DECOMMISSIONING AND REMOVAL OF OIL AND GAS FACILITIES ... · W.S. (Bill) Griffin, Jr., Phillips...

•OCS StudyMMS 98-0023

PROCEEDINGS: PUBLIC WORKSHOP

DECOMMISSIONING AND REMOVALOF OIL AND GAS FACILITIES

OFFSHORE CALIFORNIA:RECENT EXPERIENCES AND FUTURE

DEEPWATER CHALLENGES

Ventura, CaliforniaSeptember 23-25, 1997

Sponsored by:U.S. Department of the Interior, Minerals Management ServiceCalifornia State Lands Commission

Co-Sponsored by:E & P ForumChevron, USA, Inc.Torch Operating Company

Hosted by:University of California, Santa BarbaraUniversity of California, Berkeley

Edited by:Frank Manago, Minerals Management ServiceBonnie Williamson, University of California, Santa Barbara

•OCS StudyMMS 98-0023

PROCEEDINGS: PUBLIC WORKSHOP

DECOMMISSIONING AND REMOVAL OF OIL AND GASFACILITIES OFFSHORE CALIFORNIA:

RECENT EXPERIENCES AND FUTURE DEEPWATER CHALLENGES

Sponsored by:U.S. DEPARTMENT OF THE INTERIOR, MINERALS MANAGEMENT SERVICE

andCALIFORNIA STATE LANDS COMMISSION

Co-Sponsored by:E & P FORUM

CHEVRON, USA, INC.TORCH OPERATING COMPANY

Doubletree HotelVentura, California

September 23-25, 1997

Edited by:Frank Manago

andBonnie Williamson

Prepared by:Southern California Educational Initiative

Coastal Research CenterMarine Science Institute

University of California, Santa BarbaraSanta Barbara, CA 93106

May 1998

Disclaimer

This document was prepared by the Southern California Educational Initiative which is jointly funded bythe Minerals Management Service and the University of California, under Minerals Management ServiceCooperative Agreement Number 14-35-0001-30761. The report has not been reviewed by the Service foreither content or compliance with its editorial standards. The intent of the proceedings is to record whattranspired at the workshop. Its publication should not be interpreted as necessarily representing theofficial policies, either expressed or implied, of the U.S. Government or any other sponsor or cosponsor.Issue papers, plenary speeches and presentations were edited for form only.

Availability of Report

A limited number of copies of this report will be available for distribution. To order, please contact:Bonnie Williamson

Marine Science InstituteUniversity of California

Santa Barbara, California 93106phone: 805-893-2051

fax: 805-893-3777email: [email protected]

This document is also available via FTP at the MMS Pacific Region web site:ftp://www.mms.gov/pub/pacific/

Citation

The suggested citation for these proceedings is:

Manago, F. and B. Williamson (eds.) Proceedings: Public Workshop, Decommissioning and Removal ofOil and Gas Facilities Offshore California: Recent Experiences and Future Deepwater Challenges,September 1997. MMS OCS Study 98-0023. Coastal Research Center, Marine Science Institute,University of California, Santa Barbara, California. MMS Cooperative Agreement Number 14-35-0001-30761. 269 pp.

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SPONSORSHIPS

The Minerals Management Service and the California State Lands Commissionsponsored the workshop.

In addition, the following organizations made financial contributions to the workshop:��Gold E & P Forum�Silver Chevron, USA, Inc.�Bronze Torch Operating Company

The following made in-kind contributions:• UC Coastal Toxicology Program• Ecomar, Inc.• Twachtman, Snyder & Byrd, Inc.

ACKNOWLEDGEMENTS

Acknowledgements are extended to all the participants involved in this very successfulworkshop.

BACKGROUND

There are a total of 27 oil and gas platforms and approximately 200 miles of associatedpipelines located off the coast of southern California. Of the 27 platforms, four are located instate tidelands within 3 miles of the coast and 23 on the Federal Outer Continental Shelf(OCS). There are also six artificial islands located in State tidelands that have beenconstructed to recover oil and gas resources. As the end of the service life approaches forthese facilities, plans for decommissioning and removing the facilities must be developed.

