follows:

•       Volume of drilling wastes above 10,000 ft:
                 14,389 bbl/well - 2,076 bbl/well =  12,313 bbl/well (see Table X-7)
•       Incremental volume of drilling wastes requiring disposal under Option 2:
                           (12,313 bbl/well) x (0.17) = 2,093 bbl/well
                                             X-36

-------
                                                   TABLE X-12
                                      BCT DRILLING ASSUMPTIONS
                                              Typical BCT Drilling. Scenario
 a) All wells use water-based drilling fluids with mineral oil for lubricity.
 b) All rigs use intermediate 62% efficiency solids control systems (55 FR 23348).
 c) Average volume per well is 14,389 bbl/well (Appendix X-l)
                                                 2) M««3l Ofl Bsage
 a) Mineral oil for lubricity equals 0.02% of drilling fluid volume - Version I.2
 b) Residual mineral oil in the discharged mud when pill is added equals 29S25 - Version 2.
 c) Mineral oil substitution cost is $2.00/gal ($84.00/bbl).2	

                                             3} Typical Mad Composition

 a) Drilling fluids contain a total of 113 Ib/bbl total suspended solids (TSS) (Appendix X-l).
 b) Density of cuttings removed by solids control system is 980 Ib/bbl (Appendix X-l).
 c) Cuttings retained in the mud system are low gravity solids with a density of 910.7 Ib/bbl.24
 d) Specific gravity of mineral oil is 0.85.2  This converts to a density of 297.74 Ibs/bbl (0.85 x 350 Ibs water/bbl).
 e) Drilling fluids and cuttings volumes represent of the total drilling wastes generated 81% and 19%, respectively
 (Appendix X-l).

	4) Disposal Cost	

 a) Drilling wastes disposal cost for Option 2 is $76.00/bbl (Appendix X-l).
 b) Drilling wastes disposal cost for Option 3 is $42.00/bbl (Appendix X-l).
 c) Mineral oil substitution cost for Option 2 - Version 1, only:
                             (12,313 bbl/well) x (0.81) x (0.0002) x (84 $/bbl) = $168/well
 d) Total cuttings disposal cost (Option 2):
                                 (2,093 bbl/well) x (0.19) x (76.00 $/bbl) = $30,226/well
 e) Total drilling fluids disposal cost (Option 2):               .
                         (2,093 bbl/well) x (0.81) x (76.00 $/bbl) + $168/well = $129,026/well
 f) Total cuttings disposal cost (Option 3):
                                (12,313 bbUwell) x (0.19)  x  (42.00 $/bbl) = $98,258/well
 g) Total drilling fluids disposal cost (Option 3):
	(12,313 bbUwell) x (0.81) x (42.00 $/bbl) = $418,888/well	

                                         5) Conventional Pollutant Removals

 a) TSS in drilling fluid disposed (Option 2):
                                (113 Ib/bbl) x (2,093 bbl/well) x (0.81) = 191,592 Ib/well
 b) Oil in drilling fluid disposed (Option 2 - Version 1):
                           (2,093 bbl/well) x (0.81) x (0.0002) x (297.74 Ib/bbl)  = 101 Ib/well
 c) TSS in cuttings disposed (Option 2):
                                (2,093 bbl/well) x (0.19) x (980 Ib/bbl) = 389,756 Ib/well
 d) TSS in  drilling fluids disposed (Option 3):
                               (12,313  bbl/well) x (0.81) x (113 Ib/bbl) = 1,127,009  Ib/bbl
 e) Oil in drilling fluids disposed (Option 3 - Version 1):
                           (12,313 bbl/well)  x  (0.81) x (0.0002) x (297.74 Ib/bbl) = 594 Ib/well
 f) TSS in cuttings disposed (Option 3):
                              (12,313 bbl/well) x (0.19) x (980 Ib/bbl)  = 2,292,681 Ib/well
                                                        X-37

-------
6.4   BCT COST TEST CALCULATIONS
       The BCT incremental compliance costs and pollutant removals are a result of the disposal of
drilling wastes either to a privately owned landfill or injection through a dedicated injection well. Since
the cost reasonableness methodology is concerned with the cost of conventional pollutant removals under
BCT as it is applied incrementally to BPT, the effects of existing permit or BAT option limitations which
may be more stringent than BPT (such as diesel and metals limits for stock barite hi drilling fluids) are
not considered for the cost reasonableness tests. However, as described previously, some level of toxicity
is believed to have an effect on the amount of oil ha the  wastes, thus a toxicity limitation  is being
considered as one BCT option.

       The results of the BCT cost reasonableness tests for the candidate options for drilling fluids and
cuttings are presented hi Table X-13 for version 1 of this analysis. The results of version 2 BCT options
analysis are shown hi Appendix X-5.
                                             X-38

-------
                                 TABLE X-13

        BCT COST TEST RESULTS FOR DRILLING FLUIDS AND CUTTINGS -
                                COOK INLET
          (VERSION 1 - Total oil content in the drilling fluid is 0.02% by volume)
Regulatory
Option
Conv, Polt
Removal*
(Ib/weli)
Compliance
Cost*
($/wel!)
POTW
Cost
{$/&}
Pass
POTW
<<&S34)
BPT
Cost
c$/to)
ICR
Ratio
Pass
ICR
«,X.29)
Drilling Fluids
Option 2
Option 3
191,693
1,127,603
129,026
418,888
0.673
0.371
No
Yes
0.085
0.085
—
4.365
—
No
Drill Cuttings
Option 2
Option 3
389,756
2,292,681
30,226
98,258
0.078
0.043
Yes
Yes
0.057
0.057
1.368
0.754
No
Yes
Drilling Fluids and Cuttings
Option 2
Option 3
581,449
3,420,284
159,252
517,146
0.274
0.151
Yes
Yes
0.072
0.072
3.806
2.097
No
No
"Incremental to BPT.
                                    X-39

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7.0   REFERENCES

1.     Ray, James P., "Offshore Discharges of Drill Cuttings," Outer  Continental Shelf Frontier
       Technology, Proceedings of a Symposium, National Academy of Sciences, December 6,  1979.
       (Offshore Rulemaking Record Volume 18)

2.     U.S. EPA,  "Development Document for Effluent Limitations Guidelines  and New Source
       Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source
       Category (Final)," January 1993.

3.     Safavi, B., Memorandum to Allison Wiedeman regarding Cook Inlet operators' 308 questionnaire
       identification numbers and related confidential data, January 30, 1995. (Confidential Business
       Information)

4.     SAIC,  "Preliminary Statistical Analysis  of Permit Compliance Monitoring Records for the
       Toxicity of Drilling Fluids in Alaska (Draft Final Report)," December 9, 1994.

5.     Schmidt, R., Unocal, Correspondence to Manuela Erickson, SAIC, regarding drilling fluids not
       acceptable for discharge, July 11, 1994.

6.     SAIC, Worksheet entitled "Calculation of Average Mud Weight for Cook Inlet Drilling Mud,"
       April 13, 1994.

7.     SAIC, Worksheet entitled "Calculations for Average Density of Dry Solids in Cook Inlet Drilling
       Mud," June 6, 1994.

8.     SAIC,  Worksheet  entitled "Calculations for Average Density of Cuttings in Cook Inlet,"
       September 7, 1994.

9.     U.S. EPA, Responses to the  1993 "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160,
       July 1993.  (Confidential Business Information)

10.    SAIC, Worksheet entitled "Estimation of Organic Concentrations hi Cook Inlet Drilling Mud,"
       June 7, 1994.

11.    SAIC,   "Descriptive Statistics  and  Distributional  Analysis  of  Cadmium and  Mercury
       Concentrations  hi  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)

12.    Schmidt, R., Unocal Corp., Correspondence with Manuela Erickson, SAIC, regarding drill
       cuttings and fluid discharge information, April 21, 1994.

13.    SAIC,  "Oil and Gas Exploration and Production Wastes Handling Methods in Coastal Alaska,"
       January 6,  1995.

14.    Wiedeman, A., U.S. EPA, "Trip Report to Alaska -  Cook Inlet and North Slope Oil and Gas
       Facilities, August 25 - 29, 1993," August 31, 1994.
                                            X-40

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15.    Safavi, B., SAIC, Contact Report with Ocean Marine Services, May 24, 1994.

16.    Erickson, M., SAIC, Contact Report with Arctic Tug and Barge Company, March 16, 1994.

17.    ERG, "Cost-Effectiveness Analysis of Proposed Effluent Limitations Guidelines and Standards
       for the Coastal Oil and Gas Industry,"  November 11,  1994.

18.    SAIC, Worksheet entitled  "Solid Separation  Equipment Removal  Efficiency Estimation,"
       October 10, 1994.

19.    SAIC, Worksheet entitled "Solid Separation Equipment Cost Estimation," May 3, 1994.

20.    Litzen, L., Shell Western E&P, Inc., Communication with Manuela Erickson, SAIC, regarding
       production platforms in Cook Inlet," April 18, 1994.

21.    Schmidt, R., Unocal Corp., Communication with Manuela Erickson, SAIC, regarding injection
       of drilling waste hi Cook Inlet, April 7, 1994.

22.    Schmidt, R., Unocal Corp., Correspondence with Manuela Erickson, SAIC, regarding economic
       impacts of drill  cuttings and fluid discharges, April 18, 1994.

23.    SAIC, Worksheet entitled "Grinding and Processing Equipment Operating Cost Estimation,"
       May 31, 1994.

24.    Moore, P., Drilling Practices Manual, 2nd edition, Pennwell Publishing Co., Tulsa, OK, 1986.

25.    NPDES Discharge Permit No.  AK-005205-1, ARCO  Cook  Inlet Oil  & Gas Exploration,
       May 24, 1993.

26.    SAIC, "Offshore Oil and Gas Industry: Analysis of the Cost and Pollutant Removal Estimates
       for BCT, BAT and NSPS Options for the Drill Cuttings and Drilling Fluid Streams," January 13,
       1993.  (Offshore Rulemaking Record Volume 173)
                                           X-41

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                                      SECTION XI
 COMPLIANCE COST AND  POLLUTANT LOADING  DETERMINATION -
                                 PRODUCED WATER
1.0   INTRODUCTION
       This section presents the estimated compliance costs and reductions in pollutants discharged as
a result of the proposed set of treatment options developed for produced water in the coastal regions of
the Gulf of Mexico and Cook Inlet, Alaska.  The technology costs  represent additional investment
required beyond those costs associated with BPT technologies.  The  compliance costs and pollutant
reductions developed for the proposed options are presented in Sections 5.1 and 5.2.

       Treatment technology costs were estimated on a facility-specific basis using actual facility profile
information.  For operators  in the Gulf of Mexico, regulatory compliance costs  and pollutant removals
were estimated for each production facility that will continue to discharge produced water after July 1996,
based on mathematical cost model equations. For operators in Cook Inlet, compliance costs and pollutant
removals were estimated for each production facility that currently discharges produced water, based on
the current level of treatment at each facility.

2.0   OPTIONS CONSIDERED AND SUMMARY COSTS
       Five regulatory options  were evaluated for produced  water in  terms  of costs  and pollutant
removals.  These five options are based  on either  injection, unproved operating performance of gas
flotation, or BPT technologies. The limitations associated with the discharge technologies are for oil and
grease.  The five options are as listed below:

       Option 1 - (BPT AID:  EPA has included as an option setting  effluent limitations equal to the
       existing BPT requirements.  Oil and grease would be limited in the effluent at 48 mg/1 monthly
       average, and 72 mg/1 daily maximum.
       Option 2  - (Flotation All):  All discharges of produced water would be required to meet
       limitations on oil and grease content of 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 Discharge:  Cook Inlet BPT): With the exception of facilities in Cook Inlet,
       Alaska, all coastal oil and gas facilities would be prohibited from discharging produced water.
       Coastal facilities hi  Cook Inlet would  be required to comply  with the existing BPT effluent
                                            XI-1

-------
       limitations for oil and grease specified under Option 1.
       Option 4 - (Zero Discharge: Cook Inlet Flotation):  With the exception of facilities in Cook Inlet,
       Alaska, all coastal oil and gas facilities would be prohibited from discharging produced water.
       Coastal facilities in Cook Inlet would be required to comply with the oil and grease limitations
       of 29  mg/1 monthly average  and 42 mg/1 daily  maximum  based on improved operating
       performance of gas flotation.
       Option 5 - (Zero Discharge All):  This option would prohibit all discharges of produced water
       based on reinjection of the produced water.

       Table XI-1 summarizes the BAT and NSPS incremental compliance costs for the five regulatory
options. BAT incremental compliance costs listed hi Table XI-1  are equal to the capital and operating and
maintenance (O&M) costs of each given technology.  For scenarios in which gas flotation systems are
already in place (i.e., specific Cook Inlet platforms), the incremental cost is only the O&M cost
associated with improved operation of the existing  technology.  In addition, Option 1 incurs zero
incremental costs because it sets all limitations equal to BPT.
                                        TABLE XI-1
    SUMMARY OF INCREMENTAL BAT AND NSPS COMPLIANCE COST ESTIMATES
                                          (1992 $)
Options
Option 1: BPT All
Option 2: Improved Gas
Flotation All
Option 3: Zero Discharge All
Except Cook Met (BPT for
Cook Inlet)
Option 4: Zero Discharge All
Except Cook Inlet (offshore
limitations for Cook Inlet)
Option 5: Zero Discharge All
•>•••, J
BAT Cosfs
Capital
Cost
" m '"" ,
0
44,897,167
80,423,518
88,536,994
164,773,267
O&M
'. Cost
($/yr)
0
5,677,889
16,629,622
17,664,732
26,137,105
" ,1SS!*$ Casts
Capital
., Cost
($>
0
913,747
1,729,887
1,729,887
1,729,887
O&M
Cost
($/yr> ~
0
147,815
392,986
392,986
392,986
       The incremental costs for NSPS are also equal to the capital and O&M costs for each given
technology.  No new  sources are expected for Cook Inlet.  Therefore,  NSPS costs  and pollutant
reductions are predicted only for the Gulf of Mexico.  Table XI-1 also presents the NSPS incremental
                                             XI-2

-------
 compliance costs for the two regulatory options of gas flotation (Option 2) and zero discharge (Options
 3, 4 and 5). The derivation of these costs is explained in detail in the remainder of this section.

        In order to generate estimates of costs and pollutant removals for each option, EPA used existing
 industry profile information.  The industry profile information was obtained from studies described in
 Section V, and includes state discharge monitoring data, EPA site visits and sampling reports, and direct
 contacts with the operators.  This information consists of the following elements:

        •      Identification  of currently discharging  production facilities including name  of  the
               operator, state discharge permit number, location of the producing field, produced water
               discharge volumes,  and date of compliance with state requirements for no discharge
               where applicable.
        •      Contaminant levels in produced  water from BPT treatment.

        All options considered for this regulation beyond the BPT level of control for the coastal region
 are based on two treatment technologies:

        •      Filtration followed  injection of produced water into a compatible geologic formation,
               either for disposal  or for  waterflooding.  For operators hi the Gulf of Mexico,  the
               injection option includes cartridge filtration as pretreatment followed by  injection  for
               disposal. For Cook Inlet operators, the injection option includes granular media filtration
               and gas flotation as  pretreatment followed by injection either for waterflooding or  for
               disposal.
        •      Improved operating performance of gas flotation followed by discharge to surface water.

       In  referring to the options  considered for control of produced water discharges, the Gulf of
Mexico and Cook Inlet are presented separately in the option descriptions and accompanying discussion.
All other coastal areas are practicing zero discharge of oil and gas production wastes, and will be subject
to this proposal, even though not mentioned specifically.

       EPA's Region VI has recently published final NPDES General permits regulating produced water
and produced sand discharges to coastal waters in Louisiana and Texas (60 FR 2387, January 9,  1995).
The permits prohibit the discharge of  produced .water and produced sand derived  from the coastal
subcategory to any water subject to EPA jurisdiction under the Clean Water Act.

       Much of the  industry covered by this proposed rulemaking is also covered by these General
permits.  However, a significant difference between the permits and this proposal is that the permits do
                                              XI-3

-------
not cover produced water discharges derived from the Offshore subcategory wells into the main deltaic
passes of the Mississippi River, or to the Atchafalaya River below Morgan City including Wax Lake
Outlet.  This rulemaking would cover these discharges.

       Due to the close proximity of the tuning of the publication of the Region VI permits and this
proposal, this document presents the costs and impacts of this proposed rulemaking as if the Region VI
General permits were not final. The Region VI permit covers approximately 71 % of the produced water
volume being discharged hi the coastal subcategory.  The remaining 29 % is derived from coastal facilities
treating offshore  produced waters and currently discharging  them into main deltaic river passes  in
Louisiana, as well as from other coastal operations hi the U.S.

       The compliance costs of this rulemakhig (including the facilities covered by the Region VI permit)
are shown in Table XI-1.  With the Region VI General permits final, the costs of this rule would be
reduced to approximately $19.9 million annually.20

       EPA will more fully incorporate regulatory  effects of the Region VI General permits  upon
promulgation of the final rule.

3.0    COMPLIANCE COST METHODOLOGY FOR EXISTING FACILITIES IN THE GULF
        OF MEXICO
        EPA determined that 216 production facilities will be discharging produced water as of July 1996.
The treatment/disposal technologies evaluated and costed  for disposal of produced water from these
facilities are based on: 1) zero discharge by injection, and 2) effluent limitations based on improved
operating performance of gas flotation.  Three treatment/disposal scenarios have been developed for
production facilities hi the Gulf of Mexico region, as  follows:

        1)      Production facilities with low produced, water flow, referred to hereafter as small-volume
               facilities, will transport the produced v/ater  to a commercial facility for injection. There
               are 50 facilities hi this category.
        2)     Production facilities with medium to high produced water flow, referred to hereafter as
               medium/large facilities, will  treat  or inject onsite.   There are  166 facilities in this
               category.
        3)     For situations hi which more than one production facility exists  in a field and is operated
               by the same company, discharges are assumed to be combined for injection or treatment.
               There are a total of 46 production facilities  hi this  category for the zero discharge option
               and 36 for the unproved gas flotation option.
                                              XI-4

-------
        The cut-off flowrate separating small from medium/large-volume facilities was determined using
 a cost comparison analysis.  The cut-off value ranged from 70.5 bpd to 108.4 bpd depending on the type
 of facility and the technology option considered.  This analysis is described hi Section 3.4

        This section describes the development of compliance costs in terms of capital and operating and
 maintenance (O&M) costs for production facilities in the coastal Gulf of Mexico region. For the purpose
 of clarity, certain terminology used in this section is defined as follows:

        Design cost data:  Produced water flow rates and capital and O&M costs developed from actual
        equipment design and cost data obtained form oil and gas operators and equipment vendors. The
        term "design cost data" refers to both the "design costs" and the "design flows" (each defined
        below).   The design cost data were used to develop mathematical  models to best represent the
        relationship between cost and flow in order to predict facility-specific compliance costs.
        Design flows:   Produced  water flow  rates specifically  selected using  available treatment
        equipment sized and best engineering judgement.
        Design costs:  Capital and O&M design costs were calculated from actual equipment cost data
        obtained from  oil and gas operators and equipment vendors.  Design costs were calculated for
        each selected design flow.

        Information and data obtained from EPA site visits, oil  and gas production operators, vendor
 quotes,  cost information developed by the Energy Information Administration (Department of Energy),
 and engineering analysis were used to estimate design costs based on selected design flows. The design
 cost data were then used  to develop mathematical models that best represented the relationship between
 the design costs and the design produced water flows.

        Following the cost equation development process, actual facility-specific discharge flows were
 inserted into the equations to calculate capital  and O&M compliance costs.  The sources of the actual
 discharge data were state discharge monitoring reports (DMRs) from Louisiana and Texas.1 State permit
 data show that 216 production facilities will be discharging produced water after July 1, 1996.  Capital
 and O&M compliance  costs were derived for each of the 216 production facilities based on individual
 flow and location information.1  Produced water flows for these facilities reportedly range from 1 barrel
per day (bpd) to 144,000 bpd.

        The regulatory compliance costs were estimated  for all  options based on  several  general
 assumptions for future  produced water volumes and for the location of the production facilities.  Future
produced water volumes are required when sizing and costing the treatment equipment.  Production
                                              XI-5

-------
facility location is required for assigning the injection well cost and the retrofit cost, which are different
for land location than for water location.  The following are these general assumptions:

       1)      Future produced water volume increases by the same rate for both oil and natural gas
               producing wells. While produced water volumes from gas producing wells will generally
               not increase by the same rate as from oil producing wells, EPA did not differentiate
               between them.
       2)      Capital costs for facilities that will continue to discharge produced water after July 1,
               1996 were estimated by assuming a future produced water flow 1.5  tunes the current
               flow.2   The use of this'factor,  which is  a standard engineering design  practice,  has
               resulted in an overall conservative capital cost estimate.  Many operators have indicated
               a factor of 1.2 to 1.25 is typically used when sizing and costing produced water treatment
               equipment.3
       3)      All Louisiana-based production facilities have water access.
       4)      All Texas-based production facilities have land access.

       For purposes of estimation, all Texas production facilities were assumed to be located on land
and all Louisiana production facilities were assumed to be located over water.  However, EPA is aware
that some facilities in Louisiana are located over land and some facilities in Texas are located over water.
In the absence of specific location information for all of the 216 discharging facilities, EPA determined
this to be a good approximation since the coastal topography of Louisiana consists of more extensive
wetlands than that of Texas.  The location of the production facility is  an important factor  when
deterrnining the cost of drilling an injection well, and the cost of produced water transportation.

       However, EPA also investigated the location of each discharge in Texas to determine the accuracy
of the above estimation.  The state permit data for Texas includes the longitude and latitude for most
produced water outfalls. In order to more specifically estimate the location of Texas production facilities
from the state data, EPA assumed that the production facility location is the same as the outfall location.
As a result, 42 facilities were estimated as being over  water.21 A sensitivity analysis was performed to
determine whether or not a significant cost differential occurs by costing all 126 Texas facilities on land
versus 84 on land and 42 over water. This analysis was performed for the zero discharge option only
as a "worst case" test.  Table XI-2 presents the results which show a small difference between the two
cost bases.  Capital costs are higher for injection over water than on land because of higher injection well
installation and retrofit costs.  The O&M costs are slightly lower for water- than land-access because
pretreatment over water includes cartridge filtration, whereas backwashing is used over land, which is
more costly. The difference in the total capital  cost for Gulf of Mexico for water and land locations hi
                                               XI-6

-------
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                                     XI-7

-------
Texas is only 6% higher than for all land locations.


        In addition, it should be noted that as discussed in Section IV of this document, out of the 216

facilities EPA has determined to be discharging in  1996,  seven facilities hi Nueces Bay, Texas will

actually cease discharging hi 1995.  Costs  for  these facilities have been left in EPA's  cost  analysis

presented here, resulting hi an over-estimate of O&M cost by 1.9% and of capital cost by 1.4% for the

zero discharge numbers (See Appendix XI-4).  EPA plans to delete the  costs for these facilities prior to

calculating costs for the final rule.


3.1     DESIGN CAPITAL AND O&M COSTS FOR SMALL-VOLUME FACILITIES

        For all treatment options, small-volume facilities transport produced water either by barge or by

truck to a  commercial facility for disposal.  For these facilities, the capital  cost includes the cost of

installing a storage tank to provide for sufficient onsite storage capacity.  The O&M cost includes the

transportation cost plus the disposal cost charged by the commercial disposal facility.  The following

general assumptions were used to develop design costs for all small-volume facilities:


        •       Small-volume facilities with water access  transport  produced water to a commercial
               facility by barge.  Based  on the produced water flows (< 108.4 bpd), these facilities
               install storage tanks to provide a minimum of 7 days storage capacity which will allow
               for weekly barge trips by a commercial service company  (the storage tank capacity is
               flow dependent - for details see discussion at the end of Section 3.1).

        •       A single barge of 3,000 bbl capacity  services multiple small-volume facilities to  full
               capacity.4 The number of facilities serviced by one barge depends on the onsite storage
               capacity, the distance between facilities, and the distance to the commercial  disposal
               facility. An average per barrel cost was developed based on assumed distances described
               hi Section 3.1.2

        •      Small-volume facilities with land access install one 150 bbl storage tank and transport
               produced water by truck to a commercial facility for disposal.  The 150 bbl capacity was
               selected because it exceeded the  volume of the vacuum  truck.  The low produced water
               flowrate of small-volume facilities (<70.5 bpd) allows  plenty of time to schedule truck
               service.

        •      Small-volume facilities with land access are  serviced by vacuum trucks which have a
               capacity of 119 bbl.5 Trucks are readily available and the number of truck trips depends
               on the volume of produced water generated.  An average per barrel cost was developed
               based on assumed distances  described in Section 3.1.2
                                              XI-8

-------
3.1.1   Design Capital Cost

        For small-volume facilities, capital costs for all design flows include the following:

        •      Storage Tank Purchase Cost: The purchase cost depends on the storage tank capacity.
               Purchase costs were available for tanks of 150 bbl, 1,000 bbl, and 1,500 bbl storage
               capacities.4  Purchase costs for tanks with storage capacities of 300 bbl and 500 bbl were
              ' obtained by interpolating the costs for the 150 bbl, 1,000 bbl,  and 1,500 bbl tanks.6

        •      Installed  Costs:  Equipment installation costs  include the piping  cost  (15%  of the
               purchase cost), installation labor cost (32% of the purchase cost), and transportation cost
               (5% of the purchase cost).4 The equipment installation costs were calculated as fractions
               of the total equipment purchase costs based on the best available estimates of actual costs
               obtained from EPA sampling trips.4

        •      Additional Costs (Engineering, Contingency, and Insurance-Bonding Fees):  These
               fees were added to the equipment purchase and installation costs to develop actual capital
               costs.  These fees include all engineering design costs (10% of equipment installation
               cost), administrative costs (4% of equipment installation cost),  and any incidental costs
               incurred in the process of purchasing and installing the equipment (15% of equipment
               installation cost).6

        •      Platform/Concrete Pad Retrofit Costs: Equipment space requirements were estimated
               to be twice the footprint.  The retrofit costs were STS/ft2 and $40/ft2 for facilities with
               water access  and land access, respectively.4 '


        Total capital costs include platform retrofit costs for facilities with water access or concrete pad

retrofit cost for facilities with land access. The information obtained during EPA's sampling trips shows

that equipment space requirements vary between two to three times the footprint, with tanks requiring

less additional space than pumps and filters.  The total area  requirements for equipment on offshore

platforms was reported to be  twice  the footprint.7 The benefits from minimizing equipment space

requirements are two fold:  one is the economic aspect of reduced retrofit cost,  and the second is the

reduction of the impact of human activities on the surrounding environment. Therefore, for coastal oil

and gas operations, equipment space requirements were assumed to be twice the footprint. The retrofit

costs used hi this analysis were $75.00/ft2 for platforms at facilities with water access and $40.00/ft? for
concrete pads  at land-accessed facilities.4


        The following design criteria, which directly affect the capital costs, were also used for small-

volume facilities (see Section 3.1 for rational):
               Facilities with water access and with flows less than or equal to 21 bpd will install one
               150 bbl storage tank.
                                              XI-9

-------
        •       Facilities with water access and with flows greater than 21 bpd but less than or equal to
               43 bpd will install one 300 bbl storage tank.
        •       Facilities with water access and with flows greater than 43 bpd but less than or equal to
               71 bpd will install one 500 bbl storage tank.
        •       Facilities with water access and with flows greater than 71 bpd but less than or equal to
               143 bpd will install one 1,000 bbl storage tank.
        •       Facilities with water access and with flows greater than 143 bpd but less than or equal
               to 214 bpd will install one 1,500 bbl storage tank.