In 1994, the Minerals Management Service (MMS) and the California State LandsCommission (SLC) jointly sponsored a workshop to familiarize the public with thedecommissioning process and disseminate information on upcoming projects. Since thattime several major decommissioning projects have been completed and several others areunderway or moving forward. This includes a recently-announced project that could involvethe decommissioning and removal of as many as five OCS platforms and two associatedonshore processing facilities. The decommissioning and removal of these platforms, whichare located in water depths ranging from 318 to 740 feet, will present significant technical,environmental and material disposal challenges.

To facilitate the continuation of public involvement and participation in the decommissioningprocess, the MMS and SLC decided to sponsor a 1997 workshop to review recentexperiences and discuss future deepwater decommissioning challenges.

WORKSHOP GOALS

The goals of this workshop were to disseminate information to the public on the results ofrecently completed projects, identify issues of concern, and elicit recommendations on futureCalifornia decommissioning operations and associated technical, environmental, socio-economic and disposition issues.

WORKSHOP ORGANIZING COMMITTEE

Frank Manago , Minerals Management Service, Pacific OCS RegionJohn Smith , Minerals Management Service, Pacific OCS Region

Pete Johnson , California State Lands CommissionMarina Voskanian , California State Lands Commission

Mark Carr , Department of Biology, University of California, Santa CruzBonnie Williamson , Marine Science Institute, University of California, Santa Barbara

WORKSHOP SESSION CO-CHAIRS

Technical Workshop Session

Robert Byrd , Co-Chair , Twachtman, Snyder & Byrd, Inc.Marina Voskanian , Co-Chair , California State Lands Commission

Environmental Workshop Session

Bill Douros , Co-Chair , Santa Barbara County, Energy DivisionSimon Poulter , Co-Chair , Padre Associates, Inc.

Disposition Workshop Session

Mark Carr , Co-Chair , University of California, Santa CruzJohn Stephens , Co-Chair , Vantuna Research Group and

University of California, Los Angeles

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TABLE OF CONTENTS

Workshop Program .................................................................................................................... 1

Workshop Steering Committee ................................................................................................... 5

Workgroup Chairs and Members ................................................................................................ 6

Workshop Presentations

PLENARY ADDRESSESIntroductory Remarks, Carolita Kallaur, Associate Director, Offshore, Minerals

Management Service...................................................................................................... 9Pacific Region Decommissioning Update, Outlook, and Perspectives ,

Tom Dunaway, Minerals Management Service, Pacific OCS Region ........................... 11California State Lands Commission Management Responsibility and RecentDecommissioning Experience , Paul Mount, California State Lands Commission ............... 13Update on Decommissioning Issues , Bud Danenberger,

Minerals Management Service, Headquarters ............................................................... 14California State Lands Commission: Decommissioning Policy and

Regulations , Dwight Sanders, California State Lands Commission ............................. 16Regulatory Framework and Environmental Review Process for the Decommissioning

of Oil and Gas Facilities, Simon Poulter, Padre Associates, Inc. ................................ 18International Developments: Lessons Learned and Need for Public Input ,

W.S. (Bill) Griffin, Jr., Phillips Petroleum Company ....................................................... 20

TECHNICAL SESSIONThe Plugging Process: Securing Old Gas and Oil Wells for the Protection of

the Environment , Steve Fields, California Dept. of Conservation, Division of Oil,Gas & Geothermal Resources and Max Martin, Twachtman, Snyder & Byrd, Inc. ........ 25

Offshore Production Facilities: Decommissioning of Topside ProductionEquipment , Dr. Peter Prasthofer, Offshore DecommissioningCommunications Project ................................................................................................ 38

Removal and Disposal of Deck and Jacket Structures,Andy Culwell, American Pacific Marine, Inc. .................................................................. 48

Pipeline and Power Cable Decommissioning , Andy Culwell, American PacificMarine, Inc. and Jack McCarthy, Minerals Management Service,Pacific OCS Region........................................................................................................ 66

Site Clearance and Verification , Jack McCarthy, Minerals Management ServicePacific OCS Region ....................................................................................................... 74

Decommissioning of Onshore Facilities: Technical Issues , Luis Perez, SantaBarbara County Department of Planning and Management, Energy Division................ 83

ENVIRONMENTAL SESSIONAir Quality , Peter Cantle, Santa Barbara County Air Pollution Control District ....................... 93Platform Decommissioning: Commercial and Recreational Fisheries Effects ,

Dr. Craig Fusaro, Joint Oil / Fisheries Liaison Office ..................................................... 95The Commercial Fishing Industry in South/Central California , Dr. Craig Fusaro,

Joint Oil/Fisheries Liaison Office and John Richards, UC Santa Barbara...................... 97Fisheries Impacts of Explosives Used in Platform Salvage ,

Dr. Ann Bull, Minerals Management Service, Gulf of Mexico OCS Region ................... 104Effects of Decommissioning Activities on Marine Benthos ,

Leray deWit, DeWit Consulting, Inc. .............................................................................. 105

DISPOSITION SESSIONCommercial Fisheries: Long-term Effects of Offshore Oil and Gas Facilities

Decommissioning , John Richards, UC Santa Barbara ................................................ 111Ecological Consequences of Alternative Decommissioning Strategies for

POCS Offshore Facilities , Dr. Mark Carr, UC Santa Cruz, Dr. GrahamForrester, UC Los Angeles and Dr. Michael McGinnis, UC Santa Barbara ................... 116

Effect of Offshore Oil Platform Structures on the Distribution Pattern ofCommercially Important Benthic Crustaceans, with Emphasis on theRock Crab , Dr. Mark Page and Dr. Jenny Dugan, UC Santa Barbara .......................... 119

Enhancement of Platforms as Artificial Reefs , Dave Parker,California Department of Fish and Game....................................................................... 122

Long-term Socio-economic Effects of Onshore Facility Decommissioning ,Dr. James Lima, Minerals Management Service, Pacific OCS Region.......................... 124

SUMMARY AND RECOMMENDATIONSTechnical Session .................................................................................................................. 137Environmental Session .......................................................................................................... 140Disposition Session ............................................................................................................... 145

AGENCY PANEL DISCUSSION .................................................................................................... 149

POSITION PAPERSEnvironmental Defense Center , Linda Krop and Nichole Camozzi....................................... 172Exxon Co., USA , Dave Tyler ................................................................................................... 177Recreational Fishers , Merit McCrea ...................................................................................... 179Santa Barbara Lobster Trappers , Chris Miller ...................................................................... 181Southern California Trawlers Association ........................................................................... 182United Anglers of Southern California / American Sportfishing Association ,

Daniel Frumkes .............................................................................................................. 184

APPENDICES

APPENDIX I: REGULATORY FRAMEWORK AND ENVIRONMENTALREVIEW PROCESS FOR THE DECOMMISSIONINGOF OIL AND GAS FACILITIES ............................................................................ 193

APPENDIX II: PLATFORM SCHEMATIC AND LOCATIONS ..................................................... 221

APPENDIX III: GLOSSARY AND ABBREVIATIONS ................................................................... 231

APPENDIX IV: BIOGRAPHICAL SKETCHES .............................................................................. 245

APPENDIX V: LIST OF ATTENDEES ......................................................................................... 257

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LIST OF FIGURES

Author Figure

Danenberger Rigs to Reefs.................................................................................................. 15Existing OCS Structures by Age .................................................................... 15Existing OCS Structures by Water Depth ...................................................... 15Structures Removed by Water Depth ............................................................ 15Structures by Age at Time of Removal .......................................................... 15

Poulter Permitting Jurisdictions .................................................................................. 18Major Steps in the Permitting Process........................................................... 19

Griffin Worldwide Distribution of Platforms ............................................................... 20Platform Size Comparison ............................................................................. 20Finding the Right Balance .............................................................................. 22

Fields & Martin Figure 1. Well P&A Rig vs. Rigless, Step 1................................................. 28Figure 2. Well P&A Rig vs. Rigless, Step 2................................................. 28Figure 3. Well P&A Rig vs. Rigless, Step 3................................................. 28Figure 4. Well P&A Rig vs. Rigless, Step 4................................................. 28