        A mathematical model was not necessary  in developing  compliance costs for  small-volume
facilities because the capital costs are estimated as discrete values associated with discrete tank capacities.
Table XI-3 shows that for five different tank sizes, five capital costs were calculated for water-access
facilities.  For land-access facilities, Table XI-3 lists only one capital cost for all flows because of the
assumptions that: 1) all land-access facilities  will install a 150 bbl  tank, and 2) 119 bbl vacuum trucks
are readily available and have unlimited access to these sites.

3.1.2   Design O&M Cost
        For small-volume facilities with water access, O&M costs include the transportation cost that the
barge service company will charge plus the disposal cost charged by the commercial disposal company.
The average commercial O&M cost was estimated  to be approximately $1.63/bbl.  The barge service
company was  assumed to be a commercial operation and therefore the transportation cost is based on
known barge and tug  rental costs. An average  distance of 10 miles between discharging facilities, and
a distance of 50 miles  to the disposal facility were also assumed.2'3 Appendix XI-1 shows the assumptions
and calculations used to derive the average commercial  O&M disposal cost per barrel per facility with
water access.

        For small-volume facilities with land access, O&M costs include the total transportation cost that
the vacuum truck service will charge plus the disposal cost charged by the commercial disposal company.
The average commercial O&M cost was  estimated to be $1.66/bbl.4 The transportation cost is based on
an average roundtrip distance of 120 miles that a 5,000 gallon (199 bbl) truck will travel. Appendix XI-1
also shows the assumptions and calculations used to derive the average commercial  O&M disposal cost
per barrel per facility with land access.

        O&M costs vary  with flow rate, but a mathematical cost  model was not necessary for small-
                                              XI-10

-------
















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volume facilities.  Annual O&M costs were simply calculated by assuming that regardless of flow or
storage tank size, average commercial disposal costs are $1.63/bbl for water-access sites and $1.66/bbl
for land-access sites. Hence, the total O&M costs shown in Table XI-1 for either water-access or land-
access are simply the flow (bpd) tunes 365 days/yr tunes the average commercial costs. For example,
a facility with water access and a flow of 22 bpd, under this scenario, will incur a capital cost of $40,607
and O&M cost of $12,495/yr.

3.2     DESIGN CAPITAL AND O&M COSTS  FOR MEDIUM/LARGE-VOLUME FACILITIES
        As previously stated, costs for medium/large-volume facilities were developed by first estimating
design costs based on selected design flows, and then performing a regression analysis with these data
points to derive the cost equations.  Eight design flows were selected so that they fell within the actual
range of the 166 medium/large-volume discharging facilities. Section 3.2 discusses the design parameters
used as the basis for the cost equation derivations.  Section 3.3 presents the cost  equations.

3.2.1   Injection
        Capital and O&M costs for medium/large-volume facilities include the costs of pretreatment by
cartridge filtration and the costs of the injection pumps and wells. For production facilities with land
access, the proposed injection system does not include pretreatment by cartridge filtration, but rather
includes costs for more frequent injection well downhole maintenance. This is because it was found that
for land-access facilities, cartridge filtration is less necessary and well workover  costs are cheaper.4

        Based on information obtained during EPA's sampling trips, the most common downhole injection
well maintenance performed is a backwash operation.4 In a backwash operation, the flow hi the injection
well is reversed to remove the solids that accumulate on the face of the receiving formation that would
otherwise interfere with the injection operation.4  According to information obtained during EPA's
sampling trips, the frequency of the backwash operations is facility specific. However, more frequent
backwashes were performed where filtration equipment was not used as pretreatment to injection.  The
frequency of backwash operations and costs are discussed in more detail in Section 3.2.1.2.

3.2.1.1  Design Capital Cost
        The design capital costs are based on direct quotes from equipment vendors, summary statistics
from the EPA 1993  questionnaire, and standard engineering cost estimating factors.  The following list
summarizes the assumptions made to develop the design capital  costs.
                                             XI-12

-------
Pretreatment:  Facilities with water access are assumed to include cartridge filtration as
pretreatment to injection, while facilities with land access are assumed not to install
cartridge filtration but rather to conduct more frequent backwashings of the injection
wells.

Cartridge  Filters and Feed Pumps:  were sized based on the design flows  and the
manufacturer recommended volumetric loads as follows:9

        10" cartridge - 7 gpm/cartridge
        20" cartridge - 14 gpm/cartridge
        30" cartridge - 21 gpm/cartridge

One module can contain a maximum of 4 cartridges.   Where design flow exceeds 84
gpm, multiple modules were costed.  The cartridge filters are rated  for  a maximum
pressure of 150 psig. Filter feed pumps were sized for the required flow and a discharge
pressure of 50 psig.

Feed Pumps:  are electrically driven for single-well injection systems or flows up to
5,000 bpd.10 For multiple well injections systems, the filter feed pumps have natural gas
driven motors.

Injection Pump Feed Tank:  After filtration, the produced water goes into an injection
pump  feed tank.  The capacity  of  the feed  tank is  flow dependent.  For facilities
processing  less than  or equal to 1,000 bpd of produced water, a surge tank of 150 bbl
capacity was included. This translates into a minimum of 3.6 hrs of surge capacity for
the design flow of 1,000 bpd.  For facilities processing more than 1,000 bpd but less than
or equal to 5,000 bpd of produced water, a surge tank of  1,000 bbl capacity was
included. This translates into a minimum of 4.8 hrs of surge capacity for the design flow
of 5,000 bpd.  For facilities processing more than 5,000 bpd of produced water, a surge
tank of 1,500 bbl capacity was included.   This translates into 51 minutes of surge
capacity for the design flow of 42,000 bpd [(1,500/42,000) bbl/bpd x (24 x 60) min/day].
This assumption is consistent with the  Walk-Haydel  analysis in which the  minimum
capacity for the surge tank was assumed to be 3 minutes.11

Injection Pumps: are positive displacement pumps capable of delivering  the required
flow at 1,500 psig.  Costs include the pump plus the motor, both skid mounted.10 Spare
pumps are  not included because the results of the statistical analysis of the Coastal Oil
and Gas Questionnaire show that the majority of injection facilities in the coastal region
(i.e., 58%) do not use spare pumps.12

Spare Wells:  According to studies of producing areas of Louisiana and other areas in
the U.S. where injection wells are used to dispose of produced water,  operators rarely
go to the expense of drilling a "spare" well to handle produced water when the primary
disposal well is shut in for servicing.4'15  Instead, it  is more typical  for  operators to
respond by temporarily incurring the costs associated with hauling produced water to
commercial disposal facilities, or shutting in the producing well(s) until the disposal well
is brought  back into service.  If the production facility is serving multiple wells, those
with the highest water cut are more likely to be shut in for the duration of the injection
well workover.  Therefore, this analysis assumes that no spare wells are needed.
                               XI-13

-------
Pump Engines:  The injection pumps with capacities up to 500 bpd, or 12 hp, are
electrically driven.  For flows greater than 500 bpd, natural gas driven engines are used.

Electric Pumps:  For electric pumps and instrumentation, no additional power generation
equipment is required.  The assumption used here is that existing onsite power generation
equipment can handle an excess load of up to 25 hp.

Injection Well Capacity:   The  average capacity  for  the injection wells, new or
converted, is 5,000 bpd.  For flows greater than 5,000 bpd, the number of injection wells
and pumps was determined based on one injection well and one pump with a capacity of
5,000 bpd for each 5,000 bbl of flow  or portion thereof. For this cost estimating, an
average injection well capacity of 5,000 bpd was selected  based on information obtained
from the 1993 survey of coastal  oil and  gas industry.   This  average injection well
capacity is based on the statistical analysis of the produced water flow data from facilities
that currently inject produced water. The statistical analysis which took into account the
effect of underutilization by spare wells, showed that a typical injection well in the Gulf
of Mexico has an average capacity of 5,000 bpd.8 The cost to drill an injection well is
dependent on the required drilled depth and the location of the well (whether on land or
over water), but to a lesser extent on the capacity of the well.

Average Injection  Well Cost:  EPA estimated, based on data obtained  directly from
operators, that 90% of injection wells will be converted from previously producing and
abandoned wells and 10% will be newly drilled injection wells.14  For land-access
facilities, the average injection well cost (i.e., average cost of new and converted wells)
is $107,500 and for water-access facilities is $246,000, based on 90% of the  operators
having wells available for conversion to injection wells.

The cost of a new well at facilities in the Gulf of Mexico region has been estimated to
be $175,000 for land-access and $300,000 for water-access.4 It has been noted that the
cost  of drilling injection wells in the coastal Gulf  of Mexico  region does  not vary
significantly with well capacity for wells having the same depth (Kerr and Assoc., 1990).
The cost of converting an existing well to an injection well at facilities in the coastal Gulf
of Mexico region has been estimated to be $100,000 for  land-access and $240,000 for
water-access.4  Again,  the well conversion  cost is  not  affected  significantly by the
injection capacity of the well (Kerr and Assoc., 1990).

For water-accessed  facilities the average injection well cost was determined as follows:

Injection Well Cost =  0.9 x $240,000  + 0.1 x $300,000 = $246,000

For land-accessed facilities the  average injection well cost was determined as follows:

Injection Well Cost =  0.9 x $100,000  + 0.1 x $175,000 = $107,500

Platform/Concrete Pad Retrofit Cost: Equipment space requirements were calculated
based on twice the equipment footprint area requirements.  See section 3.1.1 for  a
detailed explanation of this assumption.

Pipeline Cost: is based on $4.06/in of pipe diameter/ft.  The piping diameters used in
the calculations of piping cost is as recommended  hi the Walk-Haydel report as follows:11
                               XI-14

-------
                      Flows                        Pipe Diam.

                      up to 5,000 bpd               3-inch
                      5,001 up to 14,000 bpd        4-inch
                      greater than 14,000 bpd        6-inch

        •      Average Pipeline Distance:  The average pipeline distance from the separation/treatment
               facility to the injection well is assumed to be 3,433 feet for facilities with water access
               and 794 feet for facilities with land access.6

        •      Installed  Costs:   Equipment installation costs  include the piping cost (15%  of the
               purchase cost), installation labor cost (32% of the purchase cost), and transportation cost
               (5%  of the purchase cost).4

        •      Additional Costs (Engineering,  Contingency, and Insurance-Bonding Fees):  These
               fees were added to the equipment purchase and installation costs to develop actual capital
               costs. These fees include all engineering design costs (10% of installed equipment cost),
               administrative costs (4% of installed equipment cost), and any incidental costs incurred
               in the process of purchasing and installing the equipment (15% of equipment installed
               cost).6


        Tables XI-4 and XI-5 present the design capital and O&M costs for the selected design flows for
production facilities with water- and land-access, respectively.
3.2.1.2 Design O&M Cost

       Design O&M costs for produced water injection are presented in Tables XI-4 and XI-5.  The

assumptions used to develop design O&M costs for injection are as follows:


       •       Labor:  Labor  costs are based on an hourly rate of $20.00 per hour and on 2 person-
               hour per day for the operation of single-well injection systems.  Labor costs for multiple-
               well injection systems with water- and land-access are based on 2.42 person-hour per day
               and 2.37 person-hour per day, respectively.12

       •       Fuel:  Fuel cost was calculated  based on the maximum pumping horsepower required
               above 25 hp, continuous operation (365 days per year), and on a natural gas unit cost of
               $2.50 per 1,000 cubic feet.4-12

       •       Maintenance Materials: Maintenance materials represent 5 % of the equipment purchase
               cost.4

       •       Chemicals: The cost of adding bactericides and polymer or surfactants was estimated for
               injection well operation.  The unit cost for bactericides addition is $1.095/bpd and for
               polymer/surfactant is $3.285/bpd.4

       •       Well Backwash:  Well backwash frequency and unit cost are based on the results of the
               statistical analysis of the EPA Questionnaire.12 Well backwash cost is $10,146 per job
                                             S3-15

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-------
               and $9,600 per job for facilities with water- and land-access, respectively. The frequency
               of well backwash operations is once every two years for facilities with water access and
               0.7 per year for facilities with land access.6  Well backwash is performed more often at
               land-based facilities because it is assumed that no filtration equipment is installed.
3.2.2   Gas Flotation
       The second option evaluated by EPA would establish more stringent than BPT effluent limitations
based on improved operating performance of gas  flotation technology.  This technology would consist
of improved operation and maintenance of gas flotation treatment systems, more operator attention to
treatment system operations, chemical pretreatment to enhance system effectiveness, and possible resizing
of certain treatment system components for increased treatment efficiency. The costs for this option were
developed for new gas flotation systems for all discharging facilities in the Gulf of Mexico because gas
flotation is not currently used in the coastal states  as a BPT treatment technology.19  Design capital and
O&M costs for medium/large-volume facilities include the costs of the gas flotation unit, plus a natural
gas driven generator for systems that require more  than 25 hp to operate.   Costs  for natural gas
generators  were  derived based  on  information developed  by Energy  Information  Administration
(Department of Energy).7 Installed equipment cost is the same for all production facilities,  regardless of
their location.

3.2.2. / Design Capital Cost
       Tables XI-6 and XI-7 present the design capital and O&M costs for gas flotation for the selected
design flows for production facilities with water- and land-access, respectively. Design equipment capital
costs for gas flotation in coastal areas were obtained from supporting documentation for  the Offshore
Development Document that were in 1986 dollars.16 These figures were adjusted to 1992 dollars by the
ratio of Engineering  News Record-Construction Indeces (ENR-CCI) of 4985 (1992) to 4295 (1986).
here.
       The following list summarizes the assumptions made to develop the design capital costs included
               Equipment Purchase Cost:  The equipment purchase cost for all production facilities
               includes: gas flotation and feed pump, and natural gas generator for systems that require
               more than 25 hp to operate (flows greater than 5,000 bpd).  Gas flotation equipment cost
               includes: gas flotation skid-mounted, complete electrical systems, oil and water outlets
               brought to the edge of the skid, and sufficient instrumentation for proper operation. All
               gas flotation systems are equipped with electric motors.5  For systems that require more
               than 25 hp to operate (i.e., flows greater than 5,000 bpd), the electric power is supplied
               by natural-gas driven generators.7
                                             XI-18

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               Installed Costs:  Equipment installation costs include the piping cost (15% of the
               purchase cost), and installation labor cost (32% of the purchase cost).  No transportation
               costs were included because the equipment costs represent costs of equipment delivered
               to the Gulf of Mexico area.4
               Additional Costs (Engineering, Contingency,  and Insurance-Bonding Fees): These
               fees were added to the equipment purchase and installation costs to develop actual capital
               costs. These fees include all engineering design costs (10%), administrative costs (4%),
               and any incidental  costs  incurred  in  the process  of purchasing  and installing the
               equipment (15%).6
               Platform/Concrete Pad Retrofit Costs: Equipment space requirements were estimated
               to be twice the footprint.6  The retrofit costs were $75/ft2 and $40/ft2 for facilities with
               water access and land access, respectively.4
3.2.2.2 Design O&M Cost
       Estimated design O&M costs for gas flotation treatment are presented in Tables XI-4 and XI-5.
The annual operating and maintenance cost was estimated to be 10% of the total capital cost. In addition,
labor costs were estimated based on one person-hour per day at a rate of $20.00 per hour.6 Typically,
the operating and maintenance costs include: polymer and/or flocculation enhancement chemicals, fuel
cost, and feed pump and agitator maintenance and replacement costs.

3.3   MODEL COST EQUATIONS
3.3.1    Injection
       For the zero-discharge via  injection option, eight independent linear  cost  equations were
developed for medium/large-volume  facilities: two for single well injection systems with water access
(one capital cost equation and one O&M cost equation), two for single injection well systems with land
access, two for multiple injection well systems with water access, and two for multiple injection well
systems with land access. Again, single injection well systems are assumed for operations with flows less
than or equal to 5,000 bpd and multiple injection well systems are assumed for flows greater than 5,000
bpd.  Table XI-8 lists the eight cost equations.

       The mathematical model best representing the relationship between design flow and design cost
for injection was found to be a line of the general form:
                                             XI-20

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                                                     b
where:         Y = design cost (either capital or O&M cost)
               m = slope (X-coefficient)
               X = design flow (in barrels per day)
               b = Y-intercept (constant)

        The constants (y-intercept) and x-coefficients for each of the eight equations were determined
using regression analysis with the design costs shown in Tables XI-4 and XI-5 as input data.  Note that
in Table XI-8, "design" costs are those  from Tables XI-4 and XI-5, and "calculated" costs are those
generated by  the model cost equations  for each design flow listed.  The comparison of design to
calculated costs shows an error of no greater than + 7.0% for all systems.

3.3.2   Gas Flotation
        For the discharge via gas flotation option, six independent cost equations were  developed for
medium/large-volume facilities: one capital cost equation for water accessed facilities with flows less than
or equal to 5,000 bpd, one capital cost equation for land accessed facilities with flows less than or equal
to 5,000 bpd, one O&M cost equation that is the same for these  systems, one capital cost equation for
water accessed facilities with flows greater than 5,000 bpd, one capital cost equation for land accessed
facilities with flows greater than 5,000 bpd, and finally one O&M  cost equation that is the same for these
greater than 5,000 bpd systems. There  are only two O&M cost equations because the location of the
production facility, i.e., land or water, does not affect the design O&M cost for gas flotation.  However,
capital  costs are  slightly different because of the difference in the retrofit cost for water versus land
locations.   Table XI-9 lists  the six  cost equations developed and used to predict  regional costs  for
treatment by gas  flotation.

        The mathematical model best representing the relationship between design flow and design cost
for production facilities with flows up to 5,000 bpd was found to be a function of the general form:
        For production facilities with flows greater than 5,000 bpd, the best-fit mathematical model is
a linear function of the general form:
                                              XI-22

-------
                                          Y = a + bX
where:         F = design cost (either capital of O&M cost)
               a,b,c —  constants
               X = design flow (in barrels per day)

        The constants (a,  b,  and c) for each of the six equations were determined using regression
analysis with the design costs shown in Tables XI-6 and XI-7 as input data. Note that in Table XI-9,
"design" costs are those from Tables XI-6 and XI-7, and "calculated"  costs are those generated by the
model cost equations for each design flow listed. The comparison of design to calculated costs shows
an error of no greater than + 3.1 % for  all systems.
                                                 \
3.4    DETERMINATION OF CUT-OFF FLOW FOR SMALL- vs. MEDIUM/LARGE-VOLUME  FACILITIES
        An important step in the development of the model cost equations was the determination of the
cut-off  flow rate that would distinguish small-volume  facilities (those sending produced water to
commercial disposal facilities) from medium/large-volume  facilities  (those injecting or treating the
produced water onsite).  An  analysis was performed to identify the maximum flow rate that a small-
volume facility can economically dispose of  commercially  and the minimum  flow rate that  a
medium/large-volume facility can  economically  inject or treat  onsite.  In general, this analysis  was
performed by developing total annual cost equations from the model cost data listed hi Tables XI-3, XI-8,
and XI-9, plotting as total annual cost vs. flow rate, and noting the flow rate at which the lines intersect.
The following discussion explains the details of this analysis.

        Capital and O&M  costs for commercial disposal for small-volume facilities with both water and
land access  were developed based  on flows ranging from 5  to 214 bpd as shown hi Table XI-3.  To
annualize the capital cost,  a capital recovery factor of 0.1627 was used based on 10 years and 10%
interest rate. Total annual costs were then calculated by adding the annualized capital cost and the O&M
cost for each design flow.   Total annual cost equations were then developed by regression analysis, and
plotted against the flow.

        Capital O&M costs for onsite single-well injection for medium/large-volume facilities with both
water and land access were developed based on flows ranging from 100 bpd to 5,000  bpd using the
assumptions identified hi Tables XI-4, XI-5, XI-6, and XI-7.  To annualize the capital cost, a capital
recovery factor of 0.1627  was used based on  10 years and 10% interest rate.  Total annual  costs were
                                             XI-23

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then calculated by adding the annualized capital cost and the O&M cost for  each flow. Total annual cost
equations were then developed by regression analysis, and plotted against the flows.  Figures XI-1 and
XI-2  show the cut-off flow for produced  water injection at  facilities with water and land access,
respectively.

        The cut-off flow is the flow rate at  which total annual  costs for small- and for medium/large-
volume facilities are the same.  This means that it would be more economical for facilities with flows less
than or equal to the cut-off to  install additional storage capacity and dispose of the produced water at a
commercial  facility, while for the  remaining facilities, injection or treatment onsite would be more
economical.

        For the injection treatment option, the cut-off flow was found to be 108.4 bpd and 70.5 bpd for
facilities with water- and land-access, respectively. Out of the 216 facilities, 23% of the produced water
dischargers are small-volume.  For the treatment option based on gas flotation, the cut-off flow was found
to be 70.5 bpd and 76.5 bpd for facilities with water- and land-access, respectively.6  Out of the 216
facilities, 23% of produced water dischargers are small-volume.

3.5    GRANULAR MEDIA vs. CARTRIDGE FILTRATION
        Granular media filtration is  an alternative pretreatment to injection. This technology is used at
oil and gas facilities to reduce the TSS in produced water prior to discharge or injection.  However, other
less costly filtration systems such as cartridge filtration are available for coastal operations which have
relatively low average  flows.   Both granular media and  cartridge filtration technologies have been
successfully demonstrated, proven, and are widely used.

        As part of this rulemaking,  EPA investigated the economic feasibility of using granular  media
vs. cartridge filtration systems as pretreatment to injection of produced water by comparing the capital
and O&M costs of both treatment  systems  for various produced water flows.  The cost comparison
analysis, performed over  the next 10 years, showed that for produced water discharges greater than
64,000  bpd, granular media filtration is more economical than cartridge filtration  as  pretreatment to
injection in the coastal regions.

        In 1989, Walk, Haydel developed costs for the injection of produced water using granular media
filtration as pretreatment,  as part of an economic analysis for produced water discharges in Louisiana.11
                                             XI-25

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                   FIGURE XI-1
     CUT-OFF FLOW ANALYSIS FOR INJECTION AT
   COASTAL PRODUCTION FACILITIES IN LOUISIANA
                SO         100
                          Flow

              .SmaI I-VoIume FacI I 111es

              .Med i urn/Large-VoIume Fac11 111es
                   FIGURE XI-2
     CUT-OFF FLOW ANALYSIS FOR INJECTION AT
COASTAL PRODUCTION FACILITIES WITH LAND ACCESS
                50         100
                          Flow

              .SmaI I-Volume Facilities

              . Med i urn/ Large-Vo I ume Fac i I i t i es
                       XI-26

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In their cost estimating effort, Walk-Haydel developed a capital cost equation for the surface equipment
that best represented the relationship between cost and flow. The surface treatment system included dual
upflow multimedia filters (one operating and one on standby), filter feed tank and pump, backwash pump
and tank, a polymer feed system, and the injection pumps. Not included in surface equipment capital cost
in the Walk-Haydel report is the injection well cost, pipeline to injection well, and a retrofit cost. The
O&M  cost (which includes labor,  fuel consumption, maintenance materials,  chemicals  use, and any
additional operating expenses) was estimated as representing 6.05% of the surface equipment total capital
cost.

        The second set of capital and O&M cost equations were developed for cartridge filtration systems
                   *
for two facilities in Louisiana that generate over 100,000 bpd of produced water.  These costs are based
on the same assumptions as described in Section 3.2.1,  excluding retrofit, pipeline, injection well costs,
and well backwash cost.17

        Total annual costs were calculated for both treatment systems using a capital recovery factor of
0.1627. A comparison of the total annual costs for both granular media filtration and cartridge filtration
showed that for a system with produced water flows greater than 64,000 bpd, granular filtration is more
economical than cartridge filtration as pretreatment to injection. There  is only one facility in the Gulf
of Mexico coastal area that would benefit economically from installing granular filtration as pretreatment
to injection.   This facility currently discharges in the coastal area 144,000 bpd of produced water
generated offshore.  Although this analysis showed that it would be more economical for one facility to
use granular media filtration instead of cartridge filtration as pretreatment to injection, for reasons of
being consistent and conservative EPA projected the economic impact of injection for this operator based
on the cartridge filtration cost estimates.

3.6    CENTRALIZED TREATMENT SYSTEMS
        Directing discharges to centralized treatment systems within the same field and the same company
is an alternative that can provide savings both in the form of capital  investment and hi the annual
operating  and maintenance  costs.   Therefore, a cost comparison analysis was performed  for  each
treatment option to determine which production facilities would benefit  economically from centralized
onsite injection and gas flotation systems. Centralized systems were considered for medium/large-volume
facilities within the same field because piping costs increase significantly with increasing distance.  Small-
volume facilities were not included in this analysis because they transport produced water to commercial
                                             XI-27

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facilities for injection, under all treatment scenarios.  Also, centralized systems were only considered for
production facilities within the same company because financial agreements between companies are
difficult to predict.

       The pipeline distance to a centralized treatment system was estimated based on the producing field
dimensions.  Field dimensions were estimated from oil and gas maps.  The pipeline distance was then
assumed to be one-half of the longest dimension for all production facilities within one field and owned
by the same operator.

       For the zero discharge by injection option, a total of 46 of the 216 production facilities in both
Louisiana and Texas were shown to economically benefit from centralized injection systems. For the gas
flotation option, a total of 36 of the 216 production facilities hi both Louisiana and Texas were shown
to economically benefit from centralized gas flotation treatment systems.  As shown in Table XI-11 in
Section 3.7.3, the total capital cost for medium/large-volume facilities with centralized injection system
in Louisiana and Texas was estimated to be $78,767,247. Without the centralized treatment,  the total
capital cost for  injection hi both Louisiana and Texas was estimated to be $78,804,787, which only
represents an increase of $37,540 (0.04%) over the centralized treatment scenario.  The total O&M cost
for medium/large-volume injection systems in Louisiana and Texas with centralization was estimated to
be $15,750,278/yr.  Without the centralized treatment, the total O&M cost for injection in both Louisiana
and Texas was  estimated to be $16,366,349/yr,  which only  represents an increase  of 4% over the
centralized treatment.  EPA's cost analysis included costs with centralization.

       Appendix XI-2 presents an example calculation of the centralized facilities  treatment costs.

3.7    GULF OF MEXICO COMPLIANCE  COSTS AND POLLUTANT REDUCTIONS
3.7.1   Compliance Costs for Existing Facilities
       Given the cost equations, actual volumes of produced water discharges were used to determine
facility-specific  costs.  Capital and O&M costs for the treatment technology options for the  Gulf of
Mexico were estimated by totaling the costs calculated for each existing production facility in Louisiana
and Texas that will continue to discharge  after August 1, 1996.  This date was selected as a reference
point because this rulemaking effort is scheduled to be final in July 1996.
                                             XI-28

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3.7.2   Compliance Costs for New Source Facilities
       Capital and O&M costs were also estimated for the six new sources of produced water discharges
in the Gulf of Mexico (see Section IV for new source projections). EPA determined that there will be
a total of four new source facilities with water access and two with land access.17 Of the four facilities
with water access, one is classified  as small-volume with an average produced water flow of 35.5 bpd
and three are classified as medium/large-volume, each with and average produced water flow of 3,355
bpd.17 Of the two facilities with land access, one is classified as small-volume with an average produced
water flow of 30.6 bpd and one is classified as a medium/large-volume with an average produced water
flow of 838  bpd.18

       Small-volume facilities will incur capital and O&M costs associated with  transportation and
disposal of produced water to commercial disposal facilities (see Section 3.1).

       Medium/large-volume facilities will incur capital and O&M costs associated with onsite treatment
and disposal by  injection or discharge (see Section 3.2).  Capital and O&M costs for  all new source
facilities  were developed using the same  assumptions  presented  in  Section 3.2 for  both treatment
technologies except for the type of engines and the cost of the injection well.  For new sources, the cost
of the injection well was assumed to be that of a newly drilled well  for both water- and land-access
facilities. All medium/large-volume treatment systems are equipped with electric motors.6 The electric
power required to operate the additional technology will be provided by natural gas driver generators.
The  generators are assumed an integral part  of the design of new production facilities and will have
sufficient capacity to also handle the produced water technology options. Therefore, additional costs for
generators are not included for new sources.

3.7.3   Total Gulf of Mexico Compliance Costs and Pollutant Reductions
       The incremental pollutant removals  associated with the treatment technologies were calculated as
the difference between the effluent  levels after treatment by the technology options (injection and gas
flotation) and the level associated with a typical BPT treatment (settling or  skim tank). That is, pollutant
removals by option were calculated by multiplying the average annual produced water flow rate for each
facility type (water- or land-access) by the difference in pollutant concentrations in BPT effluent and each
option effluent concentrations.  Pollutant removals are expressed in pounds per year.

       Table  XI-10 presents the produced water  pollutant loadings following BPT-level treatment and
                                             XI-29

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                                         TABLE XI-10
              POLLUTANT LOADING CHARACTERIZATION - PRODUCED WATER
                                      GULF OF MEXICO
Pollutant Groups
Conventional
Priority Organics
Priority Metals
Non-Conventionals
Total Pollutants
Tfrefcting Sources (Ib/yt)
BFT-level
11,641,571
555,396
134,438
4,294,469,209
4,306,800,602
Improved Gas Flotation
3,348,174
194,753
97,288
4,292,223,683
4,295,863,898
New Sources 
-------
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                                        XI-31

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                                            XI-32

-------
discharges in Cook Inlet: BPT,  injection,  and improved gas flotation.  Costs for  each option were
developed separately for the three shore-based facilities and for  the five  platforms  that discharge
overboard.  The following sections summarize the assumptions and present the regulatory compliance
costs estimated for injection and improved gas flotation for each discharging production facility. No costs
are attributed to BPT because this is equivalent to current practice.

4.1     INJECTION
        The  control technology for the injection option hi Cook Inlet is  treatment and injection of
produced water into producing formations as part of the waterflood operations or for disposal.  Seawater
is currently used for the waterflooding operations.  For platforms that currently inject seawater for
waterflooding, produced water will replace seawater. Therefore, the injection option includes the costs
of piping produced water back to platforms for waterflooding.  The pipeline costs represent the greatest
cost contributor, i.e., 75% of the total cost, for the injection option.

        A review  of industry concerns regarding the technical feasibility of replacing seawater with
produced water for waterflooding concluded that injection of produced water is technically feasible under
proper operating conditions.28 To meet these conditions, produced water must be pretreated for oil and
grease and total suspended solids (TSS) removal, and chemicals such as biocides and scale inhibitors must
be continuously added to the injection system.

        The injection treatment process consists of gas flotation, granular media filtration, and injection.
The estimated capital and O&M costs are the costs for additional equipment  beyond what is currently
available at each discharging facility or platform. Injection at the platform  is the only option available
to operators in  Cook Inlet because there are no geological famations beneath the onshore treatment
facilities capable of accepting the volumes of produced water generated.  Table XI-13 identifies currently
available treatment technologies at each production facility.  The information shown in Table XI-13 was
used to determine  the additional equipment that would be required for the injection process for each
production facility that discharges produced water directly to Cook Inlet.  Based on costing information
submitted by operators in Cook Inlet and the EPA Questionnaire, capital and O&M costs were estimated
for the eight individual dischargers.24'25

4.1.1    Capital Costs
        For the three shore-based facilities, capital costs include costs for additional equipment needed
                                              XI-33

-------
                                         TABLE XI-13
             PRODUCED WATER TREATMENT EQUIPMENT AVAILABLE AT EACH
                          DISCHARGING FACILITY IN COOK INLET23
Discharging Facility or Platform
Trading Bay*
Granite Point1
East Foreland1
Dillon*
Anna5
Baker*
Bruceb
Tyonek*
Available Treatment Equipment .For Produced Water
Gas Flotation
Yes
No
No
No
No
No
No
Yes
Filtration
Yes
No
Yes
Yes
Yes
Yes
Yes
No
Pipeline to
Platform
No
Yes
No
—
—
—
—
-
Injection
Equipment
Yes
No
Yes
Yes
Yes
Yes
No
No
* Shore-based treatment facility
b Platform
at the shore-based facility plus the costs for modifications at the platforms where injection will take place.
Total estimated capital costs include facility modification costs, equipment installation costs, additional
costs for engineering design, contingencies, insurance and bonding, pipeline costs (only for shore-based
facilities), and platform modifications that include retrofitting the platforms to accommodate additional
treatment equipment and injection systems. Table XI-14 presents the estimated total capital costs to inject
produced water for the three shore-based facilities and for the five platforms that discharge overboard.

       The Trading Bay production facility (TBPF) which receives production fluids for separation and
treatment from five platforms, currently has  gas  flotation units. Produced water will replace seawater
for waterflooding at three platforms (King Salmon, Grayling, and Dolly Varden)  that  currently
waterflood.  These platforms have filtration and injection equipment.  The three platforms currently inject
a total of 124,700 bpd of seawater.31 The total volume of produced water currently treated at the Trading
Bay facility is an average of 121,243 bpd. Since the amount of produced water to be injected is less than
the amount of seawater currently used in waterflooding operations, all produced water can be injected
via waterflooding. The assumptions used to develop the TBPF  modification capital costs are as follows
                                             XI-34

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(for details see Appendix XI-5):
              Shipping Pumps:  Four shipping pumps were costed, one for each pipeline and one
              spare. Each pump is rated for 1460 gpm at 700 psig with 1000 hp motor.  The pump
              costs which were presented in 1993 dollars, were adjusted for 1992 dollars by the ENR-
              CCI ratio of 4985/5210.25

              Booster  Pumps:  Three booster pumps were costed,  one for each pipeline.   Booster
              pumps are required to pump the water from the storage tank to 150 psi to satisfy the net
              positive suction head (NPSH) of the shipping pumps. Each pump is rated for 2120 gpm
              at 150 psig with a 300 hp motor.  The pump  costs which were presented hi 1993 dollars,
              were adjusted for 1992 dollars by the ENR-CCI ratio of 4985/5210.25

              Motors:  All motors are electric driven motors. Electricity for these motors is supplied
              by natural gas driven generator.  The cost of the power generation equipment is included,
              as provided by industry.25

              Storage Tanks: Two 15,000 bbl storage tanks were costed. These tanks were sized and
              costed by industry. The storage tanks costs which were presented  in 1993 dollars, were
              adjusted for 1992 dollars by the ENR-CCI ratio of 4985/5210.25

              Kg Launcher:   Three pig launchers were costed,  one for each pipeline.  Each pig
              launcher is 8  inch standard 600  ANSI.  The  costs for the pig launchers, which were
              presented hi 1993 dollars, were adjusted for 1992  dollars by the ENR-CCI ratio  of
              4985/5210.25

              Piping and Instrumentation: Piping and instrumentation costs were assumed to be 15 %
              of the equipment purchase cost. This cost includes any additional valves, fittings, piping,
              cables, conduits,  instrumentation, and instrumentation wiring.16

              Geographic Area Multiplier:  Because the equipment purchase costs represent Gulf of
              Mexico delivered equipment, a geographic  area multiplier for Cook Inlet of 2.0 was
              included.23

              Installation Cost: Equipment installation costs were set equal to the equipment capital
              cost.
23
              Equipment Building: The main equipment building is to house and protect the treatment
              equipment from the adverse weather conditions in Cook Inlet.25

              Additional Costs (Engineering, Contingency, and Insurance-Bonding Fees):  These
              fees were added to the equipment purchase and installation costs to develop actual capital
              costs.  These fees include all engineering design costs (10%), administrative costs (4%),
              and any incidental costs incurred  hi  the  process  of purchasing  and installing the
              equipment (15%).

              Pipeline Cost:   Pipeline cost  estimates include three 6.5-miles pipelines  of 8-inch
              diameter pipe.  These pipeline costs include pipeline and riser material cost, the cost to
              lay the pipeline, mobilization/demobilization costs,  and project management.   The
              pipeline costs which were presented hi 1993 dollars, were adjusted for 1992 dollars the
                                            XI-36

-------
               ENR-CCI ratio of 4985/5210.25
        •      Platform Modification Cost:   The  platform modification costs  are comprised of
               retrofitting each of the three platforms to accommodate the return pipeline to the existing
               injection system (pipeline  installation, pig receiver,  and replumbing existing piping).
               These costs which were presented in 1993 dollars were adjusted to 1992 dollars by the
               ENR-CCI ratio of 4985/5210.  In addition, costs for contract services were included.

        The Granite Point onshore treatment facility currently has bulk separation and skim tanks to treat
produced water before it is piped to the Spark platform for discharge. Add-on equipment includes gas
flotation and granular filtration.  Pipeline for produced water already exists from Granite Point to the
Spark platform. Thus, costs for a pipeline and the associated equipment (storage tanks,  booster pumps,
shipping pumps, pig launcher and pig receiver) were not included for this facility.  The operator indicated
that plans exist for future natural gas  production at the Spark platform which is currently  shut-in.22
Therefore, injection of produced water  at this platform will be for disposal rather than for waterflood.
Since there are no waterflooding operations at the Spark platform, injection pumps are required. It was
assumed that existing  service wells can be recompleted for injection. Platform modification costs include
the costs for connecting the produced water return  pipeline to the injection system, for  installing
manifolds and platform piping to injection equipment,  and for installing injection equipment.

        The East Foreland facility currently treats produced water by plate coalescers.  Add-on equipment
includes gas flotation for oil and grease removal, and all the auxiliary equipment required for transporting
produced water back to platform for injection: storage tank, booster pump, shipping pumps, and pig
launcher. Produced water will be treated for TSS at platform SWEPI "C" were multi-media filtration
equipment exists.  Pipeline was costed  to go from the E. Foreland facility back to platform "C" for a
distance of nine miles. Platform modification costs include the costs for pig receiver, for connecting the
produced water return pipeline to the platform, and for installing manifolds and platform piping to the
existing filtration and injection equipment.

        Of the five platforms that currently treat and discharge produced water overboard, three (Anna,
Baker, and Dillon) inject seawater for waterflooding.23  For these platforms, the only additional treatment
cost is for gas flotation.  The Bruce platform ceased waterflooding operations in 1983 due to overflooding
the formation.26  Since injection of produced water for waterflooding is not a technologically feasible
option,  it was assumed that  produced water at this  platform will be for disposal  into a more shallow
formation.  Because  filtration equipment is still available on  the Bruce platform, it can be used for
pretreatment to injection for disposal.  For the Brace platform,  capital cost includes  the cost of gas
                                              XI-37

-------
flotation,  injection equipment, and injection wells.   The Tyonek platform is a gas-only platform and

waterflooding is not currently practiced.  The current treatment system for produced water on the Tyonek

includes gas flotation.  The modification costs for this platform includes the cost of filtration equipment,

injection pumps,  and injection wells.   Produced water on the Tyonek platform will be  injected  for

disposal.  The assumptions used to develop the platform modification capital costs are as  follows (for

details see Appendix XI-5):

        •       Materials and Equipment: Gas  flotation and/or granular media filtration equipment,
               and injection pumps were costed for each platform based on additional equipment
            .   required for injection, as determined from Table XI-12.25  Injection pumps were sized
               and costed from information obtained from vendors.10

        •       Piping and Instrumentation: Piping and instrumentation costs were assumed to be 15 %
               of the equipment purchase cost. This cost includes any additional valves, fittings, piping,
               cables, conduits, instrumentation, and instrumentation wiring.16

        •       Geographic Area Multiplier:  Because the equipment purchase costs represent Gulf of
               Mexico delivered equipment, a geographic area multiplier for Cook Inlet of 2.0 was
               included.23

        •       Installation Cost:   An installation factor of 2.5 times the equipment capital cost was
               applied for equipment installation costs.23

        •       Additional Costs (Engineering, Contingency, and Insurance-Bonding Fees):  These
               fees were added to the equipment purchase and installation costs to develop actual capital
               costs. These fees include all engineering design costs (10%), administrative costs (4%),
               and any  incidental costs incurred  hi the  process of purchasing and installing  the
               equipment (15%).

        •       Platform Modification Cost: The cost of additional platform space was calculated based
               on equipment area requirements and a cost of $600 per square foot  in the form of a
               cantilever deck.27

        •       Injection  Wells:   One disposal well and a  spare were costed for  platforms  where
               waterflooding is not currently practiced.  Each well has a capacity of 6,000 bpd.23 The
               cost of drilling an injection well was  derived from data in the EPA Questionnaire to be
               $1,197,173 (see Section X).
4.1.2   O&M Costs

       The annual operating and maintenance cost was estimated to be ten percent (10%) of the total

capital cost. Typically, the operating and maintenance costs include: labor, polymer and/or flocculation

enhancement chemicals, fuel cost, and equipment maintenance and replacement costs. In addition, costs
for chemical treatment for injection such as scale inhibitors and biocides, and injection well maintenance
                                             XI-38

-------
costs were included for each platform where produced water has been proposed for injection. These costs
were obtained from the EPA Questionnaire from facilities that currently inject produced  water for
waterflooding.24 A statistical analysis of the chemical usage and produced water injection rates indicated
that  dosages for scale inhibitors and biocides are on the average 0.00221 gal/bbl and 0.00181 gal/bbl,
respectively.23 Table XI-15 lists the O&M costs that were estimated for injection of produced water for
each discharging facility in Cook Inlet. Total O&M costs for each production facility in Cook Inlet that
discharges produced water are presented hi Table XI-14.

4.2     IMPROVED GAS FLOTATION
        The control  technology for the improved gas flotation option  is treatment and discharge of
produced water  to Cook Inlet.  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 to achieve the  stricter effluent limitations that are proposed based on
improved gas flotation.  Table XI-13 identifies  currently available treatment technologies at  each
production facility.  The  information shown in Table XI-13  was used to determine  the  additional
equipment that would be required for each production facility that discharges produced water directly to
Cook Inlet.

4.2.1    Capital Cost
        Capital costs have been estimated for gas flotation treatment for those production facilities that
currently do  not have gas flotation.  Capital costs for facilities  that discharge produced  water are
presented hi Table XI-16.  The assumptions used to develop the capital costs for gas flotation are as
follows (for details see Appendix XI-5):
               Materials and Equipment:  The equipment purchase cost for all production facilities
               includes: gas flotation skid-mounted, complete electrical systems, oil and water outlets
               brought to the edge of the skid, and sufficient instrumentation for proper operation. The
               size of the equipment varies with flow and the cost of the equipment is the same as the
               design equipment cost for the Gulf of Mexico (see Section 3.2.2).
               Piping and Instrumentation: Piping and instrumentation costs were assumed to be 15 %
               of the equipment purchase cost.  This cost includes any additional valves, fittings, piping,
               cables, conduits, instrumentation, and instrumentation wiring (see Section 3.2.2).
               Geographic Area Multiplier: Because the equipment purchase costs represent Gulf of
               Mexico delivered equipment, a geographic area multiplier for Cook Inlet  of 2.0 was
               included.23
                                             XI-39

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                                                   XI-41

-------
               Installation Cost:  An installation factor of twice the equipment purchase cost was used
               for the shore-based facilities and a factor of 2.5 times the equipment capital cost was used
               for platforms.23
               Additional Costs (Engineering, Contingency, and Insurance-Bonding Fees): These
               fees were added to the equipment purchase and installation costs to develop actual capital
               costs. These fees include all engineering design costs (10%), administrative costs (4%),
               and any  incidental costs  incurred in  the process  of purchasing  and installing the
               equipment (15%).
               Platform Modification Cost:  The cost of additional platform space was calculated based
               on equipment area requirements and  a cost of $600 per square foot in the form of a
               cantilever deck.27
4.2.2   O&M Cost
       The annual operating and maintenance cost was estimated to be ten percent (10%) of the total
capital cost. Typically, the operating and maintenance costs include: labor, polymer and/or flocculation
enhancement chemicals, fuel cost, and equipment maintenance and replacement costs.  Estimated O&M
costs for each production facility in Cook Inlet that discharges produced water are presented in Table
XI-16.  Although the Trading Bay facility currently has gas flotation and therefore will not incur an
additional capital cost  for gas flotation, it will incur an additional O&M cost to comply with  stricter
effluent limitations based on unproved operations of gas flotation.  This cost was estimated to be  10%
of the cost of a new gas flotation system.23

4.3    TOTAL COOK INLET COMPLIANCE COSTS AND POLLUTANT REDUCTIONS
       The incremental pollutant removals associated with the treatment technologies were calculated as
the difference between the effluent  levels after treatment  by the technology options (injection, gas
flotation) and the level associated with a typical BPT treatment (gas flotation or gravity separation).  That
is, the pollutant removals were calculated by multiplying the annual average produced water flow rate
for each treatment option by the difference in pollutant concentration in BPT effluent and the additional
technology effluent concentrations.

       Table  XI-17 presents  the produced water pollutant loadings following BPT-level treatment and
improved gas flotation level treatment.  Total pollutant loadings represent the sum of individual  analyte
loading.  The values presented hi Table XI-17 were obtained from the produced  water characterization
data presented in Section VQL5.2.  Based on individual estimates, the total incremental costs and the
pollutant reductions for the two options considered to control discharges of produced water in Cook Inlet
                                             XI-42

-------
                                      TABLE XI-17
             POLLUTANT LOADING CHARACTERIZATION - PRODUCED WATER
                                      COOK INLET
Pollutant Groups
Conventional
Priority Organics
Priority Metals
Non-
Conventionals
Total Pollutants
Existing Sources 
-------
        The following sections present the analysis of each regulatory option for Cook Inlet, Texas, and
Louisiana combined.  No costs for the coastal industry located outside of these areas are incurred for
these options because they are currently meeting zero discharge (see Section IV).

5.1     BAT AND MS PS INCREMENTAL COMPLIANCE COSTS
        Table XI-1 presents the incremental compliance costs for the five regulatory options.   The
incremental compliance costs listed in Table XI-1 are equal to the capital and O&M costs for each given
technology option because they are add-on technologies.  For scenarios in which gas flotation systems
are already hi place (i.e., specific Cook Inlet platforms), the  incremental cost is only the O&M  cost
associated with improved operation  of existing technology.  Option 1 incurs zero incremental costs
because it sets all limitations equal to BPT.

        The incremental costs for NSPS are also  equal to the capital  and O&M  costs for  add-on
technology. No new sources are expected for Cook Inlet. Therefore, costs and pollutant reductions for
new source facilities are predicted only for the Gulf of Mexico.  Table XI-1 also presents the incremental
compliance costs for new sources for two regulatory options.

5.2    BAT AND NSPS POLLUTANT REMOVALS
        The incremental pollutant removals associated with existing and new source treatment technologies
were determined by comparing the effluent  levels after treatment by technology options (improved gas
flotation or injection) with the effluent levels associated with a typical BPT treatment (gas flotation or
gravity separation).

        Spreadsheets were developed to calculate pollutant removals for the five treatment options on a
regional basis using the average regional produced water flow and contaminant removal data. Existing
and new source facilities pollutant removal quantities for each option were calculated by multiplying the
annual average produced water flow rate for each region by the difference in pollutant concentrations in
BPT effluent and technology options  effluent concentrations.

        Pollutant removals were determined for each regulatory option considered and are presented in
Table XI-19 for existing and new source facilities.
                                             XI-44

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                                       TABLE XI-19
    ANNUAL REGIONALIZED POLLUTANT REMOVALS FOR EXISTING AND NEW SOURCE
                                       FACILITIES
                                          db/yr)


Option 1
Option 2
Conventionals
Priority Organics
Priority Metals
Other Non-Conventionals
Total
Option 3
Conventionals
Priority Organics
Priority Metals
Other Non-Conventionals
Total
Option 4
Conventionals
Priority Organics
Priority Metals
Other Non-Conventionals
Total
Option 5
Conventionals
Priority Organics
Priority Metals
Other Non-Conventionals
Total
Existing Sources \
<&ilf of Mexico
0

8,293,397
360,643
37,150
2,245,518
10,936,708

11,641,572
555,396
134,438
4,294,469,201
4,306,800,607

11,641,572
555,396
134;438
4,294,469,201
4,306,800,607

11,641,572
555,396
. 134,438
4,294,469,201
4,306,800,607
Cook Inlet
0

845,261
69,959
15,282
563,918
1,494,420

0
0
0
0
0

845,261
69,959
15,282
563,918
1,494,420

1,760,281
123,705
60,003
1,176,054,522
1,177,998,511
Total
0

9,138,658
430,602
52,432
2,809,436
12,431,128

11,641,572
555,396
134,438
4,293,658,243
4,305,989,648

12,486,832
625,355
149,720
4,295,033,119
4,308,295,026

13,401,853
679,101
194,441
5,470,523,723
5,484,799,118
NEW Sotttces
<5utf of Mexico
0

186,397
8,112
846
630,106
825,462

261,014
12,452
3,014
96,164,172
96,440,652

261,014
12,452
3,014
96,164,172
96,440,652

261,014
12,452
3,014
96,164,172
96,440,652
Cook Met
0

0
0
0
0
0

0
0
0
0
0

0
0
0
0
0

0
0
0
0
0
Total
0

186,397
8,112
846
630,106
825,462

261,014
12,452
3,014
96,164,172
96,440,652

261,014
12,452
3,014
96,164,172
96,440,652

261,014
12,452
3,014
96,164,172
96,440,652
6.0   BCT COST TEST
       The five options proposed for existing facilities were also evaluated according to the BCT cost
reasonableness tests.  The BCT cost test methodology for produced water is the same as that described
in Section X.6.1.  The pollutant parameters used in this analysis are total suspended solids (TSS) and oil
and grease.  Table XI-19 lists incremental costs and conventional pollutant removals for each regulatory
option.

       All of the produced water options considered for BCT regulation fail the BCT cost test except
                                          XI-45

-------
for the BCT option equal to BPT.  For Options 2 through 5, the ratio of cost of pollutant removal to
pounds of pollutant removed (POTW Test) exceeds the POTW benchmark of $0.534 per pound (the 1986
benchmark of $0.46 per pound adjusted to 1992 dollars). Table XI-20 presents the BCT Cost Test
Analysis.
                                      TABLE XI-20
                      PRODUCED WATER BCT COST TEST ANALYSIS
Option
Option 1
Option 2
Option 3
Option 4
Option 5
Conventional
Pollutant Removals
Obs/yr)
0
9,138,658
11,641,571
12,486,833
13,401,853
Annual BCT/BAT"
Costs <$/yr)2?
0
12,371,872
28,615,098
30,862,336
49,653,291
POTW Cost
Ratio ($/3b)
0
1.35
2.46
2.47
3.70
Pass POTW?
Yes
No
No
No
No
                                         XI-46

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7.0   REFERENCES
1.     Mclntyre, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Development of List
       of Coastal Produced Water Discharges in Louisiana and Texas, December 30, 1994.

2.     Sunda, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Produced Water Barging
       Assumptions, March 10, 1994.

3.     Sunda, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Factors  Affecting Cost
       of Produced Water Disposal at Commercial Facilities, March 1, 1994.

4.     SAIC,  "Produced Water Injection Cost Study for the Development of Coastal Oil and Gas
       Effluent Limitations Guidelines," January 27, 1995.

5.     U.S. EPA,  Development Document for Effluent Limitations Guidelines  and New  Source
      ' Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source
       Category, January 1993. (Offshore Rulemaking Record Volume 150)

6.     SAIC,  "Gulf of Mexico Coastal Oil and Gas:   Produced  Water Treatment Options  Cost
       Estimates,"  January 5, 1995.

7.     Energy Information Agency, "Water Treatment Technology Costs Associated with Offshore Oil
       and Gas Production," July 1992.

8.     Sunda, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding The 10 Miles Distance
       between  Facilities that Dispose of Produced Water  by Barging to Commercial  Facilities,
       April 22, 1994.

9.     Filtration Systems, Filtration Equipment Specifications and Costs, 1992.

10.    W-H-B Pumps, Inc., Pumps Specifications and Costs, January 10, 1994.

11.    Walk, Haydel & Associates, Inc., "Economic Impact of Restricted Produced Water Discharges
       in Louisiana," Feb. 1989.

12.    SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire (Final)," January 31, 1995.

13.    Sunda, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Injection Well Capacity,
       April 26, 1994.

14.    Sunda, J., SAIC, Telephone contact with Jeff Smith, EPA, regarding New and Converted Wells
       and AORs,  February 3, 1994.

15.    Kerr and Associates, Inc., "Review of Report Titled, 'Economic Impact of Restricted Produced
       Water Discharges in Louisiana [by Walk, Haydel],'" prepared for the Louisiana Department of
       Environmental Quality, September, 1990.
                                           XI-47

-------
16.    SAIC,  "Offshore Oil and Gas Industry - Analysis of the Cost and Pollutant Removal Estimates
       for the Final BCT, BAT, and NSPS Produced Water Treatment Options," January 13,  1993.
       (Offshore Rulernaking Record Volume 173)

17.    Erickson, M., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Cost Estimates for
       Produced Water Treatment by Granular Filtration in the Gulf of Mexico, January 4, 1995.

18.    Erickson, M.,  SAIC, Memorandum to Allison Wiedeman, EPA, regarding  NSPS Treatment
       Costs for Gulf of Mexico, January 9, 1995.

19.    SAIC, "Preliminary Statistical Analysis of Effluent from Coastal Oil and Gas Extraction Facilities
       (Final)," January 31, 1995.

20.    Mclntyre, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding "Annualized PW Zero
       Discharge Compliance Costs for Specific Groups of Discharges," November 8, 1994.

21.    Erickson, M., SAIC, Memorandum to Allison Wiedeman, EPA, regarding "Compliance Cost
       Estimates for Produced Water Injection for Facilities with Water Access hi Texas," December
       15, 1994.

22.    Hanchera, D., Marathon Oil Corp.,  Letter to  Erickson, M.,  SAIC,  regarding Production
       Activities Information for Platforms in Cook Inlet, April 12, 1994.

23.    Dawley,  J., SAIC,  Memorandum to Allison Wiedeman, EPA, regarding  Produced Water
       Treatment Options for Cook Inlet, June 27, 1994.

24.    U.S. EPA, Responses to the 1992 "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160,
       July 1993. (Confidential Business Information)

25.    Marathon Oil Co. and Unocal Corp., "Zero Discharge Analysis Trading Bay Production Facility,
       Cook Inlet, Alaska," March 1994.

26.    Wiedeman, A., EPA, "Draft Trip Report to Alaska  Cook Inlet and North Slope Oil and Gas
       Facilities, August 25-29, 1993," August 31, 1994.

27.    Schmidt,  R., Unocal Corp., Letter to Erickson, M.,  SAIC, regarding Drill Cuttings and Fluid
       Discharge Additional Information for Cook Inlet, April 21, 1994.

28.    Dawley, J., SAIC, Memorandum to Allison Wiedeman, EPA, regarding Technical Feasibility of
       Replacing Seawater with Produced Water for Waterflooding in Cook Inlet, June 21, 1994.

29.    ERG, "Cost Effectiveness Analysis of Proposed Effluent Limitations Guidelines and Standards
       for the Coastal Oil and Gas Industry (Draft)," October 4, 1994.

30.    Wiedeman, A.,  EPA,  Minutes  of the  Meeting  with  Alaska Oil and  Gas  Association,
       October 30, 1991.

31.    SAIC,  "Oil and Gas Exploration and Production Wastes Handling Methods hi Coastal Alaska,"
       January 6, 1995.
                                           XI-48

-------
32.    Sunda, J., SAIC, Telephone contact with Harris, Kenyo Services, regarding Truck Hauling of
       Produced Water, February 18, 1993.