Prasthofer Figure 1. Integrated Topsides / Deck .......................................................... 39Figure 2. Modular Topsides / Deck ............................................................. 39Figure 3. Hybrid Topsides on Concrete Gravity-based Structure................ 39Figure 4. Topsides Removal / Disposal Options ......................................... 40Figure 5. Removal in One Piece ................................................................. 40Figure 6. Lifting of Combined Modules........................................................ 41Figure 7. Reverse Installation...................................................................... 41Figure 8. Piece Small Removal ................................................................... 42

Culwell Figure 1. Facilities Decommissioned on the West Coast............................ 49Figure 2. Platforms Hope, Heidi, and Hilda Design..................................... 51Figure 3. Platform Hazel Design ................................................................. 51Figure 4. Pipeline Bypass at Platform Hope................................................ 53Figure 5. OS&T Abandonment Project Facilities Layout ............................. 54Figure 6. SALM Base Structure................................................................... 55Figure 7. Equipment Spread – Shallow Water Decommissioning............... 56Figure 8. Lift Plan – Crane Chart................................................................. 57Figure 9. Lift Plan – Lift Points and CG Locations....................................... 57Figure 10. Materials Transport Planning ....................................................... 57Figure 11. Preparations to Deck Packages................................................... 60Figure 12. Pile and Conductor Severing Using Explosives ........................... 63

Culwell & Figure 1. Diagram of Articulated Concrete Mat ........................................... 70McCarthy Figure 2. Exxon OS&T Project Facilities ..................................................... 71

LIST OF FIGURES(continued)

Author Figure

Fusaro & Figure 1. Crab & Lobster Traps as Deployed .............................................. 98Richards Figure 2. Crab or Lobster Vessel, Fore Deck .............................................. 98

Figure 3. Set Gillnet Deployed..................................................................... 100Figure 4. Drift Gillnet – Structure of Gear .................................................... 100Figure 5. Vessel Gillnet................................................................................ 100Figure 6. Hook & Line Gear, Deployed........................................................ 101Figure 7. Trawl............................................................................................. 101Figure 8. Vessel, Purse Seine ..................................................................... 102Figure 9. Purse Seine .................................................................................. 102Figure 10. Troll............................................................................................... 103

Page & Dugan Figure 1. Summary of Distribution & Movement Scenarios forthe Rock Crab .............................................................................. 121

Appendix I Figure 1. Permit Requirements by Facility Location .................................... 196Figure 2. NEPA Environmental Review Process: An Overview.................. 199Figure 3. Steps in the Environmental Review Process under CEQA .......... 211

Appendix II Platform Schematic ........................................................................................ 223Offshore Facilities, Santa Barbara Channel ................................................... 226Offshore Facilities, Southern California.......................................................... 227Onshore Oil & Gas Facility Decommissioning Tree ....................................... 228Offshore Oil & Gas Facility Decommissioning Tree ....................................... 229

LIST OF TABLES

Author Table

Poulter Overview of Permitting Requirements............................................................ 19

Fields & Martin Table 1. Basic Cementing Materials.............................................................. 31

Perez Table 1. Listing of Potential Contaminants Associated with Oil &Gas Operations ........................................................................... 85

Table 2. Potential Hazards of Hydrocarbons.............................................. 87Table 3. Remediation Techniques.............................................................. 88

Lima Table 1. Criteria for the Assessment of Social & Economic Impact inOnshore Facilities Decommissioning ........................................... 125

Appendix II Platforms Located in Federal Waters, Pacific OCS Region........................... 224State Waters Offshore Facilities..................................................................... 225

Workshop Program

1

DECOMMISSIONING AND REMOVALOF OIL AND GAS FACILITIES OFFSHORE CALIFORNIA:

RECENT EXPERIENCES AND FUTURE DEEPWATER CHALLENGESDOUBLETREE HOTEL, VENTURA, CALIFORNIA

SEPTEMBER 23 - 25, 1997WORKSHOP PROGRAM

TUESDAY, SEPTEMBER 23 - MORNING8:00-8:30 Registration

PLENARY SESSION8:30 - 9:00 Welcome and Introduction

• Dr. Russell Schmitt, Professor of Ecology, UC Santa Barbara• Carolita Kallaur, Associate Director, Offshore, Minerals Management Service• Robert Hight, Executive Officer, California State Lands Commission