33.    Wiedeman, A., EPA, "Trip Report to Campbell  Wells Landfarms and Transfer Stations in
       Louisiana," June 30, 1992.
                                            XI-49

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                                    SECTION XII
  COMPLIANCE COST AND POLLUTANT LOADING DETERMINATION-
      WELL TREATMENT, WORKOVER, AND COMPLETION  FLUIDS
1.0    INTRODUCTION
       This section presents the compliance costs and pollutant reductions for the regulatory options for
treatment and disposal of well treatment, workover, and completion (TWC) fluids.

2.0    OPTIONS CONSIDERED AND SUMMARY COSTS
       EPA has considered two options for the treatment of TWC fluids.  These are:
              Option 1:      Limit the discharges equal to the existing BPT requirements of 72 mg/1
                           daily maximum and 48 mg/1 monthly average for concentrations of oil
                           and grease, and include the requirement that no discharges are allowed
                           in fresh waters of Texas and Louisiana.
              Option 2:      Limit the discharges equal  to EPA's  preferred  option for  produced
                           waters.
       In this section, no costs or pollutant reductions are presented for Option 1 because it represents
no change from current limitations. Compliance costs and pollutant reductions for TWC fluids were
developed for Option 2 for the same two options that were developed for produced water: while EPA's
preferred option for produced waters is zero discharge everywhere except Cook Inlet, Alaska, where the
preferred produced water  control option is to meet limitations on oil and grease of 42 mg/1 daily
maximum and 29  mg/1 monthly average, costs were also developed for TWC  discharges following
commingling with  produced water and treatment by improved gas flotation.   For TWC fluids, these
options are referred to as Options 2a and 2b, respectively. As shown hi Section XI.2 for produced water,
discharges of TWC fluids under Option 2b would be required to meet limitations on oil and grease
content of 42 mg/1 daily maximum and 29 mg/1 monthly average.

       The cost and pollutant loadings analyses presented herein apply only to the Gulf of Mexico coastal
area.  For Cook Inlet operations, waste TWC fluids are currently commingled with produced water prior
                                         XH-1

-------
to treatment and/or disposal, and thus costs for their treatment and disposal are already included in the
costing of the produced water options.

       Table XH-1 presents the results of the compliance cost analyses  for Options 1, 2a, and 2b.
Detailed spreadsheets containing the calculation of these estimates are included in Appendix XH-1.

                                      TABLE XH-1
                TOTAL ANNUAL COMPLIANCE COST ESTIMATES FOR
                TREATMENT, WORKOVER, AND COMPLETION FLUIDS3
                                         (1992$)
                                  (from Appendix XEML)
Option
1: BPT limitations; zero
discharge to fresh
waters of TX and LA
2a: Zero discharge via
injection or
commercial disposal
2b: Discharge via
improved gas flotation
or commercial disposal
Fluid Type
All TWC Fluids
Workover/Treatment
Completion
Total
Workover/Treatment
Completion
Total
Existing Sources
$0
$449,344
$156,301
$605,645
$438,814
$152,724
$591,538
New Sotirces
$0
$57,773
$21,059
$78,831
$56,419
$20,577
$76,995
* These costs are based only on coastal Gulf of Mexico data.  Cook Inlet costs were determined to be zero for this analysis.

3.0   COMPLIANCE COST METHODOLOGY
       The following sections describe the assumptions, data and methodology used to develop the cost
estimates in Table XH-1.

3.1    GENERAL ASSUMPTIONS AND INPUT DATA
       The technology basis assumed in the development of compliance cost estimates for TWC fluids
is either commercial disposal or commingling of TWC fluids  with produced water for onsite treatment
and/or disposal.  A statistical analysis of the responses to the 1993  Coastal Oil and Gas Questionnaire
showed that 85% of the producing wells in the Gulf of Mexico coastal area that disposed of workover
                                          xn-2

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and/or treatment fluids in 1992 did so by  commingling  the  fluids with produced  water.1   Also,
commingling of TWC fluids is an existing technology in Cook Inlet, Alaska.2

       No additional capital expenses are included for handling TWC fluids under Options 2a and 2b.
It  is assumed that, since TWC operations are  occasional occurrences (rather than continuous), all
necessary tankage and equipment would be brought onsite at the time of the job as a matter of standard
operations, and would be removed at the conclusion of the job.  It is further assumed that, except in the
case of fluids that would be captured for reuse or separate disposal after the job (e.g., oil-based fluids),
TWC fluids can be left in the hole and brought up with the produced fluids when the well is brought back
on-line, thus  requiring no additional fluids management equipment to be purchased.3 Thus, costs for
                   *
onsite treatment and/or disposal  of TWC fluids are based on operating  and maintenance (O&M) costs
previously developed for produced water in Section XI.  Costs for offsite commercial disposal are based
on information obtained directly  from industry sources.

       Several assumptions regarding the profile of production operations in the Gulf of Mexico coastal
area were adopted from the produced water cost estimate analysis presented in Section XI and are listed
below.  In addition, per-well discharge volume data were obtained from a statistical analysis of the
responses to the 1993 Coastal Oil and Gas Questionnaire.1 These assumptions and data are also presented
below.
3.1.1    Assumptions  and  Input  Data  Derived from the Results of  the  1993  Coastal
         Questionnaire
       Annual Number of Existing Wells Discharging TWC Fluids:  As described in Section IX.2.1,
       the numbers of existing wells currently discharging workover/treatment fluids and completion
       fluids were derived from the 1993 Questionnaire results and state Discharge Monitoring Report
       (DMR) data. The survey results indicate that hi 1992, 219 wells discharged workover/treatment
       fluids and 209 wells discharged completion fluids.1  A comparison of the number of wells in the
       survey to the number of wells for which DMR data are available revealed that the survey count
       of wells must be increased by a factor of 1.6 for an accurate count of existing wells.4 Thus, the
       estimates of 219 wells discharging workover/treatment fluids  and  209 wells discharging
       completion fluids were increased to 350 and 334, respectively.
                                             XH-3

-------
   •    Annual Number of New Wells Discharging TWC Fluids:  The number of new wells discharging
        TWC fluids was derived from  1993 survey data.  The  survey results indicate that 187 new
        production wells were drilled in 1992.1  EPA determined that due to the existing prohibition of
        TWC fluid  discharges to fresh water areas imposed by the EPA Region VI general permit (58
        FR 49126), a proportion of the 187 new wells would not be affected by the proposed regulation.
        Data used to identify the population of coastal operators to be included in the 1993 survey were
        used to determine the proportion of new wells that would be located in fresh vs saline water
        areas. Table XII-2 lists the data and results of this analysis, and shows that approximately 76%
        of the wells in the coastal Gulf of Mexico region that were completed since 1990 are located in
        fresh water areas and 24% are located in saline water areas.   The calculation of the number of
        wells located in saline water areas, and hence subject to the proposed regulations,  is as follows:

           (187 wells discharging TWC fluids in 1992) x (24% saline water areas)  = 45 new source wells/year

                                         TABLE XH-2
         NUMBER OF WELLS LOCATED IN FRESH VS SALINE WATERS IN THE
                          COASTAL  GULF  OF MEXICO REGION1'3
Size of Operator
Major
Small Independent
Other
Total
-, s Wv J ^ f$* fff f
\ Freshwater Areas __,..
174
14
287
475
Saline Water Areas
65
2
80
147
* The values in this table are the sum-of the values in Tables 2, 6, and 7 in the source document, only for wells completed during
or after 1990.'
       Percentage of Land- vs Water-Access Facilities:   The data shown in Table IX-13 in Section
       DC.3.2  were obtained from the  responses to the 1993 Coastal Questionnaire.5  This table
       compares the number of responses to three survey questions that relate to facility location (i.e.,
       over water or land) by asking whether they are accessible via truck or barge.  Using these data,
       it was estimated that the percentage of water-access facilities is 65.6% and land-access facilities
       represent 34.4%. This assumption is used to distinguish which facilities will incur barge vs truck
       transportation costs for those facilities that must dispose of their TWC fluids commercially.
                                             xn-4

-------
  •   Average  Volume  of  TWC  Fluids  Discharged Per  Well:    The  annual  volumes  of
       workover/treatment fluids and completion fluids discharged per well were reported in Section
       IX.2.1 as being 587 bbls and 209 bbls, respectively.1

3.1.2   Assumptions Adopted from the Produced Water Cost Estimate Methodology

  •   Percentage  of Large vs Small  Facilities:   From the produced  water costing analysis,  two
       categories of facility size were developed, based on flow rate:  1) medium/large facilities that
       would employ onsite treatment technology, and 2) small facilities that would utilize commercial
       disposal.  The methodology for determining these categories is discussed in Section XI. For both
       the zero-discharge via injection option and the discharge via improved gas flotation option, there
       are 50 small and 166 medium/large facilities.  This translates to 23% small facilities and 77%
       medium/large facilities.  In both TWC fluid option cost analyses,  77% of the  identified
       discharging wells are assumed to utilize either injection (for Option 2a) or gas flotation (for
       Option 2b).  Likewise,  23% of the identified wells are assumed to utilize commercial disposal
       in both Options 2a and 2b.

  •   Costs to Inject TWC Fluids: These costs were calculated from the O&M costs and volumes that
       were developed for injection of produced water at medium/large facilities, as presented in Section
       XI, Table XI-11.  For water-access sites, the cost is $0.08/bbl, and for land-access sites, the cost
       is$0.15/bbl.

  •   Costs to Treat TWC Fluids with Gas Flotation: These costs were calculated from the O&M costs
       and volumes that were developed for gas flotation treatment of produced water at medium/large
       facilities,  as presented in Section XI, Table XI-12.  For water-access sites, the cost is $0.01/bbl,
       and for land-access sites, the cost is $0.09/bbl.

3.1.3   Additional Assumptions and Data

  •   Barge Capacity and Cost:  Water-access facilities  that were determined to utilize commercial
       disposal rather than onsite treatment and/or disposal were assumed to require a portion of a small-
       capacity (1,500 bbls) shale barge to transport the waste TWC fluids to a land-based commercial
       disposal facility.6 These shale barges are divided into four equivalent and separate sections.  The
                                             xn-s

-------
       cost for the use of a shale barge was derived by assuming that a portion of the barge would be
       dedicated to TWC fluids while other wastes would be transported in the remainder of the barge.
       Although it is recognized that TWC fluids would likely be mixed with other field wastes with
       comparable disposal costs,  such as spent drilling fluid, this approach reflects the fraction of the
       barge cost attributable to the TWC volumes. Each 587-bbl volume of workover\treatment fluid
       would require one-half of a  single barge's capacity  (750  bbls).  Each 209-bbl volume  of
       completion fluid would require one-fourth of a barge (375 bbls).  The transportation cost for a
       single barge and tug is $1,000 per round trip.6  Therefore, the costs for barge transportation are
       estimated to be $500 per job for workover/treatment fluids, and  $250 per job for completion
       fluids.
                     %

  •   Truck Capacity and Cost:   Land-access facilities that  were determined to utilize commercial
       disposal rather than onsite  treatment and/or disposal were assumed to require 120-bbl capacity
       vacuum trucks to transport the waste TWC fluids to a land-based commercial disposal facility.7
       The assumed cost for a vacuum truck is $1.75/bbl.7

  •   Commercial Disposal Cost for TWC Fluids:  The assumed cost for disposal of all TWC fluids
       is $8/bbl.8 This cost was obtained from a commercial disposal company for completion fluids8,
       and is applied to all TWC fluids based on the fact that completion and workover fluids are similar
       types of fluids  and typically weigh nine pounds  per gallon or more.

3.2   COMPLIANCE COST METHODOLOGY
       The spreadsheets in Appendix XTJ-1 were developed to calculate the compliance cost estimates
for existing and new sources of TWC fluids. For each option and for each source category (existing or
new), two spreadsheets were created:  one for workover/treatment fluids and one for completion fluids.
The input data (described  in Section 3.1) applicable to each scenario are listed in  each spreadsheet.
Within each spreadsheet, two costs were calculated:  treatment (either injection or gas flotation) costs at
medium/large-volume facilities, and commercial disposal costs at small-volume facilities. The treatment
costs, determined separately for water- and land-access  facilities, consist of the following calculations:

         •     Number of workover/treatment or completion jobs per year
         •     Number of jobs injected or treated by gas flotation per year
         •     Total volume treated per year
                                             xn-6

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         •     Treatment (injection or gas flotation) cost per year.

The commercial disposal costs,  also determined for water-  and land-access facilities, consist of the
following calculations:

         •     Number of workover/treatment or completion jobs per year
         •     Number of jobs disposed commercially per year
         •     Total volume disposed commercially per year
         •     Transportation cost per year
         •     Commercial disposal cost per year
         •     Total transportation and disposal cost per year.

The total costs presented in Table XII-1 are the sum of the costs presented in Appendix XII-1.

4.0   POLLUTANT  REDUCTIONS
       The following sections describe the assumptions, data and methodology used to develop these
pollutant reduction estimates.

4.1    GENERAL ASSUMPTIONS AND INPUT DATA
       The concentration data for TWC fluids produced water presented in Table IX-7  in Section
IX.2.2.3 are assumed to represent the characteristics of TWC fluids as they are currently discharged by
commingling.   Details  of the development of these data  are  provided in  Section IX.2.2.3.   The
concentration data for improved gas flotation presented in Table VHI-6 in Section VTJI.5.2.1  describing
produced water are assumed to represent the characteristics of TWC fluids following commingling and
treatment with produced water. These data are used here because no data are available for TWC fluids
treated by improved gas flotation.  Furthermore, it is assumed that TWC fluids that can be commingled
and treated without upsetting the treatment system have characteristics similar to produced water.

4.2   METHODOLOGY
       The spreadsheets in Appendix XH-2 were developed to calculate the pollutant reduction estimates
for existing and new sources of TWC fluids.  For each option and for each source category (existing or
new), two spreadsheets were created: one for workover/treatment fluids and one for completion fluids.
The annual volumes discharged, injected, treated, or disposed hi these spreadsheets are those calculated
                                            xn-7

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in the corresponding compliance cost spreadsheets in Appendix XII-1.

        The pollutant reductions due to the application of the zero-discharge option (Option 2a) are
equivalent to the loadings due to current practice.  As shown in the spreadsheets, the current-practice
concentrations were multiplied by the volumes currently discharged, and the reductions were calculated
by subtracting the treatment-level loadings (0 Ibs in this case) from the current-level loadings. Table XII-
3 presents the total TWC fluid loadings and reductions calculated for each source category (existing or
new) and for each option.  The loadings and reductions presented in Table XII-3 are the sum of the
reductions presented in Appendix XII-2.

        The pollutant reductions due to the application of the treat-and-discharge option (Option 2b) are
the difference between the current  loadings and  the loadings resulting from improved gas flotation
treatment. However, because it is assumed that 77% of the volume currently discharged will be treated
and discharged under this  option, while the remaining 23%  is commercially disposed,  the calculated
pollutant reductions reflect the complete removal of 23 % of the waste stream (i.e., a loading of 0 Ibs for
23% of the volume, as in the zero-discharge option).

5.0    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 and
treat-and-discharge options. The methodology for the BCT cost test is presented in Section X.6.1.

        The compliance costs and pollutant reductions presented hi Sections 3.0 and 4.0 are all considered
to be incremental to BPT-level  costs and reductions  because they were based  on costs and pollutant
characteristics that are additional or supplemental to BPT-level treatment.

        Table XII-4 presents the results of only the first part of the BCT cost test, the POTW cost ratio
test, because both Options 2a and 2b fail this test.
                                             xn-s

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-------
                 TABLE XII-4
              BCT COST TEST FOR
TREATMENT, WORKOVER, AND COMPLETIONS FLUIDS
Option
1: BPT limitations;
zero discharge to
fresh waters of TX
and LA
2a: Zero discharge via
injection or
commercial disposal
2b: Discharge via gas
flotation or
commercial disposal
Conventional
. PoButants
Removed
JlBbs/yr)
0
72,397
68,433
Compliance
Cost
($/yr)
0
605,645
591,538
POTWCost
Ratio ,
0
8.37
8.64
Pass?
(V7N)
Y
N
N
                   XH-10

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6.0   REFERENCES
1.     SAIC, "Statistical Analysis of the Coastal Oil and Gas Questionnaire," January 31, 1995.

2.     Wiedeman, Allison, U.S. EPA, "Trip Report to Alaska — Cook Inlet and North Slope Oil and
       Gas Facilities, August 25-29, 1993,". August 31, 1994.

3.     Wiedeman, Allison,  U.S. EPA,  Memorandum to  Marv  Rubin, U.S.  EPA, regarding
       "Supplementary Information to  the  1991  Rulemaking  on Treatment/Workover/Completion
       Fluids," December 10, 1992.

4.     Jones, Anne, ERG, Memorandum to Niel Patel, EPA, regarding "Estimates for Total Numbers
       of Coastal Wells, Operators, and  Production," September 26, 1994.

5.     EPA, Responses to the "Coastal Oil and Gas Questionnaire," OMB No. 2040-0160, July 1993.

6.     U.S. EPA. "Trip Report to UNOCAL, Intracoastal City,  Louisiana, September  8-9, 1993,"
       Freshwater Bayou, Vermilion Parish, Louisiana. January 25, 1995.

7.     U.S. EPA. "Sampling Trip Report to ARCO Oil and Gas Drill Site, Black Bayou Field, Sabine
       Wildlife Refuge, Lake Charles, Louisiana, July 21-22, 1993." October 21, 1994.

8.     Mclntyre, Jamie, SAIC, Communication with Kathy Cavalier, Campbell Wells, regarding waste
       disposal cost mformation, May 12, 1994.
                                          XH-11

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                                     SECTION XIII
           COST AND POLLUTANT LOADING DETERMINATION -
                                   DECK DRAINAGE
1.0   INTRODUCTION
       This section presents the compliance costs for the proposed regulatory options for treatment and
disposal of deck drainage. For coastal operations in the Gulf of Mexico, EPA investigated deck drainage
from drilling operations and production operations as two separate types of sources. This was due to the
fact that Gulf Coast drilling and production operations can be two separate and distinct activities which
may generate different volumes and have characteristically different pollutant contamination (e.g., only
drilling operations experience contamination with drilling fluids). For Cook Inlet, however, drilling and
production can occur simultaneously, therefore producing a combined deck drainage source as discussed
later hi this section.

2.0   OPTIONS CONSIDERED AND COSTS
       The  technology option considered for deck drainage was the capture of the first 500 bbls of a
storm event, referred to as the "first flush", and setting the limitation for this volume equal to those for
the major wastestreams that it can be commingled with.  The two treatment and disposal technologies
considered for the commingled deck drainage are zero discharge and unproved gas flotation.  The deck
drainage volume that exceeds the 500 bbl volume would be subject to the current BPT limitation for deck
drainage.  The options are defined as follows:

Option 1)     Discharge limitation is equal to the current BPT limitation requiring "no discharge of free
              oil."

Option 2)     Capture of the  first 500 bbls of deck drainage during a storm event. For production
              operations,  the technology  basis is commingling the captured deck drainage with
              produced water for treatment and disposal.  For drilling operations, the captured deck
                                           xra-i

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               drainage is subject to a zero discharge limitation because this is the preferred option for
               drilling waste.

       Since two options were considered for produced water disposal at production facilities, Option 2
is further divided into the following options:

       Option 2a)     Commingling  of  the  first  flush volume with produced water followed by
                      treatment and disposal by zero discharge.  Zero discharge is accomplished by
                      onsite subsurface injection or offsite commercial disposal.

       Option 2b)     Commingling  of  the  first  flush volume with produced water followed by
                      treatment and disposal by improved gas flotation and surface discharge.

       In both cases, zero discharge would be required for the first flush for drilling operations.

       Table Xffl-1 presents a summary of the compliance cost estimates for the options considered.
The methodology used to derive these cost estimates is presented hi the following sections.

3.0   COMPLIANCE COST CALCULATIONS FOR PRODUCTION OPERATIONS - GULF
       OF MEXICO
       The average amount of deck drainage from the facilities that reported deck drainage in the 1993
Coastal Questionnaire is used to determine costs for this waste stream.  Capital and O&M costs for an
average size facility are developed for each disposal category (identified by type of location and disposal
method) based on this average flow. The number of facilities that fall into each disposal category are
then multiplied by the average facility cost.

       Compliance costs  for Options 2a and 2b are based on the average volume of deck drainage
reported  in  the  1993 Coastal Oil and Gas Questionnaire and  the  estimated number of production
facilities.1 Disposal costs  are based on the commingling of the deck drainage with produced water for
treatment and disposal.  In the compliance costs analysis for produced water, the production facilities
were separated into land-access and water-access facilities.  The same approach was used for  deck
drainage  because of the commingling of deck drainage with produced water.  Appendix Xni-I presents
the detailed compliance cost calculations for capital and O&M costs.
                                            xra-2

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          xin-s

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       Tables Xm-2 and XQI-3 provide the total estimated costs for zero discharge of the first flush and
surface discharge via gas flotation at the estimated 853 production facilities in the Gulf of Mexico region.
All facilities that were estimated to be hi service in 19922 are assumed to generate deck drainage, whether
or not produced water is discharged. (Note: As discussed in Section XI, 216 out of 853 production
facilties are estimated to be affected by produced water requirements, because all  other facilities are
currently not discharging produced waters.  However, the 853 facilities are not required to meet zero
discharge for deck drainage.) The capital costs are the same for both Options 2a and 2b because these
costs are associated only with the deck drainage collection and storage equipment. No capital costs were

                                    TABLE Xin-2
ANNUAL COST FOR GULF OF MEXICO PRODUCTION OPERATIONS DECK DRAINAGE
     OPTION 2B:  DISCHARGE OF FIRST FLUSH BY IMPROVED GAS FLOTATION
Access Ttyffi "

Land
Land
Water
Water
Total
', SMsposaJ %"$E«s
•"'".. < ; - ^
. . ? 1 f •:•':•.
Flotation
Commercial
Flotation
Commercial

J&lifeitOMft
-»XiPBrMc5iity?

$59,124
$59,124
$74,979
$74,979

t*&M,€pt,
Pec Ikejliiy*

$1,121
$18,614
$224
$18,277

$a*nb*r «t
' liacaafei^

181.9
67.5
346.8
128.7
724.9
ft', '
Ifetat Capltai
Cost

$10,753,699
$3,990,241
$26,006,333
$9,649,845
$50,400,119
IbfetTAasaai
tJ&M Cost ,

$203,892
$1,256,247
$77,694
$2,352,262
$3,890,094
      See Appendix Xm-1
      See Table XHI-4
                                    TABLE Xffl-3
ANNUAL COST FOR GULF OF MEXICO PRODUCTION OPERATIONS DECK DRAINAGE
     OPTION 2B:  DISCHARGE OF FIRST FLUSH BY IMPROVED GAS FLOTATION
Access *S$&
Land
Land
Water
Water
i "-; \ ' » -x.x
BBgOSatType
X * w ,
\-? '^^ ,'*
Flotation
Commercial
Flotation
Commercial
s ••*
Capitol Cast
?&$&&%$*•
$59,124
$59,124
$74,979
$74,979
G&MCost
$rfto8tf;
$1,121
$18,614
$224
$18,277
Total
: Number of :
i ^aiplpes'' !
181.9
67.5
346.8
128.7
724.9
Total Capital "
Cfl^ ' „
$10,753,699
$3,990,241
$26,006,333
$9,649,845
$50,400,119
T«ta! Annual
-O^M Oust
$203,892
$1,256,247
$77,694
$2,352,262
$3,890,094
      See Appendix Xm-1
      See Table Xffl-4
                                       xra-4

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included for treatment and disposal because the annual deck drainage volume is only 1.5 to 1.7 percent
of the average facility annual produced water volume (see Section IX.3.2.2).  O&M costs for treatment
and disposal were included and were based on the average O&M costs for produced water at land-access
and water-access facilities. The following sections describe the assumptions, data, and methodology used
to calculate these cost estimates.

3.1     NUMBER OF FACILITIES IN EACH COSTING CATEGORY
        As noted in Section IX.3.2.1, EPA estimates that 19.5 percent of the production operations in
the  Gulf of Mexico region commingle deck drainage with produced water for disposal by subsurface
injection.  Therefore, it is assumed that 19.5 percent of the facilities that currently inject produced water
already commingle deck drainage and will not  incur any cost under the zero discharge option.

        This 19.5 % is applied equally to both land-based and water-based facilities and applies to facilities
that are projected to install an injection system for produced water to meet the produced water zero
discharge  option (i.e., "medium/large" facilities, as described in Section XI).  Table Xffl-4 shows  the
estimated number of facilities by disposal category and the factors used to develop these numbers.

3.2    ASSUMPTIONS FOR PRODUCTION FACILITIES
        •       The average annual volume  of deck drainage in 1992  was 11,644 bbls per production
               facility.3  The New Orleans area received approximately 80 inches of rainfall in 1992.4
               The equivalent surface area needed to generate 11,644  bbls of rainwater at 80 inches is
               9,807 sq ft which is assumed to be the average size of a facility.   This is roughly
               equivalent to the surface area of the Texaco tank battery at Port Neches which measured
               90 ft x 100 ft  (9,000 sq ft) and generated 210 bpd (76,650 bpy) of oil and 4,000 bpd
               (1,460,000 bpy) of produced water.5 This volume is roughly equivalent to the estimated
               average oil production per facility of 237 bpd (86,483 bpy) and 245 bpd (89,492 bpy)
               for  facilities that inject and surface discharge  produced  water,  respectively.3  The
               produced water volume is equivalent to 2.08 and 1.93 tunes the estimated average water
               production per facility for facilities that inject and surface discharge produced water,
               respectively. Therefore, the average volume of 11,644  bpy appears to be consistent with
               field observations.
                                             xni-5

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                                        TABLE XIH-4
                 ESTIMATED NUMBER OF COASTAL GULF OF MEXICO
                  PRODUCTION FACILITIES BY DISPOSAL CATEGORY
Tjpeof
J&silitj
Land
jUnd"
Land
Water
Water"
Water
Erojx>se*I
»eck;0rr
DJsgiOSfcir ^
Injection
llpCtSHt, * \
Commercial
Injection
Injeetjoa, v, I
Commercial
« # 3*,4 !
34.4
65.6
, ss,g :
65.6
3?«t««Kt
lajectioa ys.
C«nHnetcial
-------
       •       The only treatment chemical used will be an oxygen scavenger at a cost of $0.01/bbl,
               based on an oxygen scavenger cost of $9.00/gal and a dosage rate of 1.0 gal/1,000 bbl.6
               The oxygen scavenger cost will not be added to the O&M cost for commercial disposal
               because this treatment is only needed when deck drainage is mixed with produced water
               which will occur during and after transport to the commercial facility. Therefore, the
               oxygen scavenger cost is assumed to be already included in the commercial disposal cost.

       •       Commercial disposal cost is $1.63/bbl for water-based  facilities and $1.66/bbl for land-
               based facilities (Section XI.3.1.2).

       •       Two 200 gpm pumps will be needed for the average facility. One of these pumps alone
               is capable of pumping two inches of rainfall per hour for the average size facility (9,806
               sq ft).  The foot print of these two pumps is assumed to be 50 sq ft.

3.3    ESTIMATION OF THE FIRST FLUSH CAPTURE VOLUME
       Capturing the first 500 bbls of deck drainage will require the capture of the first 3.5 inches of
rainfall during a storm event for an average size facility (9,806 sq. ft.) (see Section IX  3.2.2).  The
Regional Climate Center provided the following rainfall data:7

       •       For a 24 hour duration and a return  period" of one year, the maximum rainfall depth
               ranges  from  3.75 inches  for  northwestern  Louisiana to 5.0  inches  in southeastern
               Louisiana.

       •       For a 24 hour duration and a return period1 of two years, the maximum rainfall depth
               ranges  from  4.5  inches for Northwestern Louisiana to greater than 6.0 niches in
               southeastern Louisiana.

       This means that a 3.5 inch rainfall depth will probably be exceeded at least once per year hi
southern Louisiana and at most two to three tunes.  In Texas, which receives less rainfall than Louisiana
(e.g.,  Galveston, Texas receives 42.9  niches annually, compared to 53.7 inches for New  Orleans,
Louisiana8), the frequency of exceeding  3.5 inches of rainfall in a 24 hour period will be even less.
    aA "return period" is the frequency (period between occurrences) at which a storm of a given intensity
will occur.
                                             xin-7

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        As a result of this requirement to catch only the first 3.5 inches, there will be some deck drainage
discharge during severe storm events, particularly at facilities that are greater in area than the average
facility.  A simplified method to estimate this volume is to assume that the depth of 3.5 inches will be
exceeded only once per year and to assume that the exceedence depth is the average of the maximum 24-
hour storms for the one and two year return periods from the area of the Gulf Coast with the greatest
rainfall,  Southeastern Louisiana.  These rainfall depths are 6 inches for a one year return period and 5
inches for a two year return period.7  Using these rainfall  depths for the entire Gulf Coast  should
compensate for the possible volume discharged from a second or third storm to exceed 3.5 inches. This
method results hi the following calculated depth of rainfall discharged:

       Annual Depth of Rainfall Discharged per year = ((6 in. + 5 in.)/ 2) - 3.5 in. = 2.0 inches per year

       Therefore, using the conservative assumption that the average annual rainfall received in  the
region is the same as that for New Orleans, Louisiana (53.7 niches), the volume discharged will be  2.0
inches out of 53.7 inches or 3.7%.  Therefore, since the predominant source of deck drainage is rainfall,
the average volume of deck drainage captured  is 11,213 bpy (11,644 x 0.963).  The  total volume
generated by all 853 production facilities is therefore estimated to be 9,932,332 bpy and the total volume
captured under Options 2a and 2b is estimated to be 9,564,689 bpy. Of this volume, EPA estimates that
80.5 percent is currently being  discharged (see Section XIH.3.2).  This results in an estimated volume
discharged of 7,995,527 bpy. The volume not captured under Options 2a and 2b that would be subject
to the BPT limitations is 295,953 bbls.

3.4   CAPITAL COST ESTIMATE
       Capital costs are based  on  the installation of a 500 bbl storage tank and two centrifugal pumps
with a capacity of up to 200 gpm. The data for tank and platform costs, as  well as tank dimensions were
obtained from the produced water  cost analysis for the Gulf of Mexico (Section XI.3.2).  The cost  for
the centrifugal pumps was obtained from a vendor (Sunda, October 1994) .9  The only difference between
facilities is that the additional platform space cost is  $40/sq.ft. for land-based facilities and $75/sq.ft.
for water-based facilities.  Capital costs are presented in detail in Appendix XTJI-1.

3.5   DETERMINATION OF ONSITE INJECTION VERSUS COMMERCIAL DISPOSAL
       As described hi Section XI.3, for water-based facilities, the produced water cost analysis used
a threshold flowrate of 108.5 bpd as the point at which, as the flowrate increases, it becomes economical
                                             xm-8

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to inject onsite.  In the produced water cost analysis in Section XI, Table XI-11 shows that 23% of the
facilities (50 out of 216) surface discharging produced water were costed for commercial disposal. In
order to be consistent with cost estimates for other wastes, the 23% value will be used in this analysis.
This factor was used for both options 2a and 2b.

4.0   COMPLIANCE COST CALCULATIONS FOR DRILLING OPERATIONS - GULF OF
       MEXICO
       The 1993 Coastal Oil and Gas Questionnaire asked questions separately for new production,
exploratory, recompletion, "other" and service wells.  Responses for new production and exploratory
wells were grouped together in this analysis because of their similarities.  Responses for sidetracks of
existing wells (reported as "other" wells) were also grouped with responses for recompletion because of
similarities. All of the equipment to be used for zero discharge of deck drainage at drilling operations
in the Gulf Region is assumed to be rented.  Therefore, no capital costs will be incurred; rental costs for
the equipment (pumps and tanks/barges)  are included in the O&M costs.

       Table Xffl-5 presents the estimated total deck drainage volumes and costs of zero discharge of
the 500 bbl first flush, assuming that the current disposal practice is  surface discharge for all drilling
operations.  A review of the land-based drilling operations that reported deck drainage in the 1993
Coastal Questionnaire found none that reported surface discharge.2 The methods of disposal reported
were commercial disposal and annular injection.  For water-based drilling operations, the majority of the
deck drainage reported was  surface discharged.3  Therefore, the estimated compliance costs for  zero
discharge of deck drainage is somewhere between the total cost for water-based operations of $759,528
and  the total cost  of $1,685,615 for both water- and land-based operations.  The following sections
describe the assumptions, data, and methodology used to calculate these cost estimates.

4.1    ESTIMATING  THE VOLUME OF DECK DRAINAGE CAPTURED
       Considering the small surface area and deck drainage volumes associated with water-based drilling
operations, it is assumed that the first flush volume of 500 bbls will not be exceeded at any time, except
under extreme circumstances, and that the volume disposed under zero discharge for Option 2a is equal
to the volume generated.  For land-based drilling operations, the volume of 500 bbls is expected to be
exceeded on numerous occasions because land-based operations cover a much  greater area  and  thus
generate higher volumes of deck drainage.  For a drilling operation with a surface area of 122,500 sq
ft (see Section IX.3.2.3.5), the depth of rainfall that would generate 500 bbls of area runoff is only 0.275
                                            xm-9

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         xra-io

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inches.  Appendix XHI-2 presents daily rainfall data for New Orleans for the year of 1993.w The total
of 52.7 inches for this year is within 2% of the average annual rainfall of 53.7 inches in New Orleans
and therefore is considered representative of a typical year.  As discussed hi Section IX, new and
exploratory wells take an average of 30 days to drill and recompletions take 15 days. Appendix XJJI-2
shows  the volumes  of deck drainage generated, the volume captured, and the remainder that can be
discharged if it meets BPT and local requirements. These volumes are based on a land-based surface area
of 122,500 sq ft.  The captured volumes are subject to the zero discharge requirements and will be either
reused in the drilling process or disposed by transporting it to an offsite commercial disposal  facility.
The deck  drainage can also be annularly injected, however, EPA did not include this option hi this
analysis.

4.2    ASSUMPTIONS FOR LAND-BASED DRILLING OPERATIONS
       The assumptions  and data sources for developing the compliance costs for land-based drilling
operations are presented below.  The assumptions used in developing the deck drainage volumes and the
calculations of the cost estimates are presented hi Appendix XIII-1.

       •       Trucking to a commercial disposal facility will be the disposal method.  The cost will be
               $1.75/bbl for trucking and $2.00/bbl for disposal, for a total of $3.75/bbl.1U2

       •       One 500 bbl frac tank will be rented to provide storage for the 500 bbl first  flush at
               $75/tank per day. In addition a  pump will be rented for $50/day to be used to  transfer
               rain water to the tank.11

4.3    ASSUMPTIONS FOR WATER-BASED DRILLING OPERATIONS
       The assumptions  and data sources for developing the compliance costs for water-based "new
production well"  drilling operations are presented  below.   The calculations of the cost  estimates are
presented in Appendix XQI-1.

        •       Deck drainage will be collected in shale  barges and will be included  in the disposal
               volumes for muds and cuttings.

        •       Onsite storage and barging to a commercial facility will be the disposal method.  The
               rainwater will be stored hi a  compartment of a shale barge.  The daily cost  for storage
                                            xra-ii

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               will  be one-quarter the cost of a  1,500 bbl  shale barge  (i.e.,  one  of the four
               compartments in the shale barge).  The estimated deck drainage volume of 516 bbls and
               567 bbls per well for newly drilled wells and recompletions, respectively, is assumed to
               be collected by two barges over the course of the drilling operation, with one replacing
               the other.  A typical 1,500-bbl shale barge has four compartments.13 Thus, the average
               per-barge deck drainage volume of 258 bbls and 284 bbls for newly drilled wells and
               recompletions, respectively, will fill most of the 375 bbl capacity of one compartment.
               The  rental cost is  $150.00/day and will be assumed to be  incurred  for  30 days.
               Transportation costs are assumed to  be one fourth the cost of two trips which was
               reported to be  $l,000/trip.13  The disposal cost will be $2.00/bbl.12

5.0    COOK INLET
        Operations in Cook Inlet occur on deep water platforms where drilling and production can occur
simultaneously. Thus, deck drainage from these platforms can include drainage from both drilling and
production operations,  and is therefore, addressed in this section as a single combined source.

        As noted in Section IX, four platforms in  Cook Inlet treat and surface discharge deck drainage
at the platform independently from the produced water which is piped to shore-based treatment facilities.
An additional five platforms commingle deck drainage with produced water for treatment and disposal
at the platform. The remaining platforms commingle deck drainage with produced fluids which is then
piped to shore-based treatment facilities.  Since deck drainage is commingled with produced water at all
but four of the platforms, commingling is consisered to be technologically feasible to perform at all
platforms provided that the equipment is sized accordingly.  In the development of equipment costs for
the produced water BAT options for zero discharge and improved gas flotation presented in Section XI,
enough excess capacity has been included to accommodate deck drainage without additional capital costs.
Since all but four of the platforms already include piping arrangements to allow commingling of deck
drainage with produced fluids, no capital costs will be incurred by those facilities.  For the four platforms
that do not commingle deck drainage, it is assumed that the piping costs will be similar to the piping costs
for the installation  of gas flotation  systems installed at a platform.   The  average piping  and
instrumentation costs was $19,516 for the four platforms where gas flotation was costed (see Appendix
IX-17).  This value was rounded up to $20,000 for this estimate.
                                            xra-12

-------
       Tables Xffl-6 and XHI-7 present the capital and O&M costs for Options 2a and 2b, respectively.
Annual O&M costs were estimated by dividing the produced water O&M costs  for each platform or
shore-based facility by the produced water flowrate to get the unit per-barrel cost. The unit per-barrel
cost was then multiplied by the estimated deck drainage flowrates from Table IX-17. Tables XIII-6 and
XIII-7 also show the capital cost  design flowrate  of the produced water equipment indicating that the
equipment was designed to  included the deck drainage flow volume.

6.0   POLLUTANT REMOVAL CALCULATION METHODOLOGY
       The pollutant removal estimates are based on the estimated volumes of deck drainage discharged
and the first flush volumes captured and commingled with produced water.  For the Gulf of Mexico
production operations  and  Cook Inlet platforms, pollutant loading  and reduction calculations were
performed  for three separate scenarios:  discharge  under current  BPT limitations  (Option  1);  zero
discharge of the first flush (Option 2a)  and; improved gas flotation treatment and  discharge of the first
flush (Option 2b).  For the Gulf of Mexico drilling operations, Options 2a and 2b  are the same because
zero discharge is the only applicable option considered for drilling wastes.  Tables XQI-8 and XE-9
present the estimated total pollutant loadings and reductions, respectively, for Options 1, 2a and 2b for
the Gulf of Mexico and Cook Inlet deck drainage sources.  Deck drainage characteristics are presented
in Table IX-19, and loadings and reductions are calculated from these  concentrations.  The detailed
pollutant loading and reduction tables showing individual pollutant removals for each option  and  each
source are presented in Appendix Xm-3.

       The pollutant concentrations used hi the analyses were obtained from two sources.  Data from
the Three Facility Study used in support of the offshore rule, which are shown in Table IX-19, were used
to represent deck drainage discharged under the current BPT limitations and are considered representative
of settling treatment effluent. These data were reported as ranges of maximum and minimum  observed
values, and thus, the pollutant loading and reduction estimates in Tables XEI-8 and Xffl-9 are reported
as ranges.   The second source of data was the  calculated effluent concentrations for unproved gas
flotation presented in Table "VTfl-6. These data were used to estimate the capability of gas flotation to
remove pollutants from commingled produced water and deck drainage.  In calculations for compliance
with Option 2b which involved both data sources, only the pollutants that are present in both data sources
were used.  Thus, the pollutant loading and reduction estimates for Option 2b include fewer pollutants
in the total than Option 2a.
                                            xm-13

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-------
        In calculating the pollutant loadings where a portion of the deck drainage volume exceeds the first
flush volume, the appropriate concentration (e.g., improved gas flotation data for Option 2b) was applied
to the first flush volume and the settling effluent  (BPT level) concentration was applied to the excess
volume.  These two  values  were then summed together.   Where the gas flotation (Option 2b)
concentrations  exceeded  either the  mmimum or  maximum settling concentrations, the  settling
concentrations were used  to develop the loadings.  This was done to eliminate the appearance of an
increase in pollutant loadings as the result of improved treatment.  The pollutant loadings are calculated
by multiplying the volume discharged  by  the pollutant concentration associated with the treatment
technology, times unit conversion factors.
                    %
7.0    BCT COST TEST
        The options proposed for existing facilities were also evaluated using the BCT cost reasonableness
test. The BCT  cost test methodology is the same as that described in Section X.6.1.  The pollutant
parameters used in this analysis are the conventional pollutants; total suspended solids (TSS) and oil and
grease.  Table Xm-9 lists the  total pollutant removal ranges for these conventional pollutants for each
regulatory option.

        Table XHt-10 presents the results  of  the BCT  cost test.  All of the deck drainage options
considered for BCT regulation fail the BCT cost test except for the BCT  option equal to BPT.  For
Options 2a and 2b, the ratio of the cost of pollutant removal to pounds of pollutants removed (the POTW
Test) exceeds the POTW benchmark of $0.534 per pound pollutant removed (the 1986 benchmark of
$0.46 per pound adjusted to 1992 dollars). This is true even for the scenario where  the maximum
concentration (taken from the  ranges calculated in the previous section) is assumed for BPT  effluent.
Since the  considered options failed the first POTW test, the Industry Cost-Effectiveness Test was not
performed.
                                            xm-is

-------
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-------
8.0    REFERENCES
1.     Jones, A., ERG, Memorandum to Neil Patel, EPA, Regarding estimates for total number of
       coastal wells, operators and production. September 26, 1994.

2.     U.S. EPA, Responses to the "1992 Coastal Oil and Gas Survey," July 1993.

4.     ERG, "Cost-Effectiveness Analysis of Proposed Effluent Limitations Guidelines and Standards
       for the Coastal Oil and Gas Industry. November 11, 1994.

3.     SAIC,  "Statistical Analysis of the Coastal Oil and Gas Questionnaire. Draft Final Report."
       September 30, 1994.

5.     SAIC. Trip Report:  Texaco, Inc., Port Neches, Texas. September 15, 1993.

6.     SAIC,  "Produced Water Injection Cost Study for the Development of Coastal Oil and Gas
       Effluent Limitations Guidelines." (Draft) January 20, 1995.

7.     Faires, G., Southern Regional Climate Center. Telephone Contact Report. J. Sunda to G. Faires
       regarding Frequency of Storm Events in Southern Louisiana.  June 21, 1994.

8.     Miller. A., and Thompson. J.. Elements of Meteorology. 2nd. Ed. Charles E. Merrill Publishing
       Company. Columbus, Ohio. 1975.

9.     Moores Pumps and Supply, Telephone Contact Report. John Sunda to Mike Foreman regarding
       cost of 100 to 200 gpm centrifugal pumps. October 13,  1994.

10.    Britton, S., Louisiana Office of State Climatology, Louisiana State University, Facsimile to J.
       Sunda, regarding daily precipitation data for New Orleans, Lake Charles and Galveston for 1993
       and 1994 plus normal means and extremes. October  18,1994

11.    SAIC, "Sampling Trip Report: Drilling Operations, ARCO, Black Bayou Prospect, Cameron
       Parish, Louisiana." (Draft) August 8, 1994.

12.    U.S.EPA, "Trip Report to Campbell Wells Landfarms and Transfer Stations in Louisiana. May
       12 and 13, 1992." Allison Wiedeman, Project Officer, June 30, 1992.

13.    SAIC, "Sampling Trip Report: Drilling Operations,  UNOCAL, Freshwater Bayou, Vermillion
       Parish, Louisiana." (Draft) August 5, 1994.
                                          xm-20

-------
                                        SECTION
                                            XIV
         OPTIONS SELECTION:  RATIONALE AND TOTAL COSTS
1.0   INTRODUCTION
       This section presents the options EPA has selected for control of the coastal oil and gas
wastestreams.  A discussion of the reasons why the options were chosen, and the total costs of this
proposed rulemaking is also included hi this section.

2.0   SUMMARY  OF OPTIONS SELECTED AND COSTS
       Under this rule, EPA is co-proposing three options for the control of drilling fluids and cuttings
(including any effluent from dewatering pit closures activities) for BAT effluent limitations guidelines,
and NSPS. The three  options considered contain zero discharge for all areas, except two of the options
contain allowable discharges for Cook Inlet. One of these options, which would allow discharges meeting
a more stringent toxicity limitation if selected for the final rule, would require an additional notice for
public comment since  the specific toxicity limitation has not been determined at this time.  The three
options are: Option 1 - zero discharge of all areas except Cook Inlet where discharge limitations require
toxicity of no less than 30,000 pm (SPP), no discharge of free oil and diesel oil and no more than 1 mg/1
mercury and 3 mg/1 cadmium in the stock barite, Option 2 - zero discharge for all areas except for Cook
Inlet where discharge  limitations would be the same as Option 1, except toxicity would be set to meet
a limitation between 100,000 ppm (SPP) and 1 million pm (SPP), and Option 3 - zero discharge for all
areas. EPA is proposing PSES and PSNS prohibiting all discharges of drilling fluids and drill cuttings.
BCT for drilling fluids and cuttings is being proposed as zero discharge for the entire subcategory except
for Cook Inlet, Alaska. BCT limitations for drilling fluids and cuttings for Cook Inlet would require no
discharge of free oil (as determined by the static sheen test).

       EPA is proposing to prohibit discharges of produced water from all coastal subcategory operations
except those located hi Cook Inlet, Alaska, under BAT.  Proposed BAT for coastal facilities in Cook Inlet
would limit the discharge of oil and grease in produced water to a daily maximum of 42 mg/1 and a thirty
day average of 29 mg/1.  EPA is proposing to prohibit discharges of produced water from all coastal
                                           XIV-1

-------
subcategory operations under NSPS, PSNS, and PSES.  BCT limits for produced waters in all coastal
regions (including Cook Inlet) would be set equal to the current BPT limitations, which limit the
discharge of oil and grease to a daily maximum of 72 mg/1 and a thirty day average of 48 mg/1.

       BCT for treatment, workover and completion fluids is proposed to be set equal to current BPT
limits prohibiting discharges of free oil, with compliance to be determined by use of the static sheen test.
EPA is co-proposing two options for BAT and NSPS limitations for treatment, workover and completion
fluids. Option 1 would require no discharge of free oil and prohibit discharges to freshwaters of Texas
and Louisiana. This option reflects current practice.  Option 2 would require the same limitations as the
preferred option for produced water.  This option would require for BAT that discharges of treatment,
workover and completion fluids would be prohibited in all coastal areas except Cook Inlet.  In Cook Inlet,
these discharges  would be required to meet a daily maximum oil and grease limitation of 42 mg/1 and a
30 day average of 29 mg/1. Option 2 would require zero discharge of these fluids everywhere for NSPS.
EPA proposes zero discharge as PSES, and PSNS for treatment, workover and completion fluids.

       BPT, BCT, BAT, NSPS, PSES, and PSNS are being proposed for produced sand and would
prohibit all discharges of this wastestream.  The only BPT effluent limitations guidelines being proposed
today are for produced sand which is the only wastestream for which BPT limits have not been previously
promulgated.

       BCT, BAT, and NSPS limits being proposed for deck drainage would be set equal to current BPT
limits prohibiting discharges of free oil, with compliance to be determined by use of the visual sheen test.
EPA is proposing zero discharge for PSES and PSNS for deck drainage because collection and capture
of this wastestream is technically unpractical in many situations such that its direction to POTWs would
rarely, if ever,  occur.   EPA also believes that combining this wastestream with municipal treatment
facilities that may already be at full capacity should not be encouraged.

       BCT is being proposed for domestic wastes as equal to BPT (which is no discharge of floating
solids) with an additional requirement prohibiting the discharge of garbage.  BAT is being proposed for
domestic wastes  to prohibit discharge of foam.  NSPS is being proposed for domestic wastes as equal to
BCT and no discharge of foam and no discharge  of garbage.  No pretreatment  standards are being
established for domestic wastes.
                                            XIV-2

-------
       BCT and NSPS limitations for sanitary wastes are being proposed as equal to the current BPT
effluent limitations guidelines. Sanitary waste effluents from facilities continuously manned by ten (10)
or more persons would contain a minimum residual chlorine content of 1 mg/1, with the chlorine level
maintained as close to this concentration as possible.  Coastal facilities continuously manned by nine or
fewer persons or only intermittently manned by any number of persons must comply with a prohibition
on the discharge of floating solids. BAT is not being developed for sanitary wastes because no toxic or
nonconventional pollutants of concern have been identified in this waste stream.   No pretreatment
standards are being established for sanitary wastes.

       These options and their costs are presented in Table XIV-1.  Annualized costs (for O&M and
capital costs  combined) are also presented here.  The derivation of annualized cost is presented in a
separate document prepared for this proposal entitled Economic Impact Analysis of Proposed Effluent
Limitations Guidelines and Standards for the Coastal Oil & Gas Industry.1

       The limitations proposed under each option for all wastestreams are presented,  by effluent
guideline level, in Table XIV-2 through XTV-7.

3.0   OPTION SELECTION RATIONALE
3.1    DRILLING FLUIDS AND CUTTINGS
3.1.1    BAT and NSPS
       EPA has not selected a preferred option  for control of drilling fluids and drill cuttings under
BAT and NSPS but, rather is co-proposing all three  options. EPA  has determined, based on available
information, that all three  options are technologically and economically achievable and have acceptable
non-water quality impacts.  However, due to possible operational interferences (for Option 3), the lack
of sufficient data to set a toxicity  limitation more stringent than 30,000 ppm (SPP) (for Option 2) and the
high cost-effectiveness results for both Options 2 and 3, a preferred option has not been selected.

       A large majority of  operators  are already discharging  at levels less toxic than the toxicity
limitations of 30,000 ppm (SPP) contained in Option 1.  Thus,  this is a no cost option incurring no
economic or non-water quality environmental impacts.

       Option  2 requires  zero discharge for all operators except in Cook Inlet where operators would
be required to meet the Offshore subcategory limitations in addition to a toxicity limitation of between
                                             XIV-3

-------
                                               TABLE XIV-1
                                 Costs of Preferred BAT Options (1992$)
Wastestream
Drilling Fluids
and Cuttings
Produced Water
Treatment,
Workover, and
Completion
Fluids
Total
Selected Options
Co-Proposal
Option 1: Zero Discharge except
Cook Inlet (30,000 ppm toxicity)
Option 2: Zero Discharge except
Cook Inlet (100,000 - 1 million ppm
toxicity)
Option 3: Zero Discharge
BAT: Option 4: Zero discharge:
Cook Inlet Improved Gas Flotation
NSPS: OptionS: Zero Discharge All
Co-proposal
Option 1: BPT
Option 2a: Zero Discharge
Option 2b: Gas Flotation
-
Costs
BAT
Capital
($MMfr
NA"
NAb
NAb
88.54
NA
NAC
NAC
NA"
-
O&M
<$MM?yr>
NA"
NA"
NAb
17.66
NA
0
0.61
NAd
-
Aromatized*
(SMMftr)
0
1.37"
3.89"
30.86
NA
0
0.61
NA"
30.86-35.36
NSPS
Capital
<$MM)
NAb
NAb
NA"
NA
1.73
0
NA"
NA"
-
Grand Total:
(BAT and NSPS combined)
O&M
<$MM)/yr
NAb
NAb
NAb
NA
0.39
0
0.079
NA"
—
Annualized"
0MMfyr)
0"
0"
Ob
NA
4.48
0
0.079
NA"
4.48 - 5.00
$35.34 -$40.36
" Annualized (S million/yr) Costs from the Economic Impact Analyses (ERG, Nov. 1994)
b The total compliance costs for drilling fluids and cuttings were not segregated into capital and O&M costs (see Section X of mis document).
* Capital costs were not calculated for treatment, workover, and completion fluids (see Section XII of this document).
* Not considered as an option because this is not the preferred option selected for produced water.