9:00 - 9:50 Pacific Region Decommissioning Update, Outlook and Perspectives• Tom Dunaway, Regional Supervisor, Office of Development, Operations & Safety,

Minerals Management Service, Pacific OCS Region• Paul Mount, Chief, Minerals Resources Management Division,

California State Lands Commission• John Patton, Director, Santa Barbara County, Dept. of Planning and Development• Linda Krop, Senior Staff Attorney, Environmental Defense Center• Frank Holmes, Coastal Coordinator, Western States Petroleum Association

9:50 - 10:40 Decommissioning Policy, Regulations and International Developments• Bud Danenberger, Chief, Engineering and Technology Division, Minerals Management

Service• Dwight Sanders, Chief, Div. of Environmental Planning and Management,

California State Lands Commission• Susan Hansch, Deputy Director, Energy & Ocean Resources Unit,

California Coastal Commission• Bill Griffin, Director of Special Projects, Phillips Petroleum Company• Simon Poulter, Principal, Padre Associates, Inc.

10:40-11:00 Break11:00 - 11:45 Preview of the Workgroup Sessions

Technical Workgroup Co-Chairs• Marina Voskanian, Chief Reservoir Engineer, Minerals Resources Mgmt. Div.,

California State Lands Commission• Dr. Robert Byrd, Principal, Twachtman, Snyder & Byrd, Inc.

Environmental Workgroup Co-Chairs• Bill Douros, Deputy Director, Energy Division, Santa Barbara County,

Dept. of Planning and Development• Simon Poulter, Principal, Padre Associates, Inc.

Disposition Workgroup Co-Chairs• Dr. John Stephens, Director, Vantuna Research Group and Office of Research,

UC Los Angeles• Dr. Mark Carr, Assistant Professor of Biology, UC Santa Cruz

11:45 - 12:15 Public Discussion PeriodModerator: Dr. Russell Schmitt, Professor of Ecology, UC Santa Barbara

12:15 - 1:30 Lunch Break

Proceedings: Decommissioning Workshop, September 1997

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TUESDAY, SEPTEMBER 23 - AFTERNOON

TECHNICAL SESSION1:30 - 3:15 The Process of Decommissioning and Removing Offshore and Associated Onshore

Oil and Gas FacilitiesCo-Chair: Dr. Robert Byrd, Principal, Twachtman, Snyder & Byrd, Inc.Co-Chair: Marina Voskanian, Chief Reservoir Engineer, Minerals Resources

Management Division, California State Lands CommissionMaking Oil & Gas Wells Safe: The Plugging Process

• Steve Fields, Operational Engineer, California Department of Conservation,Division of Oil, Gas and Geothermal Resources

Offshore Production Facilities: Decommissioning of Topside Production Equipment• Dr. Peter Prasthofer, Technical Manager, Offshore Decommissioning Communications

ProjectDecommissioning of Decks, Jackets, Pipelines and Cables

• Andy Culwell, Vice President of Special Projects, American Pacific Marine, Inc.3-15 - 3:30 Break3:30 - 4:30 TECHNICAL SESSION - (continuation)

Site Clearance and Verification• Jack McCarthy, Geophysicist, Minerals Management Service, Pacific OCS Region

Onshore Facility Cleanup and Removal• Luis Perez, Energy Specialist, Energy Division, Santa Barbara County,

Dept. of Planning & Development4:30 - 5:30 Public Discussion Period

WEDNESDAY, SEPTEMBER 24 - MORNING8:00 - 8:30 Registration

ENVIRONMENTAL SESSION8:30 - 10:30 Environmental and Socio-Economic Effects Occurring During the Decommissioning and

Removal Process and Measures for Mitigating ImpactsCo-Chair: Bill Douros, Deputy Director, Energy Division, Santa Barbara County,Dept. of Planning and DevelopmentCo-Chair: Simon Poulter, Principal, Padre Associates, Inc.Air Quality

• Peter Cantle, Santa Barbara County Air Pollution Control DistrictCommercial / Recreational Fisheries

• Dr. Craig Fusaro, Director, Joint Oil Fisheries Liaison OfficeFisheries Research

• Villere Reggio, Outdoor Recreation Planner, Minerals Management Service,Gulf of Mexico OCS Region

Marine Mammals• Peter Howorth, Principal, Marine Mammal Consulting Group

Marine Benthic Organisms• Ray de Wit, L.A. de Wit, Consulting

Water Quality• Dr. Peter Raimondi, Assistant Professor of Biology, UC Santa Cruz

10:30 - 10:45 Break10:45 - 11:25 ENVIRONMENTAL SESSION - (continuation)

Cleanup Standards: Assessment and Remediation of Onshore Sites• Frank DeMarco, Associate Water Resource Control Engineer, Central Coast Regional

Water Quality Control BoardFuture Land Use

• Kim Schizas, Land Use Planner, Wynmark Company

Workshop Program

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11:25 - 12:30 Perspectives of Ocean User Groups and Public Discussion PeriodModerator: Dr. Russell Schmitt, Professor of Ecology, UC Santa BarbaraOcean User Group RepresentativesCommercial Fishing

• Mike McCorkle, President, Southern California Trawlers AssociationRecreational Fishing

• Merit McCrea, Owner, Captain McCrea's SportfishingOil and Gas Industry

• David Tyler, Public Affairs Advisor, Exxon Co., USA, Inc.Environmental Interest Groups

• Marc Chytilo, Chief Counsel, Environmental Defense Center12:30 - 1:30 Lunch Break

SEPTEMBER 24 - AFTERNOON

DISPOSITION SESSION1:30 - 3:10 Long-term Environmental and Socio -Economic Effects Related to the Disposition of

Oil and Gas FacilitiesCo-Chair: Dr. John Stephens, Director, Vantuna Research Group and Office of

Research, UC Los AngelesCo-Chair: Dr. Mark Carr, Assistant Professor of Biology, UC Santa CruzCommercial Fishing

• John Richards, Sea Grant Extension Program, Marine Science Institute,UC Santa Barbara

Recreational Fishing• Dr. Milton Love, Associate Research Biologist, Marine Science Institute,

UC Santa BarbaraHabitat Value of Oil and Gas Facilities

• Dr. Mark Carr, Assistant Professor of Biology, UC Santa CruzEnhancement of Platforms as Artificial Reefs

• Dave Parker, Senior Biologist, California Dept. of Fish and GameSite Clearance: Long-term Issues

• Jack McCarthy, Geophysicist, Minerals Management Service, Pacific OCS Region3:10 - 3:30 Break3:30 - 4:10 DISPOSITION SESSION - (continuation)

Onshore Disposition: Ultimate Fate• Dr. James Lima, Social Scientist, Minerals Management Service,

Pacific OCS RegionSocial and Economic Effects

• Dr. Robert Ditton, Professor of Wildlife and Fisheries Sciences,Texas A&M University

4:10 - 5:30 Perspectives of Ocean User Groups and Public Discussion PeriodModerator: Dr. Russell Schmitt, Professor of Ecology, UC Santa BarbaraOcean User Group RepresentativesCommercial Fishing

• Gordon Cota, Member, Southern California Trawlers AssociationRecreational Fishing

• Dan Frumkes, Director, Conservation Network, American Sportfishing AssociationOil and Gas Industry

• Lee Bafalon, Senior Land Representative, Chevron U.S.A., Inc.Environmental Interest Group

• Linda Krop, Senior Staff Attorney, Environmental Defense Center


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THURSDAY, SEPTEMBER 25 - MORNING

SUMMARY AND RECOMMENDATIONS SESSIONModerator: Dr. Russell Schmitt, Professor of Ecology, UC Santa Barbara

9:00 - 10:00 Report of Session Co-ChairsTechnical Workgroup Session

• Dr. Robert Byrd / Marina VoskanianEnvironmental Workgroup Session

• Bill Douros / Simon PoulterDisposition Workgroup Session

• Dr. Mark Carr / Dr. John Stephens10:00 - 12:30 Agency Panel Discussion With Public

Federal Agency Representatives• Dr. J. Lisle Reed, Regional Director, Minerals Management Service,