NA Not Applicable
                                               TABLE XTV-2
                                   Proposed BPT Effluent Limitations
Pollutant Parameter Waste
Source
Produced Sand
Maximum for any 1 day
zero discharge
i Average of Values far 30
: consecutive days shall not
exceed
zero discharge
Residual chlorine minimum for
any 1 day
NA
                                                   XIV-4

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                                               TABLE XIV-3
                                        BAT Effluent Limitations
Stream
Produced Water
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Drilling Fluids and Drill
Cuttings
Option 1
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Option 2
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Option 3
All coastal areas
Well Treatment, Workover
and Completion Fluids
Option 1
A) All coastal areas except
freshwater of Texas and
Louisiana
B) Freshwaters of Texas
and Louisiana
Option 2
A) All coastal areas except
Cook Inlet
B) Cook Inlet
Produced Sand
Deck Drainage
Domestic Waste
Pollutant Parameter
Oil & Grease


Free Oil(1)
Diesel Oil
Mercury
Cadmium
Toxicity

Free Oil(1)
Diesel Oil
Mercury
Cadmium
Toxicity




Free Oil(l>

Oil and Grease

Free O'dm
Foam
BAT Effluent Limitations
No discharge
The maximum for any one day shall not exceed 42 mg/1,
30-day average shall not exceed 29 mg/1


No discharge
No discharge
No discharge
1 mg/kg dry weight maximum in the stock barite
3 mg/kg dry weight maximum in the stock barite
Minimum 96-hour LC50 of the SPP shall be 3 percent by

and the


volume®

No discharge
No discharge
No discharge
1 mg/kg dry weight maximum in the stock barite
3 mg/kg dry weight maximum in the stock barite
Minimum 96-hour LC50 of the SPP shall be 10 percent to 100
percent by volume'3'

No discharge


No discharge
No discharge

No discharge
The maximum for any one day shall not exceed 42 mg/1,
30-day average shall not exceed 29 mg/1






and the
No discharge
No discharge
No discharge
(1)   As determined by the static sheen test.
(2)   As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual sheen).
(3)   As determined by the toxicity test (see Appendix 2 of 58 FR 12454, March 4, 1993).
                                                    XTV-5

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                                               TABLE XIV-4
                                   Proposed BCT Effluent Limitations
Stream
Produced Water (all facilities)
Drilling Fluids and Drill Cuttings
A) All facilities except
Cook Inlet
B) Cook Inlet
Well Treatment, Workover, and
Completion 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 garbage
BCT Effluent Limitations
The maximum for any one day shall not exceed 72 mg/1, and the
30-day average shall not exceed 48 mg/1
No discharge
No discharge (1)
No discharge (1)
No discharge
No discharge (2)
Minimum of 1 mg/1 maintained as close to this concentration as
possible
No discharge
No discharge of Floating Solids or garbage (3)
(1) As determined by static test 40 CFR Part 435, Subpart A, Appendix 1
(2) As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual sheen).
(3) As defined in 40 CFR § 435.41(1).
                                                    XIV-6

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                                                 TABLE XIV-5
                                          NSPS Effluent Limitations
Stream
Produced Water
(all facilities)
Drilling Fluids and Drill Cuttings
Option 1
A) All coastal areas except Cook Inlet
B) Cook Inlet





Option 2

A) All coastal areas except Cook Inlet
B) Cook Inlet





Option 3
All coastal areas
Well Treatment, Workover and
Completion Fluids
Option 1
A) All coastal areas except freshwater of
Texas and Louisiana
B) Freshwaters of Texas and Louisiana
Option 2
A) All coastal areas except Cook Inlet
B) Cook Inlet

Produced Sand
Deck Drainage
Sanitary Waste
Sanitary M10

Sanitary M91M
Domestic Waste

Pollutant Parameter





Free OiP
Diesel Oil
Mercury
Cadmium
Toxicity




Free Oil("
Diesel Oil
Mercury
Cadmium
Toxicity





Free Oilm




Oil and Grease


Free OiP

Residual Chlorine

Floating Solids
Floating Solids,
Garbage(4) and Foam
NSPS/PSNS ECBuerit Limfiatfens
No discharge



No discharge
No discharge
No discharge
1 mg/kg dry weight maximum in the stock barite
3 mg/kg dry weight maximum in the stock barite
Minimum 96-hour LC50 of the SPP shall be 3 percent
by volume ra


No discharge
No discharge
No discharge
1 mg/kg dry weight maximum in the stock barite
3 mg/kg dry weight maximum in the stock barite
Minimum 96-hour LC50 of the SPP shall be 10 percent
to 100 percent to 100 percent by volume 0)

No discharge


No discharge

No discharge

No discharge
The maximum for any one day shall not exceed 42
mg/1, and the 30-day average shall not exceed 29 mg/1
No discharge
No discharge

Minimum of 1 mg/1 and maintained as close to this
concentration as possible
No discharge
No discharge of floating solids or garbage or foam

(1)    As determined by the static sheen test
(2)    As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual sheen).
(3)    As determined by the toxicity test (see Appendix 2 of 58 FR 12454, March 4, 1993).
(4)    As defined hi 40 CFR § 435.41(1)
                                                      XTV-7

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                                       TABLE XIV-6
                             Proposed PSES Effluent Limitations
Stream
Produced Water
Drilling Fluids and Drill Cuttings
Well Treatment, Workover, and
Completion Fluids
Produced Sand
Deck Drainage
i <• ff
Pollutant Parameter „ ,1,





PSES Effluent Limitations
No discharge
No discharge
No discharge
No discharge
No discharge
                                       TABLE XIV-7
                             Proposed PSNS Effluent Limitations
Stream.
Produced Water (all facilities)
Drilling Fluids and Drill Cuttings
Well Treatment, Workover, and
Completion Fluids
Produced Sand
Deck Drainage
^ Pollutant Parameter





PSNS Effluent Limitations
No discharge
No discharge
No discharge
No discharge
No discharge
100,000 ppm (SPP) and 1,000,000 ppm (SPP).    This option would cost $1.4 million annually and
results in less than a 0.1 percent reduction in estimated lifetime production for Cook Inlet platforms which
would not significantly reduce the profit potential for these operators.2  Option 2 would result in the
removal of approximately 3.9 million pounds of pollutants being discharged per year (or 1264 pounds
in toxic equivalents)2, assuming a volume of 17 percent of the discharges would not meet a toxicity limit
of between 100,000 ppm and one million ppm (SPP) and would therefore be disposed of by grinding and
injection or on land.  Out of the 3.9 million pounds removed annually less than 0.02 percent consists of
toxic priority pollutants (or 642 pounds).2

       Due to limitations with the data base, EPA is currently only able to  estimate an achievable
toxicity limit in the range of 100,000 ppm (SPP)  to one million ppm (SPP).   EPA will continue to
                                           XIV-8

-------
evaluate toxicity test results and volumes and other data for drilling fluids used and discharged in Cook
Inlet in an effort to derive a more specific limitation.  A  supplemental notice presenting the data and
soliciting comment may be necessary prior to promulgation.

        Option 3 would cost the industry $3.9 annually and result hi the reduction of 23 million pounds
of pollutants being discharged per year (or 7375 in toxic pounds equivalents).2 Zero discharge of drilling
fluids and drill cuttings is widely practiced in other coastal areas other than Cook Inlet, including the Gulf
of Mexico, California, and the North Slope of Alaska. In Cook Inlet, zero discharge is not currently
practiced but for a small amount of drilling fluids  (approximately one percent) that do not meet permit
limits.  Zero discharge is technologically available because operators are able  to comply with zero
discharge by either disposing of their drilling fluids and drill cuttings onshore or by grinding and injecting
the waste.  The costs of this option would result hi.a 2.7 percent reduction  in the estimated lifetime
production for Cook Inlet platforms, which would not significantly reduce the profit potential for these
operators.1 Thus, EPA believes these costs are economically achievable.  However, concerns have been
raised that zero discharge would interfere with drilling operations, hi part because the weather conditions
and tidal fluctuations in the Inlet pose logistical difficulties for drilling waste transportation especially
during whiter months. In addition, while Option 3 would result in the removal of 23 million pounds of
pollutants per year, less than 0.02 percent of which are  toxic pollutants2, the $3.9 million annually
incurred by industry to remove the 3760 pounds of priority toxic pollutants indicates that this option is
not cost effective.  In Cook Inlet, operators are not currently practicing zero discharge.  EPA estimates
that to comply with a  total zero discharge requirement, 24 percent of the drilling fluids and drill cuttings
would be ground and injected into dedicated wells, and 76 percent would be disposed of onshore.

        EPA does  not expect any new source development wells drilled in Cook Inlet hi the seven years
following the scheduled promulgation of this rule. This is because all development wells are expected
to be drilled from existing platforms hi Cook Inlet.  According to the definition of new sources, these
wells would be existing sources. Additionally, any drillings that may  occur in the recently discovered
Sunfish formation hi  Upper Cook Inlet, are projected to be exploratory wells, which are also existing
sources according  to the new source definition.  Thus, no costs will be attributed to NSPS in Cook Inlet
because no new sources are projected for this area.  However, hi the case  that a  new source would be
drilled hi Cook Inlet, EPA has determined that zero discharge would not pose a barrier to entry for the
drilling project.1  The same options are being considered for NSPS as for BAT, no one preferred NSPS
option is being selected for this proposal.  Since the NSPS requirements would be the  same as those for
BAT, costs to meet zero discharge would be equal to or less than BAT.  Costs may be less than BAT
                                             XIV-9

-------
because process modifications can be incorporated into the drilling rig design prior to its installation
rather than retrofitting an existing operation.   Since EPA has determined that BAT is economically
achievable, equivalent NSPS requirements would also be economically achievable, and cause no barrier
to entry.

       EPA also finds the non-water quality environmental impacts of zero discharge to be acceptable
(see Section XVI of this document).  Again, non-water quality environmental impacts attributable to this
rule would occur only in Cook Inlet. The air emissions and energy requirements associated with waste
transportation were calculated for the two operators expected to utilize onshore landfill disposal to
accommodate the wastes from their drilling operations.  For the remaining two operators who will be
                    *
drilling and do not have access to onshore disposal, EPA has  calculated the air emissions and energy
requirements resulting from grinding and injection to meet zero discharge.  EPA has found that these non-
water quality environmental impacts represent only a very small fraction of the total air emissions and
energy requirements from normal operations, and that these non-water quality environmental impacts are
acceptable.  As stated above, EPA does not expect any new sources to be initiated in Cook Inlet. EPA,
however,  believes that the non-water quality environmental impacts resulting from any such activity
would be equal to or less than those anticipated for existing sources, which EPA has found acceptable.

3.1.2   BCT
       As discussed in Section W of this document, Option 2 (prohibition of the discharge of free oil
and diesel oil, limitations on cadmium and mercury hi the stock barite, and toxicity limitations of between
100,000 and 1  million ppm (SPP)) and Option 3 (zero discharge  all) did not pass the BCT cost test.
Thus, BCT is being proposed as equal to Option 1 which is zero discharge everywhere except for Cook
Inlet where BPT would apply.

       In addition to  considering setting the  BCT  limitations equal to  BPT, EPA  considered two
additional BCT options for control of conventional pollutants in drilling fluids and drill cuttings.  Both
of these options would  require zero discharge of drilling fluids  and  drill cuttings throughout the
subcategory except in Cook Inlet. Because  all operators throughout the entire subcategory, except in
Cook Inlet, are currently meeting a zero discharge requirement,  or in the case of dewatering effluent, are
practicing zero discharge already, there is zero cost and zero removal of conventional pollutants for the
limitation. Thus, EPA has determined that zero discharge passes the BCT cost tests and other statutory
factors and proposes a BCT limitation equal to zero discharge for all areas  except Cook Inlet.
                                            XIV-10

-------
       In Cook Inlet, EPA considered either zero discharge (Option 3) or allowing discharge based on
requirements identified in Option 2. EPA did not consider Option 1 for Cook Inlet, allowing discharge
at the current Offshore Guidelines limitations with a toxicity limit of 30,000 ppm (SPP), as a distinct BCT
option because the amount of removal of the conventional pollutant oil and grease, as oil, from discharge
by this level of toxicity could not be determined from that removed by the current BPT requirement of
no free oil. Both candidate BCT options fail the BCT cost test, and BCT is set equal to Option 1 for this
proposal which is equal to zero discharge everywhere except for Cook Inlet where BPT would apply.

3.1.3  Pretreatment Standards
       Based on the 1993 Coastal Oil and Gas Questionnaire and other information reviewed as part of
this rulemaking, EPA has not identified any existing coastal  oil and gas facilities which discharge drilling
fluids and cuttings to publicly owned treatment works (POTWs), nor are any new facilities projected to
direct these wastes  in  such manner.   However,  due to the high solids content of drilling fluids  and
cuttings, EPA is proposing to establish pretreatment standards for existing and new sources equal to zero
discharge because these wastes are incompatible with POTW operations (see Section XV).  For PSNS,
zero discharge would not cause a barrier to entry.1

3.2    PRODUCED WATER
3.2.1   BAT and NSPS
       As BAT for produced water, EPA proposes zero discharge everywhere except facilities in Cook
Inlet would be  required to meet limitations based on improved gas flotation (Option 4).  This option
prohibits discharges of produced water from all coastal facilities, except for those facilities located in
Cook Inlet.  Coastal facilities  in Cook Inlet would be required to  comply with the oil and  grease
limitations (29 mg/1 30-average, 42 mg/1 daily maximum) based on improved operating performance of
gas flotation. This option will remove 4.3 billion pounds per year of pollutants. EPA has determined
this option to be economically achievable and technologically available, and that it reflects the BAT level
of control.

       Zero discharge is technologically available  because  injection of produced water  is  currently
ongoing in much of the coastal subcategory at the present time, and adequate geological formations exist
to accept produced water. By 1996 (the projected date  of promulgation of this rule), 75 percent  of the
facilities in the Gulf region will already be meeting zero discharge. Option 4 is economically achievable
                                            XTV-11

-------
for those operators (the remaining 25%) that would otherwise be discharging in 1996, as the economic
analysis shows.1  The oil and grease limit applicable to Cook Inlet is technologically available.

       Option 4 is economically achievable because, as the economic analysis shows, total production
losses in terms of oil production as a result of this proposed  rule are expected to range between 1.0
percent and 1.7 percent of total lifetime production for both Cook Inlet and the Gulf.1  Additionally, only
2.4 percent of all current Gulf coastal wells (111 out of 4675 current Gulf coastal wells) and no Cook
Inlet platforms are considered likely to  shut in as a result of this rule.  These shut-in wells tend to be
relatively low - producing and marginal wells.  At most, only  2.8 percent of the operators in the Gulf
(12 of the estimated 435 Gulf coastal operators) might fail as a result of a zero discharge requirement and
no firm failure is expected in Cook Inlet, as a result of meeting oil and grease limits of 29 mg/1 30-day
average and 42 mg/1 daily maximum for produced water.   (The range of firm failures in the Gulf is
actually 0-12, but because data were not available  to rule  out the possibly of failures,  EPA assumed
possible failures to be actual failures.)  The "average" Gulf coastal firm does not discharge produced
water and coastal firms are expected to  face average (medium) declines in equity or working capital of
0 percent.  Of the 122 discharging firms, average (medium) declines in equity or working capital of 0.37
percent and 2.63 percent, respectively,  are expected to occur.   These  impacts, combined with the fact
that most Gulf coastal operators  (72 percent)  will not be discharging by  1996, show Option 4 to be
economically achievable.

       Option 5, zero discharge all, was not selected based on the unacceptable  economic impacts
estimated for the Cook Inlet operators.1  EPA's economic analysis shows that 3 of 13 platforms would
be shut-in as a result.1  EPA did not select the "Flotation All" or "BPT All"  options as preferred because
they,  applied industry-wide, do not represent BAT or NSPS level of control.  As stated previously, all
coastal operations in California,  Alabama, Florida, some parts of Louisiana,  and the North Slope of
Alaska do not discharge produced water, but inject their produced water underground either to comply
with permit limitations or to enhance hydrocarbon recovery. EPA has therefore concluded that control
options based on the continued discharge of produced water in all areas of the country do not represent
BAT or NSPS.

       Non-water  quality environmental impacts for the proposed Option 4 consist of incremental air
emissions of approximately 2,800 tons/year across the  entire subcategory.  Given that an average Gulf
coast production facility may alone produce approximately 188 tons/year of emissions, this option would
increase air emissions by about 13 percent.  EPA considers this increase to be acceptable.
                                            XIV-12

-------
       For NSPS control of produced water discharges from new sources, EPA is proposing the "Zero
Discharge All" (Option 5) prohibiting discharges of produced water from all new sources.  Option 5 is
economically achievable for the reasons discussed in the economic impact analysis.1  This NSPS option
is estimated to cost approximately $4.5 million annually for the entire coastal subcategory.  This cost
would be incurred only by Gulf Coast operators  where EPA  estimates that approximately 6  new
production facilities will be constructed per year.   No new sources are  expected in the  Cook Inlet.
However, were new sources to be installed in Cook  Inlet, the preferred NSPS option of zero discharge
is not expected to cause a barrier to entry because new project operations would still be quite profitable.1
In addition, EPA has determined the non-water quality environmental impacts to be acceptable for the
NSPS option for produced water. Total incremental emissions from the proposed option is approximately
64 tons/year for  NSPS.  As  a comparison, an average  Gulf coast production facility may produce
approximately 188 tons/year of emissions.  EPA considers this increase in non-water quality impacts to
be acceptable.

3.2.2   BCT
       As discussed earlier in Section Vm of this document, all options except Option 1:   "BPT All"
fail the BCT cost tests,  and thus, EPA proposes to establish BCT limitations equal to BPT. Costs for the
"BPT All" option are equal to  zero because facilities are complying with the current BPT limitations.

3.2.3   Pretreatment Standards
       Based on the 1993 Coastal Survey and other information reviewed as part of this rulemakrng,
EPA has not identified any existing coastal oil and gas facilities which discharge produced water to
publicly owned treatment works (POTWs), nor are any new facilities projected to direct their produced
water discharge in such manner.   However,  because EPA is proposing a limitation requiring zero
discharge for those existing facilities, there is the potential that some facilities may consider discharging
to POTWs in order to meet the  BAT and/or NSPS limitations. Pretreatment standards for produced water
are appropriate because EPA  has identified the presence of a number of toxic and nonconventional
pollutants, many of which are incompatible with the biological removal processes at POTWs  (see Section
XV).  Large concentrations of dissolved solids in the form of various salts in the produced  water cause
the discharge to POTWs to be incompatible with the biological treatment processes because these "brines"
can be lethal to the organisms present in the POTW biological treatment systems.
                                            XIV-13

-------
       EPA is proposing to require pretreatment standards for existing and new sources (PSES and
PSNS, respectively) that would prohibit the discharge of produced water.   The technology basis for
compliance with PSES and PSNS would be the same as that for BAT and NSPS zero discharge limits.
The cost projection for both PSES and PSNS are considered to be zero since no existing sources
discharge to POTWs,  and there are no known plans for sources to be installed in locations amenable to
sewer hookup.  Also, because no facilities are discharging to POTWs, EPA proposes that PSES and
PSNS requiring zero discharge be effective as of the effective date of this rule.  Because zero discharge
for new sources is economically achievable, the costs of complying with zero discharge would not be a
barrier to entry.  Non-water quality environmental impacts would be similar to those for new sources,
which EPA has found to be acceptable.  Thus, EPA has determined that pretreatment standards for new
sources that are equal to NSPS are economically achievable and technologically available for PSNS, and
that the non-water quality environmental impacts are acceptable.

3.3   TREATMENT, WORKOVER, AND  COMPLETION FLUIDS
       EPA is proposing to establish BCT limitations equal to BPT, prohibiting the discharge of free oil
in well treatment, workover, and completion fluids. Compliance with this limitation would be determined
by  the static sheen test.  Based  on the available data regarding the levels of conventional pollutants
present hi these wastes, EPA did not identify any other options which would pass the BCT cost test other
than establishing BCT equal to the existing BPT limits (see Section XH). There are no costs or non-water
quality environmental impacts associated with this proposed BCT limitation and, since it is equal to BPT,
it is technologically available and economically achievable.

       EPA is co-proposing Option 1 and Option 2a for well treatment, workover, and completion fluids
for BAT and NSPS.  (Option 2b is not proposed because discharges based on unproved gas flotation
technology was not an option selected for produced water.)  EPA has determined that both options are
technologically and economically achievable1 and have acceptable non-water quality impacts (see Section
XVI of this document). However, due to the high cost effectiveness results for Option 2a2 (requiring the
same limitations as proposed for  produced  water), a preferred option has not been selected.  Option 1,
which would prohibit the discharge of free oil and prohibit the discharge of treatment,  workover and
completion of fluids to freshwaters of Texas and Louisiana, reflects current regulatory requirements and
thus will incur no additional compliance costs, economic or non-water quality environmental impacts.
This option would result in no incremental removal  of pollutants from this wastestream  beyond the
existing BPT requirements.
                                           XIV-14

-------
        Option 2a would require for BAT zero discharge of treatment, completion, and workover fluids
except for Cook Inlet, where EPA would establish oil and grease limitations of 29 mg/1 30-day average,
42  mg/1 daily maximum.   For  NSPS,  this option would  require  zero  discharge  of all treatment,
completion, and workover fluids from all new sources.

        Zero discharge  is being achieved by many operators (except those in Texas, saline waters of
Louisiana,  and Cook Inlet) for the treatment, workover, and completion fluids  wastestream.   The
technology basis for zero discharge is commingling this wastestream with produced water or sending it
separately to off-site commercial disposal facilities.  For Cook Inlet, this  option, which also contains
allowable discharge limitations is based on commingling with produced water, because commingling of
these wastestreams is currently occurring in this area. The specific oil and grease  limits proposed are
technologically available for the same reasons they are available for  control of produced water, as
discussed above.

        The zero discharge  limitation would  eliminate all  discharges of toxic,  conventional,  and
nonconventional pollutants. The oil and grease limits would be technologically based on improved gas
flotation performance and serve to limit  the discharge of toxic and conventional pollutants to surface
waters.

        Zero discharge for treatment, workover and completion fluids in Cook Inlet was not selected for
this BAT option because these fluids are commingled with produced water as an integral part of their
operations, and because zero discharge for produced water was determined to be uneconomical for Cook
Inlet operators.

        The costs to meet Option 2a for BAT ($610,000) are relatively minimal since this amount is
negligible in comparison to total annual production revenue from Gulf coastal operations.1

        Costs to achieve zero discharge everywhere for Option 2a NSPS are expected to be negligible.
Out of the 187 new wells that will be drilled in the Gulf Coast, 76 percent will not discharge these fluids
in freshwaters because of water quality standards requirements.  The remaining 45 facilities will each
generate approximately 800 bbls of treatment, workover and completion fluids per year (estimates of
volumes from the 1993 Coastal Oil and Gas Questionnaire). While some of these fluids may be directed
for treatment and disposal to existing production facilities, EPA is conservatively estimating costs of the
Option 2a NSPS assuming all of these fluids would be directed to new production facilities for treatment
                                            XTV-15

-------
and disposal (or be treated on-site at the new source).  For the Gulf, the NSPS requirements under this
Option 2a would be  the same as those for BAT, thus costs would either be equal to BAT, or less than
BAT since new sources can more efficiently design their facilities to comply with zero discharge.  Costs
for new sources in the Gulf generating treatment, workover and completion fluids to meet zero discharge
would be approximately $520,000 per year which is negligible in relation to annual production revenue
from Gulf coastal operators.1

       For Cook Inlet, costs to meet Option 2a requirements for treatment, workover and completion
fluids are included in the cost analysis for produced water because current practice there is commingling
of these wastestreams.  While EPA does not anticipate any new sources to be constructed in Cook Inlet,
and therefore has not attributed any costs to NSPS,  the NSPS would not cause a significant barrier to
entry.1 These impacts are only a small incremental increase over the impacts resulting from the controls
on produced water and drilling fluids and cuttings. Finally the non-water quality environmental impacts
of this Option 2a are believed to be acceptable, because like their volumes, they are relatively small (see
Section XVI of this document) as discussed below.

       Option 2a  would result in the removal of 3.9  million pounds of conventional, toxic and non-
conventional pollutants annually (a total of 2140 hi toxic pound equivalents2). However the amount of
toxic priority pollutants removed is approximately 0.02 percent of this total.  The annual compliance costs
of $1.1 million (for BAT and NSPS combined) to remove 800 pounds of priority toxic pollutants indicates
that this option is not cost effective.2

       For BCT, EPA is proposing to establish limitations equal to BPT, prohibiting the discharge of
free oil and TWC  fluids.  No  other options passed the BCT cost tests.  No costs are attributed to this
BCT option because  it reflects  current practice.

       Pretreatment standards for treatment, workover, and completion fluids are being proposed equal
to zero discharge.  This is because their chemical composition, like produced water, tends to be high in
total dissolved which may interfere with POTW operations (see  Section XV).  EPA solicits comments
on  these issues.  Zero discharge for NSPS would  not pose  barrier to entry for the same reason as
discussed under NSPS for this wastestream.1
                                            XIV-16

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3.4    DECK DRAINAGE
        EPA has selected BPT as its preferred option for BAT and NSPS for deck drainage. Since free
oil discharges are already prohibited under BPT, there are no incremental compliance costs,  pollutant
removals, or non-water quality environmental impacts associated with this control option. Since this
preferred option limits free  oil equal to existing BPT standards,  it is technologically available and
economically achievable.

        EPA has rejected the first flush option for control of deck drainage for several reasons primarily
relating to whether this option is technically available to operators throughout the coastal subcategory.
Deck drainage is currently captured by drains and flows via gravity to separation tanks below the deck
floor.   However,  the problems  associated with capture  and treatment beyond gravity feed, power
independent systems,  are compounded by the possibilities of back-to-back storms which may cause first
flush overflows from an already full 500 bbl tank. In addition, tanks the size of 500 barrels are too large
to be placed under deck floors.  Installation of a 500 bbl tank would require construction of additional
platform space and the installation of large pumps capable of pumping sudden and sometimes large flows
from a drainage collection system up into the tank.  The additional deck space would add significantly,
especially for water-based facilities, to the cost of this  option.  Further,  many coastal facilities are
unmanned and have no power source available to them.  Deck drainage can be channelled and treated
without power under the BPT limitations.

        Capturing deck drainage  at drilling operations poses  additional technical difficulties.   Drilling
operations on land  may involve an area of approximately 350 square feet.   A  ring levee is typically
excavated around the entire perimeter of a drilling operation to contain contaminated runoff. This ring
levee may have a volume of 6,000 bbls, sufficient to contain 500 bbls of  the first flush. However,
collection of these  500 bbls  when  6,000 bbls may be present hi the ring levee would not efficiently
capture the first flush.  Costs to install a separate collection system, including pumps and tanks, would
add significantly to the cost of this option.

        While costs are significant, the technological difficulties involved with adequately capturing deck
drainage at coastal facilities is the principal reason why this option was not selected.  EPA has selected
the option requiring no discharge of  free oil for BAT and NSPS control of deck drainage.  EPA has
determined that these limitations and standards properly reflect BAT and NSPS levels of control. EPA
did not identify any other available  technology for this waste-stream.
                                             XTV-17

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        EPA's proposed option does not include best management practices (BMPs) for this wastestream
as part of these guidelines. EPA currently believes that current industry practices,  in conjunction with
the requirements as proposed in the proposed general stormwater rule (58 PR 61262-61268, November
19, 1993), would be sufficient to minimize the introduction of contaminants to this wastestream to the
extent possible.  These stormwater requirements, if promulgated as proposed, would require an oil and
gas operator to develop and implement a site-specific storm water pollution prevention plan consisting
of a set of BMPs depending on specific sources of pollutants at each site.  As noted in the stormwater
proposal, the two types of BMPs most effective in reducing storm-water contamination are to minimize
exposure (e.g., covering, curbing, or diking) and treatment type BMPs which are used to reduce or
remove pollutants in storm-water discharges (e.g., oil/water separators, sediment basins, or detention
ponds).  BMPs that may be incorporated into system operations are discussed hi Section XVI of this
document.

        The first flush option did not pass the BCT cost test, thus EPA is proposing that BCT limitations
for deck drainage equal BPT which prohibits the discharge of free oil.  No costs are attributed to this
option because it reflects current practice.

        EPA is proposing to limit PSES and PSNS for deck drainage as zero discharge.  EPA believes
that zero discharge for PSES and PSNS is  preferable to  establishing a limit equal to BPT because
generally slugs of deck drainage would interfere  with biological treatment processes at POTWs (see
Section XV).  Moreover, technical difficulties associated with capture of deck drainage that make it
difficult to require limitations other than the BPT, no free oil limit makes it unlikely that this wastestream
would be sent to POTWs.

3.5    PRODUCED SAND
        EPA is proposing to set the BPT, BCT, BAT, and NSPS limitations equal to zero discharge for
produced sand. Produced sand is the only wastestream for which BPT is being proposed (BPT has been
previously promulgated for all other wastestreams). As discussed in Section IX.2, produced sand is not
currently being discharged into the coastal regions  of Alaska, California, nor the Gulf of Mexico.  EPA
has determined that zero discharge reflects the  BPT, BCT,  BAT,  and NSPS levels of control because,
since it is widely practiced throughout the industry,  it is both economically achievable and technologically
available.  The zero discharge requirement would eliminate the discharge of all pollutants present in
produced sand.  Because zero discharge of produced sand is already so widespread, this requirement will
                                            XIV-18

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result in a minimal increased cost to the industry, and non-water quality environmental impacts will be
negligible.   Since proposed BCT would be set equal to proposed BPT,  there is no cost of BCT
incremental to BPT.  Therefore this option passes the BCT cost reasonableness test.

        EPA is also proposing to set PSES and PSNS equal to zero discharge for produced sand.  The
technology basis for compliance with PSES and  PSNS is the same  as that for BAT  and NSPS.
Pretreatment standards for produced sands are being proposed as equal to zero discharge because, like
drilling fluids and cuttings, their high solids content would interfere with POTW operations (see Section
XV). Because EPA is not aware of any discharges of produced sands to POTWs, this requirement is not
expected to incur any costs.  There are no additional non-water quality environmental impacts associated
with this requirement because it reflects current practice.

3.6    DOMESTIC WASTES
        The BPT limitations for domestic wastes are no discharge of floating solids.  EPA is proposing
to limit floating solids for BCT and NSPS. In addition, EPA is proposing to prohibit discharges of foam
for BAT and NSPS.  EPA is also proposing to incorporate requirements limiting discharges of garbage
as defined in the U.S. Coast Guard regulations at 33 CFR Part 151.

        The current Region X General Permit regulations applicable to coastal facilities in Alaska have
limitations of "no free oil," "no floating solids," and "no foam."  The EPA Region VI General Permits
for both drilling and production operations include a prohibition on the discharge of floating solids and
on the discharge of garbage  as defined by Coast  Guard regulations  at 33 CFR Part  151 (the definition
of "garbage" is included hi 33 CFR 151.05). Floating solids is a conventional pollutant, while foam is
a nonconventional pollutant.