Pacific OCS Region• Richard Schubel, Chief, Regulatory Functions Branch, U.S. Army Corps of Engineers,

Los Angeles District• Maureen Walker, Deputy Director, Office of Ocean Affairs, U.S. Department of State

State Agency Representatives• Robert Hight, Executive Officer, California State Lands Commission• Brian Baird, Ocean Program Manager, California Resources Agency• Susan Hansch, Deputy Director, Energy & Ocean Resources Unit, California Coastal

Commission• Pete Bontadelli, Administrator, Oil Spill Prevention and Response Office,

California Dept. of Fish & GameLocal Agency Representatives

• Nancy Settle, Manager, Regional Programs Section, Ventura County, Planning Division,Resources Management Agency

• John Patton, Director, Santa Barbara County, Dept. of Planning and DevelopmentSummary and Closing RemarksModerator: Dr. Russell Schmitt, Professor of Ecology, UC Santa Barbara

Committee Members

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STEERING COMMITTEE MEMBERS / PARTICIPANTS

RICHARD WILHELMSEN , Co-Chair , MineralsManagement Service, Pacific OCS Region

PAUL MOUNT , Co-Chair, California State LandsCommission

Doug Anthony, Santa Barbara County, EnergyDivision

Lee Bafalon, Chevron, USA, Inc.

Chandra Basavalinganadoddi, California State LandsCommission

Dennis Bedford, CA Department of Fish & Game

Theresa Bell, Minerals Management Service, PacificOCS Region

John Brown, U.S. Coast Guard

Dr. Robert Byrd, Twachtman, Snyder & Byrd, Inc.

Andy Caldwell, Coalition of Labor, Agriculture &Business

Peter Cantle, Santa Barbara County, Air PollutionControl District

Dr. Mark Carr, UC Santa Cruz

Brian Collins, UC Berkeley

Andy Culwell, American Pacific Marine, Inc.

John Deacon, Torch Operating Company

Bill Douros, Santa Barbara County, Energy Division

Tom Dunaway, Minerals Management Service,Pacific OCS Region

Steve Fields, CA Dept. of Conservation, Division ofOil, Gas and Geothermal Resources

Nancy Francis, County of Ventura, Planning Division

Daniel Frumkes, United Anglers of SouthernCalifornia

Dr. Craig Fusaro, Joint Oil / Fisheries Liaison Office

Troy Gillum, Worley International, Inc.

Bill Grady, Exxon Company, USA, Inc.

Jim Grant, Minerals Management Service, PacificOCS Region

Richard Habrat, Minerals Management Service,Pacific OCS Region

Frank Holmes, Western States PetroleumAssociation

Jean Holmes, League of Women Voters

Peter Howorth, Marine Mammal Consulting Group

Pete Johnson, California State Lands Commission

Pat Kinnear, CA Dept. of Conservation, Division ofOil, Gas and Geothermal Resources

Linda Krop, Environmental Defense Center

Irma Lagomarsino, National Marine Fisheries Service

John Lane, Minerals Management Service, PacificOCS Region

Herb Leedy, Minerals Management Service, PacificOCS Region

Roger Lyon, Surfrider Foundation

Frank Manago, Minerals Management Service,Pacific OCS Region

Nabil Masri, Minerals Management Service, PacificOCS Region

Jack McCarthy, Minerals Management Service,Pacific OCS Region

Mike McCorkle, Southern California TrawlersAssociation

Dr. Daniel Meade, UC Santa Barbara

Elaine Meckenstock, UC Berkeley

Dr. Saahed Meshkatj, University of SouthernCalifornia, Petroluem Engineering Program

Aiden Naughton, California State Lands Commission

Dave Parker, CA Department of Fish & Game

Dr. Fred Piltz, Minerals Management Service, PacificOCS Region

Simon Poulter, Padre Associates, Inc.

Greg Sanders, U.S. Fish & Wildlife Service

Jerry Schiebe, Santa Barbara County, Air PollutionControl District

John Segerstrom, Texaco, Inc.