        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 hi current State or NPDES permits.  Under the Coast Guard regulations, discharges of garbage,
including plastics, from  fixed and  floating  platforms engaged  hi  the exploration, exploitation, and
associated offshore processing of seabed mineral resources, are prohibited with one exception:  Victual
Waste (not including plastics) may be discharged from fixed or floating platforms located beyond 12
nautical miles from nearest land, if such waste is passed through a screen with openings no greater than
25 millimeters (approximately one inch)  in diameter.  Because vessels and fixed and floating platforms
                                            XIV-19

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must comply with these limits, EPA believes that all coastal facilities are able to comply with this limit
as well.

       Since these BCT, BAT, and NSPS limitations for domestic waste are already in either existing
State or NPDES permits or existing 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.

       Pretreatment standards are not being developed for domestic waste because they are compatible
with POTWs (see Section XV).

3.7   SANITARY WASTES
       Existing BPT limitations for facilities continuously manned by 10 or more people require sanitary
effluent to maintain a minimum residual chlorine content of 1 mg/1, with the chlorine concentration to
remain as close to this level as possible.  Facilities intermittently manned or continuously manned by
fewer than 10 people must comply with a BPT prohibition on the discharge  of floating solids.  EPA is
proposing to  limit sanitary wastes discharges for BCT and NSPS equal to BPT limitations.

       EPA considered zero discharge of sanitary wastes based on off-site disposal  to municipal
treatment facilities or injection along with other oil and gas wastes. Off-site disposal would require pump
out operations, that while available to certain land facilities, are not available to remote or water-based
operations.  Because sanitary wastes are not wastes exclusively associated with  oil and gas operations,
which are routinely injected into Class n wells, zero discharge was not considered for sanitary wastes.
Thus, zero discharge was not considered for sanitary wastes.

       Since there are no increased control requirements beyond that already required by current effluent
limitations, there are no 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.
                                            XIV-20

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       EPA is not establishing BAT effluent limitations for the sanitary waste-stream because no toxic
or nonconventional pollutants of concern have been identified in these wastes.  Pretreatment standards
are not being developed for sanitary wastes because they are compatible with POTWs (see Section XV).
                                            XIV-21

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4.0   REFERENCES

1.     Eastern Research Group,  Inc. (ERG), "Economic Impact Analysis  of Proposed Effluent
       Limitations Guidelines and Standards for the Coastal Oil and Gas Industry," EPA Contract No.
       68-03-0302, January 31, 1995.

2.     Eastern Research Group, Inc. (ERG),  "Cost Effectiveness Analysis  of Proposed Effluent
       Limitations Guidelines and Standards for the Coastal Oil and Gas Industry," EPA Contract No.
       68-C3-0302, January 31, 1995.
                                          XIV-22

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                                      SECTION XV
                          PRETREATMENT STANDARDS
1.0   INTRODUCTION
       EPA must develop pretreatment standards for existing sources (PSES) under Section 307 (b) of
the Clean Water Act (CWA).   Pretreatment standards are designed to prevent the discharge of the
pollutants that pass through, interfere with, or are otherwise incompatible with the operation of publicly
owned treatment works (POTWs). The Clean Water Act requires that pretreatment standards for existing
sources  are to  be technology-based  and analogous to  the best  available  technology  economically
achievable (BAT) for direct dischargers.

       Section 307 (c) of the CWA requires EPA to promulgate pretreatment standards for new sources
(PSNS) at the same time that it promulgates new source performance standards (NSPS). The pretreatment
standards for new sources are to be technology based  and analogous to the best demonstrated control
technology (BADCT) for direct dischargers.  New  indirect discharging facilities,  like new direct
discharging facilities, have the opportunity to install the best available demonstrated technology, including
process changes, in-plant controls, and end-of-pipe treatment technologies.

       The general pretreatment regulations, applicable to existing and new source indirect dischargers
(PSES & PSNS) appear in 40 CFR Part 403.  These regulations describe the Agency's overall policy for
establishing and enforcing pretreatment standards for new and existing users of a POTW as  well as the
prohibited discharges that apply.

       The Agency is proposing zero discharge for the  pretreatment standards  for drilling fluids and
cuttings, produced water, treatment, workover and completion fluids, deck drainage and produced sand.
No pretreatment standards are being developed for sanitary and domestic wastes because these wastes are
compatible with POTWs.

       EPA determines which pollutants to regulate in PSES and PSNS on the basis of whether or not
they pass through, interfere with, or are incompatible with the operations of POTWs.  This section
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describes these pretreatment standard criteria and how they were evaluated with respect to the regulation
of the coastal oil and gas industry wastestreams.

       Pretreatment standards were not based on the pass-through analysis due to limited data to perform
this analysis.  The 1993 Coastal Survey and other information reviewed as part of this  rulemaking,
indicated that these wastes  were not  currently being discharged into POTWs.  However, pretreatment
standards are being proposed in the event that the zero discharge standard for direct discharges would
encourage operators to discharge into POTWs.

       Pretreatment standards for sanitary and domestic wastes are not being developed because they are
not expected to cause any upsets with the operation of the POTW. POTWs typically receive these types
of wastes from industrial and domestic users.

2.0   INTERFERENCE
       EPA's preferred option for produced water is zero discharge everywhere except Cook Inlet.  In
Cook Inlet,  the selected option for produced water is based on  improved gas flotation and requires a
limitation be met for oil and grease. Produced water consists of a brine usually containing high dissolved
solids.  In  1985,  EPA considered various  technologies  for treatment of produced waters including
biological treatment.   Biological treatment  was rejected because of the severely  difficult problems
associated with biologically treating briny wastes (1991 Offshore Development Document, Section IX).1
If produced  water is to be discharged into POTWs, problems with interference or incompatibility could
occur. These systems (POTWs, biological treatment systems) can be acclimated to high dissolved solids
content, but the incoming stream would have to continue at a constant concentration and flow rate for the
system to work properly.2-3  However,  this is uncommon for  this industry  (variations hi flow and
concentrations exist, and production  processes may cease periodically for a short time to rework and
maintain the well).  Major interruptions could occur as a result, causing interferences with the operation
of POTWs.

       The proposed BAT option for drilling fluids and drill cuttings is a zero discharge requirement hi
all coastal areas.   The zero discharge limitation would eliminate the discharge of all  pollutants in the
waste stream.  Drilling fluids and drill cuttings would cause interference with the operation of POTWs
due to the high total suspended solids (TSS)  content which could not only cause clogging hi the piping
leading into  the POTW, but interfere with the biological treatment systems as well.  And as stated in 40
                                             XV-2

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CFR Part 403.5 "National Pretreatment Standards: Prohibited discharges":  Solid or viscous pollutants
in amounts which will cause obstruction to the flow in the POTW resulting in interference shall not be
introduced  into POTWs. This can occur with drilling fluids and drill cuttings due to the high solids
content (pollutants found in drilling fluids and drill cuttings are listed in Section YE of this document).

       The proposed BAT option for deck drainage consists of a prohibition on the discharge of free oil
which is  equal to the current BPT limitation.  EPA determined that technical difficulties are associated
with the capture of deck drainage in order to meet a zero discharge requirement. However, for the same
reasons that zero discharge is not feasible, it is unlikely that deck drainage would be captured, contained
and directed to POTWs for treatment. Additionally, deck drainage, being generated due to rainfall, may
consist of unmanageable slugs of sudden influent to POTWs such that it would cause POTW interference.
Deck drainage consists of precipitation runoff, miscellaneous leakage and spills, washdown of decks and
could potentially contain pollutants that would interfere with the operation of POTWs as in the case of
produced water. Thus pretreatment standards are being proposed as equal to zero discharge.

       Untreated deck  drainage data was  collected by the Agency from  the three-facility sampling
program  conducted during 1989.  The information is summarized in Section XTfl of this document. Also,
in 1989,  EPA reviewed extensive records of deck drainage data provided by API in the 1990s. Both the
Agency's data gathering efforts and API's survey information indicate that the frequency, volume and
content of deck drainage is highly variable.

3.0   PASS-THROUGH
       Pretreatment standards for existing sources are analogous to BAT and thus a pass through analysis
is conducted in order to determine the specific pollutants to be regulated under PSES.

       EPA determines whether  or not to regulate a pollutant under pretreatment standards on the basis
of whether or not the pollutant passes through, interferes with, or is incompatible with the operation of
the POTW.  EPA  evaluates pollutant pass through by comparing  the average percentage removed
nationwide by  well-operated POTWs  (those meeting secondary treatment requirements) with the
percentage removed by directly discharging facilities applying BAT for that pollutant.  When the average
percentage removed by  well-operated POTWs is less than the percentage removed applying BAT, the
pollutant is said to pass through and a pretreatment standard would be required. When the pollutant does
not pass  through (average percentage removed by well-operated POTWs is greater than the percentage
                                             XV-3

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removed by applying BAT) a pretreatment standard would not be required. However, for the coastal oil
and gas industry, insufficient information exists to perform pass through analyses.  Rather, pretreatment
standards have been developed on the basis of interference.

        Pretreatment standards for new sources are analogous to NSPS and thus are being proposed as
zero discharge. New facilities have the opportunity to install the best available demonstrated technology
and  since both standards concern new  sources, the  technology  basis being proposed  for  NSPS is
appropriate for application for PSNS.

4.0    REMOVAL CREDITS
        As described previously, many industrial facilities discharge large  quantities of pollutants to
POTWs where their wastewaters mix with wastewater from other sources such as domestic sewage from
private  residences  and run-off from various-sources prior to treatment and discharge by the POTW.
Industrial discharges frequently contain pollutants that are generally not removed  as effectively by
treatment at the POTWs as by the industries themselves.

        The introduction of pollutants to a POTW from industrial discharges may pose several problems.
These include potential  interference  with the  POTW's operation or pass-through of pollutants if
inadequately treated.  As discussed, Congress, in section 307(b) of the Act, directed EPA to establish
pretreatment standards to prevent these potential problems.   Congress also recognized that, hi certain
instances, POTWs could provide some or all of the treatment of an industrial user's wastewater that
would be required pursuant to the pretreatment standard.   Consequently,  Congress established  a
discretionary program for POTWs to grant "removal credits" to their indirect dischargers. The credit,
in the form of a less stringent pretreatment standard, allows an increased concentration of a pollutant in
the flow from the indirect discharger's  facility to the POTW.

        Section 307(b) of the CWA establishes a three-part test for obtaining removal credit authority for
a given pollutant.  Removal credits may be authorized only if (1) the POTW "removes all or any part
of such toxic pollutant," (2) the POTW's ultimate discharge would "not violate that effluent limitation,
or standard which would be applicable to that toxic pollutant if it were discharged" directly rather than
through a POTW and (3) the POTW's discharge would "not prevent sludge use and disposal by such
[POTW] in accordance with section [405]...." Section 307(b).
                                             XV-4

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        EPA has promulgated removal credit regulations in 40 C.F.R. Part 403.7. The United States
Court of Appeals for  the  Third Circuit has interpreted the statute to  require EPA  to  promulgate
comprehensive sewage  sludge regulations before any removal credits could be authorized.   NRDC v.
EPA. 790 F.2d 289, 292 (3rd Cir. 1986) cert, denied. 479  U.S. 1084 (1987).  Congress made this
explicit  in the Water Quality Act of 1987 which provided that EPA could not authorize any removal
credits until it issued the sewage sludge use and disposal regulations required by section 405(d)(2)(a)(ii).

       Section 405 of the  CWA requires EPA to promulgate regulations that establish standards for
sewage sludge when used or disposed for various purposes. These standards must include sewage sludge
management standards as well as numerical limits for pollutants that may be present in sewage sludge in
concentrations which may adversely affect public health and the environment.  Section 405 requires EPA
to develop these standards in two phases.  On November 25,  1992, EPA promulgated the Round One
sewage  sludge regulations establishing standards, including numerical pollutant limits,  for the use or
disposal of sewage sludge.  58 Fed. Reg.  9248.   EPA established pollutant limits for ten metals when
sewage sludge is applied to land, for three metals when it is disposed of on a surface disposal site and
for seven metals and a total hydrocarbon operational standard, a surrogate for organic pollutant emissions,
when sewage sludge is  incinerated.  These requirements are codified at 40 C.F.R. Part 503.

       The Phase One regulations partially fulfilled the Agency's commitment under the terms of a
consent decree that settled a citizens suit to compel issuance of the sludge regulations.  Gearhart. et al.
v. Reillv. Civil No. 89-6266-JO (D.Ore).  Under the terms of that decree,  EPA must propose and take
final action on the Round Two sewage sludge regulations by December 15, 2001.

       At  the  same tune EPA promulgated the  Round One  regulations, EPA  also amended its
pretreatment regulations to provide that removal credits would be available for certain pollutants regulated
hi the sewage sludge regulations.  See  58 Fed. Reg, at 9386.  The amendments to Part 403 provide that
removal credits may be made potentially available for the following pollutants:

        (1) If a POTW  applies its sewage sludge to the land for beneficial uses, disposes of it on surface
disposal sites or incinerates it, removal credits may be available, depending on which use or disposal
method is selected (so  long as  the POTW complies  with the requirements in Part 503).   When sewage
sludge is applied to land, removal credits may be  available  for ten metals.  When sewage sludge is
disposed of on a surface disposal site, removal credits may be available for three metals.  When the
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 sewage sludge is incinerated, removal credits may be available for seven metals and for 57  organic
 pollutants.  See 40 C.F.R. § 403.7(a)(3)(iv)(A).

        (2) In addition, when sewage sludge is used on land or disposed of on a surface disposal site or
 incinerated, removal credits may also be available for additional pollutants so long as the concentration
 of the pollutant in sludge does not exceed a concentration level established in Part 403.  When sewage
 sludge is applied to land, removal credits may be available for two additional metals and 14  organic
 pollutants.  When the sewage sludge is disposed of on a surface disposal  site, removal credits  may be
 available for seven additional metals and 13 organic pollutants.  When the sewage sludge is incinerated,
 removal credits may be available for three other metals. See 40 C.F.R. § 403.7(a)(3)(iv)(B).

        3) When a POTW disposes of its sewage sludge in a municipal solid waste landfill that meets the
 criteria of 40 C.F.R. Part 258 (MSWLF), removal credits may be available  for any pollutant in the
 POTW's  sewage sludge.  See 40  C.F.R.  §  403.7(a)(3)(iv)(C).   Thus, given  compliance with the
 requirements of EPA's removal credit regulations,* following promulgation of the pretreatment standards
 being  proposed here, removal credits may be authorized for any pollutant  subject to pretreatment
 standards if the applying POTW disposes of its sewage sludge in a MSWLF that meets the requirements
 of 40 C.F.R. Part 258. If the POTW uses or disposes of its sewage sludge by land application,  surface
 disposal or incineration, removal credits may be available for  the following metal pollutants (depending
 on the method  of use or disposal):  arsenic, cadmium,  chromium,  copper,  iron, lead, mercury,
molybdenum, nickel, selenium and zinc. Given compliance with section 403.7, removal credits  may be
available for the following organic pollutants (depending on the method of use or disposal) if the POTW
uses or disposes of its sewage sludge: benzene, 1,1-dichloroethane, 1,2-dibromoethane, ethylbenzene,
methylene chloride, toluene, tetrachloroethene, 1,1,1-trichloroethane, 1,1,2-trichloroethane and trans-1,2-
 dichloroethene.

        Some facilities may be interested in obtaining removal credit authorization for other pollutants
being considered for regulation hi this rulemaking  for which removal credit authorization would not
otherwise be available under Part 403.   Under sections 307(b) and 405 of the CWA, EPA may authorize
    a   Under Section 403.7, a POTW is authorized to give removal credits only under certain conditions. These include applying
for, and obtaining, approval from the Regional Administrator (or Director of a State NPDES program with an approved pretreatment
program), a showing of consistent pollutant removal and an approved pretreatment program. See 40 C.F.R. § 403.7(a)(3)(i), (ii),
and (iii).
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removal credits only when EPA determines that, if removal credits are authorized, that the increased
discharges of a pollutant to POTWs resulting from removal credits will not affect POTW sewage sludge
use or disposal adversely.  As discussed in the preamble to amendment to the Part 403 regulations (58
Fed. Reg. 9382-83), EPA has interpreted these sections to authorize removal credits for a pollutant only
in one of two circumstances.  Removal credits may be authorized for any categorical pollutant 1) for
which EPA have established a numerical pollutant limit in Part 503; or 2) which EPA has determined will
not threaten  human health and the environment when used or disposed of in sewage  sludge.   The
pollutants described in paragraphs (1) - (3) above include all those pollutants that EPA either specifically
regulated hi Part 503 or evaluated for regulation and determined would not adversely affect sludge use
and disposal.

        Consequently, in the  case of a pollutant for which EPA did not perform a risk assessment hi
developing the Phase One sewage sludge regulations, removal credit for pollutants will only be available
when the Agency determines  either a safe level for the pollutant in sewage sludge or that regulation of
the pollutant is unnecessary to protect public health and the environment from the reasonably anticipated
adverse effects  of  such a  pollutant.5    Therefore, any person seeking to add additional categorical
pollutants to the list for which removal credits are now available would need to submit information to the
Agency to support  such a determination. The basis for such a  determination may include information
showing the absence of risks for the pollutant (generally established through an environmental pathway
risk assessment such as EPA used for Phase One) or data establishing the pollutant's presence hi sewage
sludge at low levels relative to risk levels or both. Parties, however, may submit whatever information
they conclude is sufficient to establish either the absence of any potential for harm from the presence of
the pollutant in sewage sludge or data demonstrating a "safe" level for the pollutant in sludge. Following
submission of such a demonstration, EPA will review the data and determine whether or not it should
propose to amend the list of pollutants for which removal credits would be available.

        EPA has already begun the process of evaluating a number of pollutants for adverse potential to
human health and the environment when present hi sewage sludge. In May, 1993, pursuant to the terms
of the consent decree in the Gearhart case, the Agency notified  the United States District Court for the
    b    In the Round One sewage sludge regulation, EPA concluded, on the basis of risk assessments, that certain pollutants (see
Appendix G to Part 403) did not pose an unreasonable risk to human health and the environment and did not require the
establishment of sewage sludge pollutant limits.  As discussed above, so long as the concentration of these pollutant hi sewage
sludge are lower than a prescribed level, removal credits are authorized for such pollutants.
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District of Oregon that, based on the information then available at that time, it intended to propose 31
pollutants for regulation hi the Round Two sewage sludge regulations.  These are acetic acid (2, 4, -
dichlorophenoxy), aluminum, antimony, asbestos, barium, beryllium, boron, butanone (2-),  carbon
disulfide, cresol (p-), cyanides (soluble salts and complexes), dioxins/dibenzofurans (all monochloro to
octochloro congeners), endsulfan-H, fluoride, manganese, methylene chloride, nitrate, nitrite, pentachloro-
nitrobenzene, phenol, phthalate (bis-2-ethylexyl), polychlorinated biphenyls (co-planar), propanone (2-),
silver, thallium, tin, titanium, toluene, trichlorophenoxyacetic acid (2, 4, 5-), trichlorphenoxypropionic
acid ([2 - (2, 4, 5-)], and vanadium.

       The  Round Two regulations  are  not scheduled for  proposal  until December,  1999 and
promulgation in December 2001. However, given the necessary factual showing, as detailed above, EPA
could conclude before the contemplated proposal and promulgation dates that regulation of some of these
pollutants is not necessary. In those circumstances, EPA could propose that removal credits should be
authorized for  such pollutants before  promulgation of the  Round Two  sewage sludge regulations.
However, given the Agency's commitment to promulgation of effluent limitations and guidelines under
court-supervised deadlines, it may not be possible to complete review of removal credit authorization
requests by the time EPA must promulgate these guidelines and standards.
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REFERENCES
1.     U.S. EPA, Development Document for Effluent Limitation Guidelines and Standards for the
       Offshore Subcategory of the Oil and Gas Extraction Point Source Category, EPA 440/1-91/055,
       March 1991.

2.     Organic Chemicals, Plastics, and Synthetic Fibers Regulation, Monsanto Comments section 5,
       submitted December 13, 1985.

3.     Ray  and Engelhardt, Produced Water, Technological/Environmental Issues and  Solutions -
       Environmental Science Research, Volume 46, Tellez and Nirmalakhandan, "Bioreclamation of
       Oilfield Produced Wastewaters: Characterization and Feasibility Study", 1992.
                                           XV-9

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                                     SECTION XVI
         NON-WATER QUALITY ENVIRONMENTAL IMPACTS AND
                                  OTHER FACTORS
1.0   INTRODUCTION
       The elimination or reduction of one form of pollution has the potential to  aggravate other
environmental problems, an effect frequently referred to as cross-media impacts. Under sections 304(b)
and 306 of the Clean Water Act, EPA is required to consider 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.  EPA evaluated the non-water quality environmental impacts  on a. regional basis because
the different regions each have their own unique considerations. This section discusses the non-water
quality environmental impacts associated with these regulations for each waste stream, and other factors
such as safety.

       Table XVI-1 presents the  non-water quality impacts in terms  of air emissions and energy
requirements for the options selected for proposal (see Sections X, XI, and  XII).

2.0   DRILLING WASTES - COOK INLET
       The control technology basis for compliance with the options considered for the drilling fluids
and drill cuttings waste streams in Cook Inlet are transportation of drilling  wastes to shore for disposal
and grinding followed by injection at the platform. Therefore, hi addition  to energy requirements and
air emissions, adequate onshore disposal capacity for these wastes is critical hi assessing the options.
Safety and impacts of marine traffic on coastal waterways were other factors also considered.

2.1   ENERGY REQUIREMENTS AND AIR EMISSIONS
       Energy requirements  and air emissions resulting from the operation of equipment required for
transportation and disposal such as boats, cranes, trucks,  and earth-moving  equipment,  and for grinding
and injection at the platform were estimated by using emission factors  relating the production of air
                                           XVI-1

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                                                      TABLE XVI-1
                                    AIR EMISSIONS AND ENERGY REQUIREMENTS
                                 FOR THE PROPOSED OPTIONS BY WASTESTREAMS
Waste Stream Option
Fuel (BOE/yr)a
BAT
NSPS
Air Emissions (tons/yr)
BAT
NSPS
Drilling Wastes , t
Option 1: Zero Discharge; Cook
Inlet Tox. Limit of
30,000 ppm SPP
Option 2: Zero Discharge; Cook
Inlet Tox. Limit of
1,000,000 ppm SPP
Option 3: Zero Discharge All
0
1,738
2,285
0
0
0
0
8.69
12.47
0
0
0
Produced Water _ _ s
Option 1: BPT All
Option 2: Flotation All
Option 3: Zero Discharge; Cook
Inlet BPT
Option 4: Zero Discharge; Cook
Met Flotation
Option 5: Zero Discharge All
0
28,595
258,946
260,376
343,759
0
1,712
5,948
5,948
5,948
0
258.40
2,799.32
2,801.00
2,899.14
0
17.31
63.67
63.67
63.67
Treatment^ Workover, and Completion Fluids
Option 1: BPT
Options 2a and 2bb: Zero
Discharge or Gas Flotation
0
1,138
0
155
0
12.20
0
1.66
               * BOE (barrels of oil equivalent) is the sum of total diesel volume required and total natural gas volume converted to
                 equivalent oil volume by the factor: 1,000 scf = 0.178 bbl oil
               b Energy requirements and air emissions were calculated only for the portion of TWC fluids that would be commercially
                 disposed as described in the cost analysis in Section XE.
              pollutants to time of equipment operation and amount of fuel consumed.  The differential increases in fuel
              requirements and air emissions resulting from compliance with each control option are presented in Table
              XVI-2.  Detailed calculations of the totals presented in Table XVI-2 are included in Appendix XVI-1.
              The volumes reported In this table and the following pertinent sections are based  on total volume of
              drilling wastes that would requke disposal under each option from industry-provided drilling activity data
              projected over the 7  years following promulgation of this  rule (see  Section X, for drilling activity
              schedule).
_
                                                          XVI-2

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                                         TABLE XVI-2
AIR EMISSIONS AND ENERGY REQUIREMENTS FOR DISPOSAL OF DRILLING FLUIDS
                          AND DRILL CUTTINGS IN COOK INLET
                                     (from Appendix XVH-1)
Options
Option 1: Zero Discharge; Cook
Inlet Tox. Limit of 30,000 ppm
Option 2: Zero Discharge; Cook
Inlet Tox. Limit of 1,000,000
ppm
Option 3: Zero Discharge All
Waste "Volume*
(bH)
Barged" i
0
93,984
422,780
Injected
0
0
130,066
Total
0
93,984
552,846
Air Emissions
(tons/yr)°
0
8.69
12.47
Fuel
Requirements
€BOE/yr>a
0
1,738
2,285
a  The volume of wastes represents cumulative values for the 7 year period from 1996 through 2002.
b  Wastes barged are those .transported via barge (and/or supply boat) to shore and disposed of in landfills.
e  Annual air emissions represent the total estimated emissions divided by seven.
d  BOB (barrels of oil equivalents) is the sum of total diesel volume required and total natural gas volume converted to equivalent
   oil volume by the factor: 1,000 scf = 0.178 bbl oil. Values shown are the total estimated BOB divided by seven.
2.1.1   Energy Requirements
        Energy  requirements for  the treatment  options  considered  for  this rule were  calculated by
identifying those activities necessary to support onshore disposal of drilling wastes and injection at the
platform. The only landfill available for disposal of drilling wastes in Cook Inlet is privately owned and
operated.  Access  to this  landfill is limited to only the  two operators that own and operate it.  The
Kustatan landfill, which is located on the west side of Cook Inlet, is only operated for four months in the
summer because of climate conditions that are specific to Cook Inlet. Drilling wastes are first transported
by supply boats from the platform to a temporary storage facility on the east side of Cook Inlet to be
unloaded and temporarily stored.  Barges are used to transport drilling wastes from the east to the west
side of Cook Inlet.  Trucks are then used to transport the muds and cuttings to the landfill.1 For the other
operators in Cook Inlet, the  technology basis for Option 3 (zero discharge) is injection at the platform,
and  transportation and disposal to the lower contiguous United States for Option 2 (discharge, provided
limitations on free oil,  diesel oil,  cadmium, mercury and toxicity are met).  Transportation of drilling
wastes to the lower 48 states is by boat to the marine terminal on the east side of Cook Inlet and by truck
to a commercial disposal facility in Idaho.2
                                              XVI-3

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        Fuel requirements and air emissions were estimated for the following activities associated with
the transportation and disposal of drilling wastes in Cook Inlet:

        •      Supply boats and barges to transport the drilling wastes.
        •      Crane operation at the drilling sites and marine transfer stations to facilitate loading and
               unloading of the wastes.
        •      Trucks to transport the wastes from the marine terminal to the onshore disposal site.
        •      Earth-moving equipment at the disposal site to  facilitate land spreading  and landfill
               operations.
        •      Injection equipment for injection at the platform: transfer and injection pumps, grinder,
               agitator, and conveying equipment.

        Table XVI-3 summarizes the diesel fuel  requirements for the transportation and disposal of
drilling wastes either to the facility at Kustatan or to a commercial facility.  Detailed calculations for the
operating parameters can be found in Appendix XVI-1.  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, and with injection at the platform of drilling fluids and drill
cuttings.

2.1.1.1 Supply Boats and Barges
        In order to estimate the fuel requirements associated with marine transportation of drilling wastes,
energy requirements for supply boats and barges  were assumed to be the same.  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
        •      Supply boat capacity and usage
        •      Auxiliary electrical generation.

        This section details the assumptions made to estimate the fuel usage for each of these activities.
                                             XVI-4

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                                        TABLE XVI-3
          FUEL REQUIREMENTS FOR LAND DISPOSAL OF DRILLING WASTES
                                       IN COOK INLET
                                    (from Appendix XVII-1)
Source
Number Supply Boat Trips
Number Barge Trips
Auxiliary Generator (hrs/trip)
Crane (bis)
Number Truck Trips
Wheel-Tractor (hrs)
Track-type Dozer (hrs)
Total
Option 2
Operating
Parameter1'
51.75
26.42
48
768
749
440
880
-
Diesel
GAL*
38,000
5,280
7,450
6,390
433,730
730
19,360
510,940
BOE/yrc
129
18
25
22
1,475
2.5
66
1,738
Option &
Operating
Parameter^
233
155.43
. 48
3,699
4,404
360
720
-
Diesel
GAL*
170,910
31,090
33,520
30,810
11,010
600
15,840
293,780
BOE/yr*
581
106
114
105
37
2
54
999
a  Additional BOEs expended for injection are not shown on this Table for Option 3.
b  Represents the cumulative values for the 7 year period from 1996 to 2002.
c  BOE (barrels of oil equivalent) per year is the total diesel volume required converted to equivalent oil volume by the factor: 1
  BOE = 42 gal. Values shown are the estimated BOE divided by seven.

       •       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.3

                      Fuel Consumption: 130 gallons of diesel per hour.4

                      Boat Speed:  The average supply boat speed during transit is 10 knots.3  The
                      average barge speed is  6 mph.5

                      Average Distance: The average round-trip distance for the supply boats to go
                      from platforms to the  dock on the east side of Cook Inlet is 50 miles.  The
                      average round-trip distance for barges to go to the west side of Cook Inlet is 50
                      miles (see Appendix XVI-1).

       •       Maneuvering Fuel Consumption: Supply boats are estimated to maneuver at the platform
               for an average of one hour per visit. The maneuvering fuel use factor is 15 percent of
               full throttle fuel consumption.6

       •       Idling Fuel Consumption: Due to ocean current and wave action, boats must maintain
               engines  idling while at platforms unloading empty cuttings boxes and loading drilling
               fluids and boxes. The total average time idling on station at the drill site for loading is
               5.7 hours per visit. This is based on the crane operating time of 4.7 hours to transfer
                                             XVI-5

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                            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 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 hi port.

                            The average in port tune for unloading drilling fluids and drill  cuttings, tank cleanout,
                            and demurrage is  24 hours per supply boat trip.3 The boat  engines would be shutdown
                            during this period.  EPA assumed that while in port, 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 load6, and consumes
                            6 gallons of diesel fuel per hour.3
                            Supply Boat Capacity and Usage:  An offshore supply boat typically has a deck space of
                            130 feet long by 28 feet wide and can store approximately 227 cuttings boxes (8 barrel)
                            on deck.7

                            The drilling platform or rig has sufficient available deck  area to store excess drilling
                            fluids without affecting drilling operations.8  The cuttings generation rate is the highest
                            during the first phase of drilling due to the large borehole  diameter, and the volume of
                            drill cuttings are the limiting factor for boat capacity. During the last stages of drilling,
                            the drill cuttings  generation rate subsides as the borehole diameter decreases.   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.

                            EPA estimated that for Option  3, a total of 233 boat trips would be required for drilling
                            operations in Cook Inlet.  For Option 2, a total of 51.75 boat trips would be required to
                            transport drilling  waste (see Table XVI-3).  Appendix XVI-1 presents the  detailed
                            calculations used to arrive at these values.

                            Barge Capacity and Usage: Barges are required to transport the combined drilling wastes
                            from the east side of Cook Inlet to  the west side for disposal.  A typical barge that
                            operates in Cook Inlet has a deck space of 150 feet long by 45 feet wide and can store
                            approximately 340 boxes cuttings boxes (8 barrels) on deck.9  Distance from the east side
                            of Cook Inlet to  the west side, near  the Trading Bay facility  was estimated to be
                            approximately 25 miles. Boxes are unloaded on the beach near the Trading Bay facility.
_
                                                           XVI-6

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2.1.1.2  Cranes

       Cranes used to load and unload cuttings boxes at the drill site and in port 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.6

       •       Fuel Consumption:  8.33 gallons of diesel fuel per hour.4

       •       Lift Capacity:  10 lifts per hour.3 The unloading of 227 empty cuttings boxes or loading
               227 full cuttings boxes on the supply boat requires a minimum of 5.7 hours (based on
               an assumed 4 boxes per  lift).


2.1.1.3  Trucks

         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:  10-12  boxes of drilling fluids and drill cuttings.10  Capacity used for
               combined wastes is 96 bbl for short distance and 65 bbl for long distance.2

       •       Fuel Consumption:  4 miles per gallon of diesel fuel.3

       •       Distance:  The average round trip distance  between  the barge docking area and the
               disposal site is estimated at 10 miles for operators disposing of the drilling wastes on the
               west side of Cook Inlet (see Appendix XVI-1). For all the other operators, an average
               round trip of  5,000 miles is used.2


2.1.1.4  Land Disposal Equipment

       The use of land-spreading equipment at the disposal site was based on the drilling waste volumes

and the estimated 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 that
               8 hours of tractor operation are required to grade the drilling waste volume from one
               well.  The estimated fuel consumption rate for a wheel tractor is 1.67 gallons of diesel
               fuel per hour.3

        •      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.3
                                             XVI-7

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2. 7.1.5 Grinding and Injection Equipment

       The grinding and injection equipment, which constitutes the technology basis for the zero

discharge option for those operators that do not have access to a landfill in Cook Inlet, is comprised of

the cuttings processing equipment and of the injection pumps.  The cuttings processing equipment power

and fuel requirements were estimated based on the following horsepower requirements11:


              Grinder (500 KVA Transformer'):

              2-150 HP motors at 480V
              1-10 HP Auger motor
              Additional lights/heating 100 KVA

              Cutting Transfer Equipment:

              2-30 HP Disk flow motors
              1-10 HP Hydraulic pump
              Steam as required

              Dewatering Unit:

              2-5 HP Shaker motors
              1-10 HP Agitator
              1-45 HP Dewatering centrifuge
              1-10 HP Underflow pump
              2-30 HP Disk flow pumps
              1-30 HP Galliger pump
              4-1/2 HP motors

The  power and fuel requirements for the injection equipment were  estimated based on one 500-hp

injection pump rated at 5 bbl/min.1


       The equipment usage (hrs per well) was estimated based on the average time required to drill a

new  well or a recompletion.  Details of these calculations are presented in Section X, Appendix X-l.


       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 (set) of natural gas per horsepower-hour (hp-hr).12  Table XVI-4 summarizes the fuel consumption

for the grinding and injection system.  Details for these calculations are presented in Appendix XVI-1.
                                           XVI-8

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                                         TABLE XVI-4
                 FUEL REQUIREMENTS FOR GRINDING AND INJECTION
                                     (from Appendix XVH-1)

Number
Wells2
Horsepower •
Reqmt's
(np/weBJ
Operation
(hrs/wetl) j
Total
Usage*

-------
                                          TABLE XVI-5
                         UNCONTROLLED EMISSION FACTORS12'13'3
.- s
Equipment
Supply Boats
(lb/1,000 gal)
Idle
Transit
Cranes
(g/bhp-hr)
Trucks (g/mile)
Wheel Tractor
(Ib/hr)
Track-type
Dozer (Ib/hr)
Auxiliary Diesel
Engines
(lb/1,000 gal)
Natural Gas
Engines
(g/hp-hr)
Reciprocating
Turbine
Nitrogen
Oxides
(NOJ
419.6
391.7
14.0 '
11.44
1.269
0.827
469
11.0
1.7
Total
Hydrocarbons
(THC)
22.6
16.8
1.12
2.53
0.188
0.098
37.5
4.4
0.055
Sulfur
Dioxide

33.0
33.0
1.0
NA
0.136
0.058
33.5
NA
NA
1 All values shown are cumulative totals for the 7 year period from 1996 through 2002.
* 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 2,000 g/106 scf12.
  NA — Not Applicable
emission factor of 391.7 lb/1,000 gal of diesel was used.  The total diesel fuel requirement for supply
boats in transit was  estimated to be 131,590 gal (see Appendix XVI-1).  The total nitrogen oxides
emissions resulting from this activity are:

               (391.7 lb/1000 gal)x(131,590 gal)x(l ton/2000 lb/7 yrs) = 3.68 tons/yr

        The operation of the grinding and injection equipment to dispose of the drilling wastes under the
zero discharge option require a total power of 5,324,016 hp-hr.  For a natural gas driven turbine, an NOX
emission factor of 1.7 g/hp-hr was used.  The total nitrogen oxides emissions resulting from this activity
are:
               (1.7 g/hp-hr)x(5,324,016 hp-hr)x(l ton/908,000 g/7 yrs) =  1.42 tons/yr
                                              XVI-10

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                                  TABLE XVI-6
           AIR EMISSIONS ASSOCIATED WITH PROPOSED OPTIONS FOR
           EXISTING SOURCES FOR DRILLING WASTES IN COOK INLET
                               (from Appendix XVH-1)

NOx
THC
SO2
CO
TSP
Total
Option 2 {tons/yr)
Supply boats
Barges
Supply Boat Cranes
Barge Cranes
Trucks
Wheel Tractor
Dozer/Loader
Grinding/Processing Equipment
Injection Equipment
Total
1.245
0.148
0.176
0.054
3.123
0.040
0.052
0.000
0.000
4.84
0.062
0.006
0.014
0.004
0.691
0.006
0.006
0.000
0.000
0.79
0.088
0.011
0.012
0.004
0.000
0.003
0.005
0.000
0.000
0.12
0.236
0.026
0.038
0.012
2.367
0.113
0.013
0.000
0.000
2.80
0.101
0.012
0.013
0.004
0.000
0.004
0.004
0.000
0.000
0.14
1.733
0.203
0.252
0.077
6.180
0.166
0.079
0.000
0.000
8.69
Option 3 (tons/yr)
Supply boats
Barges
Supply Boat Cranes
Barge Cranes
Trucks
Wheel Tractor
Dozer/Loader
Grinding/Processing Equipment
Injection Equipment
Total
5.598
0.870
0.792
0.317
0.079
0.033
0.043
1.366
0.058
9.15
0.280
0.037
0.063
0.025
0.018
0.005
0.005
0.044
0.002
0.48
0.397
0.063
0.053
0.021
0.000
0.002
0.004
0.002
0.000
0.54
1.064
0.174
0.171
0.069
0.060
0.092
0.010
0.040
0.002
1.68
0.456
0.073
0.057
0.023
0.000
0.003
0.003
0.000
0.000
0.61
7.795
1.217
1.135
0.454
0.157
0.136
0.065
1.452
0.062
12.47
2.2   SOLID 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, as already discussed, spent drilling fluids and the
                                     XVI-11

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associated cuttings would be disposed of at onshore disposal sites or injected underground to comply with
the proposed options.

       There are currently no commercially operating disposal sites in Cook Inlet accepting offshore
drilling wastes.  The only land disposal facility accepting drilling wastes from Cook Inlet operations is
privately owned and operated.  The lack of commercial disposal sites would require operators that do not
own a land disposal facility to either transport the drilling wastes to  the nearest known  commercial
disposal facility located in Idaho or inject the drilling wastes into underground formations.

       Capacity estimates for the disposal facility at Kustatan show that this landfill has enough storage
capacity to accept the volume of drilling wastes (422,780 bbl) that would be generated under the no
discharge limitation, from the platforms that it now serves.14  The solid waste disposal facility at Kustatan
has 16 modules.  Each module consists of four cells, each with a storage capacity of 9,620 bbl.15  The
total capacity is 615,680 bbl (16 x 4 x 9,620).  To date, only two cells have  been used, leaving an
available capacity of 596,440  bbl.  The volume of drilling wastes generated under the zero discharge
option represents about 71 percent of the excess available capacity at Kustatan.

       Under the limitations of Option 2, the total estimated volume of drilling wastes requiring land
disposal is 93,984 bbl (see Table XVI-2).  Of this total volume of drilling wastes, 22,112 bbl over the
next 7 years, or 3,159 bbl/yr (see Section X) were estimated for disposal to commercial facilities in the
lower 48  states.   Because of  this small volume of wastes,  EPA  assumed that  there is ample landfill
disposal capacity in the lower 48 states, such as Idaho and Oregon.  For example, the landfill in  Idaho
is a RCRA permitted facility with a capacity of 120 tons/yr to the year  2018.16  The landfill in Oregon
is a RCRA permitted facility with an available capacity of about 4,000,000 bbl.17

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 Cook Inlet
        EPA estimates that a total of 233 boat trips would be required to comply with a zero discharge
requirement.  This estimate is for  all drilling that will take place in the next 7 years after expected
                                            XVI-12

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promulgation of this rule.  Thus, the 233 boat trips equate on the average to approximately 33 additional
boat trips per year.  EPA does not expect this to cause traffic problems in Cook Inlet.

       In fact, it will serve to provide service companies with additional work.  EPA has not estimated
expected job gains  associated with this rulemaking.  However, job gains could be realized due to
increased boat trips.

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
similar to the additional activities required should a zero discharge limitation be imposed in Cook Inlet.18

       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 hi Lines
        •      Pinched/crushed
        •      Unknown
        •      Not classified.

        The PCAS file is composed of U.S. Coast Guard  2692 forms  and contains the following
 information: case number, last name, first name,  date of birth, status, nature of the accident, nature of
                                            XVI-13

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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 tune of the accident, the body of water, the year the vessel was built, the date
of  the casualty,  industry time,  company time, name  of  the vessel, operating company, vehicle
identification number, flag,  service, use, design, length, gross tonnage, time on duty, and case year.
Form 2692 is entitled, "Report of Marine Accident, Injury or Death."  The 2692 form is included in the
PCAS file based on the  occurrence of the following:

       •       A death
       •       An injury to five or more persons hi 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 hi 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  XVI-7 presents the
primary causes and classification of accidents on MODUs and OS Vs.

       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".19 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 of 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.
                                            XVI-14

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                                    TABLE XVI-7

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
        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.

        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  discernable
        increase in casualties attributable to onshore disposal of drilling wastes is anticipated.
                                        XVI-15

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        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 in Cook Inlet are used for platforms while barges are used in summer
to transport drilling wastes to Kustatan for disposal. Containers or boxes are used to hold the excess
and/or used muds and cuttings and have  an approximate capacity of 12 barrels.  Cranes load these
containers onto and off 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.

3.0    PRODUCED WATER
                     *
       In assessing non-water quality environmental impacts for produced water, EPA projected energy
requirements and air  emissions associated with the regulatory options considered, and evaluated the
potential for degradation of underground sources of drinking water.  The  following is a description of
the non-water quality  environmental impacts for the Gulf of Mexico and Cook Inlet, and a summary of
the estimated impact levels for each option considered.

3.1    ENERGY REQUIREMENTS AND AIR EMISSIONS
       Annual energy requirements and resulting air emissions for the control options considered by EPA
are presented in Table XVI-8 for both new  and existing sources.  Estimates are presented incremental to
current BPT limitations and thus  represent the expected  increase above current emissions levels and
energy consumption.  Detailed calculations of the totals in Table XVI-8 are provided in Appendix
XVI-2.

       As can be seen from Table XVT-8, the option requiring zero discharge  of all produced water
greatly increases air emissions and fuel requirements  as compared to the "gas  flotation all" option. This
is due primarily to the energy required to operate the injection pumps.

3.1.1    Energy Requirements
         This section provides a detailed discussion on the development of fuel  requirements for each
treatment technology  hi both regions, based on the volume of produced  water  discharged from each
facility type.  The methodology which is described  hi the following sections,  was applied to estimate
energy requirements for both existing and new sources.
                                            XVI-16

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                                        TABLE XVI-8
       NON-WATER QUALITY ENVIRONMENTAL IMPACTS PRODUCED WATER
                                    (from Appendix XVH-2)
, , Option
Option 1: BPT All
Option 2: Flotation All
Option 3: Zero Discharge;
Cook Inlet BPT
Option 4: Zero Discharge;
Cook Inlet Flotation
Option 5: Zero Discharge All
Fuel Requirements
(BOE/y*)a
BAT
0
28,595
258,946
260,376
343,759
NSPS
0
1,712
5,948
5,948
5,948
Air Emissions
(tons/year)
BAT
0
258.40
2,799.32
2,801.00
2,899.14
NSPS
0
17.31
63.67
63.67
63.67
* BOB (barrels of oil equivalents) is the sum of the total diesel volume and total natural gas volume converted to equivalent oil
  volume by the factor: 1,000 scf = 0.178 bbl oil.
3.1.1.1 Small-Volume Facilities - Gulf of Mexico
        As described in Section XI, small-volume facilities in the Gulf of Mexico are those facilities that
will transport the produced water to a commercial  facility for disposal under any  option.  Energy
requirements for these facilities were calculated by  identifying those activities necessary to support
disposal of produced water.  Those activities requiring fuel consumption include:
        •   Barges to transport the produced water from facilities with water access to the commercial
           facility.  One barge of 3,000 bbl capacity is used to service multiple facilities.
        •   Trucks to  transport the produced water from facilities with land access  to a commercial
           facilities.
        •   Vacuum pumps and compressors are only used at  the commercial facility to unload the
           barges.  Barge loading is by gravity feed.

        The following sections present the assumptions and the methodology used to estimate the energy
required by various transportation and handling activities associated with commercial disposal of produced
water from small-volume facilities in the Gulf of Mexico.
                                            XVI-17

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3.1.1.1.1   Facilities With Water Access
        The fuel usage due to operation of barges to transport produced water to commercial facilities
for disposal was calculated by estimating the fuel consumption required by tugs to pull the barges, the
distance barges have to travel, and the fuel consumption by vacuum pumps and compressors to unload
the barges.  The location of each small-volume facility with water-access was determined from oil and
gas maps.  The number of boat trips was estimated based on the onsite storage capacity of each facility,
the distances between facilities, the distance from port to the first facility,  and the distance from the last
facility to the commercial disposal facility. This section details the assumptions made to estimate the fuel
usage for each of these activities.

        •  Barge capacity is 3,000 bbl. Each barge will service multiple facilities to full capacity.
        •  Distances between facilities were estimated to be on the average 10 miles.20
        •  Distance from port to first facility was assumed to be 50 miles.21
        •  Traveling speed for barge and tug is 6 miles per hour.5
        •  Time to dock at each facility is 1 hour.21
        •  Time to leave each facility is 15 minutes.22
        •  The maximum time to load or unload a barge is 8 hrs.5
        •  Distance from last facility to the disposal facility is 50 miles.21
        •  Fuel  consumption for the tug is 24 gal/hr.4   Tug engines are shut-down  if the time to
           load/unload the barge is greater than 30 minutes.
        •  A 4-inch vacuum pump with a pumping capacity of 60,000 gal/hr and compressor will be
           used to unload the barge. The average diesel fuel consumption for the pump and compressor
           is 0.6 gal/hr  and 3.5 gal/hr, respectively.4

        The annual diesel fuel consumption associated with transportation of produced water from small-
volume facilities with water access to commercial disposal facilities was calculated based on yearly barge
trip cycles.  A total of 51 barge cycles per year was estimated based on the number of small-volume
facilities, each facility's  onsite storage capacity, and the round-trip distances traveled by a  barge to and
from port.22  Table XVI-9 summarizes the fuel consumption for all existing small-volume facilities with
water access for both produced water control options.
                                             XVI-18

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                                       TABLE XVI-9
  ENERGY REQUIREMENTS FOR COMMERCIAL DISPOSAL OF PRODUCED WATER
            FROM EXISTING SMALL-VOLUME WATER ACCESS FACILITIES
                                IN THE GULF OF MEXICO
Option
Gas Flotation
Zero
Discharge
Number
SmaflrVoL
facilities
9
12
Vol. PW
Barged
bbl/yr)
65,335
155,490
Diesel Fuel Consumption (gal/yr)
Tug&Barge
204,752
224,786
Pump
64.3
64.3
Compressor
374.9
374.9
Total
205,191
225,225
Total
Fuel

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                                       TABLE XVI-10
   ENERGY REQUIREMENTS FOR COMMERCIAL DISPOSAL OF PRODUCED WATER
             FROM EXISTING SMALL-VOLUME LAND ACCESS FACILITIES
                                EN THE GULF OF MEXICO
Option
Gas
Flotation
Zero
Discharge
Number
Small-Vol. ;
Facilities
41
38
Vol. PW
Barged
(bbl/yr)
457,710
377,045
Diesel Fuel Consumption (gsuVyr):
Truck
230,880
190,200
Tug&Barge
0
0
Pump
0
0
Compressor
0
0
Total
230,880
190,200
Total
BOE/yr"
5,497
4,529
  BOE (barrels of oil equivalent) per year is the total diesel volume required converted to equivalent oil volume by the factor: 1
  BOB = 42 GAL.
3.7.1.2 Medium/Large-Volume Facilities - Gulf of Mexico
       As  described in Section XI, medium/large-volume facilities in the Gulf of Mexico are those
facilities that will treat and discharge or inject the produced water onsite. Energy requirements for these
facilities were calculated by identifying those activities necessary to support the treatment and injection
of produced water.

       The following sections present the assumptions and the methodology used to estimate the energy
required by the two control options for produced water from medium/large-volume facilities in the Gulf
of Mexico.  '

3.1.1.2.1   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 hi 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 including the feed pumps will be run by electricity. The electric
           power will be supplied by natural gas driven generators.
                                          XVI-20

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       •   For existing sources, fuel requirements and air emissions for gas flotation represent only the
           additional electricity required above 25 horsepower that must be generated for operation of
           gas flotation systems.
       •   For new sources, the fuel requirements and air emissions represent the electricity required
           by each gas flotation system as an add-on to BPT treatment.
       Energy requirements for commercially available gas flotation systems were obtained from
equipment vendors for systems of four different sizes ranging in treatment capacity from 1,700 to 77,000
barrels per day (BPD).24  Electricity requirements in kilowatts (kW) for each unit were calculated using
0.75 kW/hp as a conversion factor. 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).12 The usage rate,
in hours per year (hrs/yr), for these 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 = 1.02 million standard cubic feet (scf) of natural gas.   Table XVI-11 presents unit
energy and fuel requirements for the four gas flotation units evaluated.
                                       TABLE XVI-11
                  FUEL REQUIREMENTS FOR GAS FLOTATION UNITS23
Feed Rate (bpd)
Power Required (hp)
Electricity Required (kW)
Fuel Required (scf/yr)
1,700
12.25
9.2
1.02xl06
1%000
20.5
15.4
1.7xl06
25,000
40.5
30.4
3.37xl06
77,000
100.5
75.4
8.36xl06
       The energy requirements for these four units were used to predict the energy requirements for
the nine design systems described in Section XI. In addition, the total design system power requirements
include the power required to operate the feed pumps. Natural gas fuel requirements were only calculated
for those design systems that treat more than 5,000 bpd of produced water, or require more than 25 hp
total to operate.  For those design systems that require less than 25 hp to operate, it was assumed that
existing onsite power generation equipment can handle an additional load of no more than 25 hp, at no
additional cost. A natural gas driven generator will supply the energy required to operate systems that
                                            XVI-21

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treat more than 5,000 bpd of produced water.  The power and fuel requirements for the complete gas
flotation systems designed to treat from 200 to 80,000 bpd of produced water are presented in Table XVI-
12.
                                      TABLE XVI-12
            FUEL REQUIREMENTS FOR DESIGN GAS FLOTATION SYSTEMS
                                 FOR EXISTING SOURCES
Feed Rate (bpd}
Power Required (hp)
Electricity Required
(kW)
Fuel Required
(MMscf/yr)
200
12.2
9.1
0
1,000
13.4
10.0
0
3,000
15.3
11.5
0
5,000
22.8
17.1
0
10,000
36
0
3.0
15,000
49
0
4.1
25>00»
75
0
6.2
40,000
115
0
9.6
8
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                                       TABLE XVI-13
                   POWER UTILIZATION AND FUEL REQUIREMENTS
                     FOR PRODUCED WATER TREATMENT OPTIONS
                                   (from Appendix XVH-2)
Option
BAT1
Power
Usage
(hp-hr/yr)
Diesel
{gai/yr)
Natural
Gas
(Msef/jr)
Total
Fuel
(BQE/yrf
SSfSJPSfc
Power
Usage
(hp-hr/yr)
Diesel

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                                      TABLE XVI-14
             ENERGY REQUIREMENTS FOR DESIGN INJECTION SYSTEMS
                  FOR EXISTING SOURCES IN THE GULF OF MEXICO
                                   (from Appendix XVH-2)

' Design Mow (bpd)
. 200
' 500 '
1,000
5,000
10,000
18,000
30,000
42,000
" Facilities With Water Access
Power Required (hp)
Electricity Required (kW)
Fuel Required (MMscf/yr)
9
6.8
0
19
14.3
0
41
1.5
3.25
176
4.5
14.1
352
9
28.3
704
18
56.6
1,068
18
86.9
1,614
18
132.3
Facilities With L^d Recess
Power Required (hp)
Electricity Required (kW)
Fuel Required (MMscf/yr)
8
6
0
18
13.5
0
39
0
3.25
170
0
14.1
340
0
28.3
680
0
56.6
1,020
0
84.9
1,530
0
127.3
natural gas fuel requirements shown represent energy requirements above 25 hp.

       In order to predict the energy requirements and fuel usage for treatment systems that require more
than 25 hp to operate (or facilities with water access and with flows greater than or equal to 700 bpd, and
facilities with land access and flows greater than 727 bpd)  other than the  design flows, two linear
mathematical models were developed through a regression analysis, of the form:
                                HP = 0.0372 x (flow) - 11.22
                                HP = 0.0359 x (flow)-3.10
(water access)
 (land access)
       Energy requirements for each facility with flows greater than 700 bpd and 727 bpd for water- and
land-access, respectively, were calculated using the linear models based on each facility location and the
produced water flow. Table XVI-13 summarizes the power usage (hp-hr/yr) and fuel requirements for
all BAT and NSPS options considered for produced water discharges in the coastal region.

3.1.1.3  Cook Inlet
       For the eight discharging facilities, energy requirements and air emissions were estimated for
equipment that is required hi addition to existing equipment to meet the limitations of the three regulatory
                                          XVI-24

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options considered to control discharges of produced water.  The equipment required to comply with the
control options for produced water in Cook Inlet is presented in Section XI. Table XVI-13 summarizes
the power and fuel requirements to comply with the treatment options for the control of produced water
discharges in Cook Inlet.  Detailed calculations of the totals presented  in Table XVI-13 are provided
Appendix XVI-2.

3.1.2   Air Emissions
       The air emissions were calculated for each discharging facility by taking the product of 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 emission factors for both natural
gas-fired reciprocating  engines  and turbines.26   Table XVI-5 presents the emission factors used in
calculating air emissions for all treatment technologies considered to control produced water discharges
in the coastal  Gulf of Mexico area. Air emissions for medium/large volume facilities  hi the Gulf of
Mexico were estimated from emission factors for reciprocating engines.  According to industry sources,
almost all engines used at tank batteries  and compressor stations are reciprocating internal combustion
engines.27 Air emissions for discharging facilities in Cook Inlet were estimated from emission factors for
natural gas driven turbines.1 Table XVI-15 summarizes the air emissions for all options for both the Gulf
of Mexico and Cook Inlet regions.  Detailed calculations of the totals in Table XVI-15 are provided hi
Appendix XVI-2.

       In order to determine the significance of the air emission estimates, EPA investigated the amount
of air emissions associated with subsurface injection compared to the total  air emissions generated by a
typical production operation prior to the installation of an injection system.  EPA obtained air emission
estimates from an air permit application for an average size oil and gas production tank battery and a gas
compressor  station hi Louisian