Glenn Shackell, Minerals Management Service,Pacific OCS Region

John Smith, Minerals Management Service, PacificOCS Region

Robert Sollen, Sierra Club

Rick Sorrell, U.S. Coast Guard

Dr. John Stephens, Vantuna Research Group, UCLos Angeles

Theresa Stevens, U.S. Army Corps of Engineers

Win Thornton, WINMAR Consulting Services, Inc.

Lyman Thorsteinson, U.S.G.S., Biological ResourcesDivision

Marina Voskanian, California State LandsCommission

Kirk Walker, California State Lands Commission

Tiffany Welch, U.S. Army Corps of Engineers

Al Willard, California State Lands Commission

Bonnie Williamson, UC Santa Barbara

James Wiseman, UC Berkeley


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WORKING GROUP MEMBERSFrank Manago and John Smith, Minerals Management Service, Pacific OCS Region,

served as liaisons among the working groups

Technical Working GroupDR. ROBERT BYRD , Co-Chair , Twachtman, Snyder & MARINA VOSKANIAN , Co-Chair , CA State Lands

Byrd, Inc. CommissionDolores Aguilar-Zepeda, Chevron, USA, Inc. Daniel Knowlson, Minerals Management Service,Roma Armbrust, League of Women Voters Pacific OCS RegionDr. Robert Bea, UC Berkeley Herb Leedy, Minerals Management Service,Peter Brooks, Worley International, Inc. Pacific OCS RegionAndrew Culwell, American Pacific Marine, Inc. Roger Lyon, Surfrider FoundationSteve Fields, CA Dept. of Conservation, Division of Jack McCarthy, Minerals Management Service,

Oil, Gas & Geothermal Resources Pacific OCS RegionBill Grady, Exxon Company, USA, Inc. Paul Mount, CA State Lands CommissionJames Grant, Minerals Management Service, Luis Perez, Santa Barbara County, Energy Division

Pacific OCS Region Gregory Scott, CA State Lands CommissionCathy Hoffman, Minerals Management Service, Glenn Shackell, Minerals Management Service,

Pacific OCS Region Pacific OCS RegionJean Holmes, League of Women Voters Arvind Shah, Minerals Management Service,Maher Ibrahim, Minerals Management Service, Gulf of Mexico OCS Region

Pacific OCS Region Win Thornton, WINMAR Consulting Services, Inc.Pete Johnson, CA State Lands Commission Robin Villa, Fugro West, Inc.Mike Kelley, Exxon Company, USA, Inc. Bonnie Williamson, UC Santa BarbaraPat Kinnear, CA Dept. of Conservation, Division of Wes Winkler, Chevron, USA, Inc.

Oil, Gas & Geothermal Resources Lou Zylstre, American Pacific Marine, Inc.

Environmental Working GroupBILL DOUROS , Co-Chair , Santa Barbara County, SIMON POULTER, Co-Chair , Padre Associates, Inc.

Energy DivisionDoug Anthony, Santa Barbara County, Pete Johnson, CA State Lands Commission

Energy Division Karl Krause, Ventura County, APCDLee Bafalon, Chevron, USA, Inc. Linda Krop, Environmental Defense CenterDr. Art Barnett, MEC Analytical Systems, Inc. Herb Leedy, Minerals Management Service,Theresa Bell, Minerals Management Service, Pacific OCS Region

Pacific OCS Region Joan Leon, League of Women VotersPeter Cantle, Santa Barbara County, APCD Roger Lyon, Surfrider FoundationDr. Mark Carr, UC Santa Cruz Richard Nitsos, CA Department of Fish & GameAlison Dettmer, California Coastal Commission Bob Sollen, Sierra ClubNancy Francis, Ventura County, Planning Division John Storrer, Storrer Environmental ServicesDr. Craig Fusaro, Joint Oil / Fisheries Liaison Office Rosie Thompson, SAICBill Grady, Exxon Company USA, Inc. Marina Voskanian, CA State Lands CommissionFrank Holmes, Western States Petroleum Bonnie Williamson, UC Santa Barbara

Association Dr. Charles Woodhouse, Santa Barbara Museum ofPeter Howorth, Marine Mammal Consulting Group Natural History

Disposition Working GroupDR. MARK CARR , Co-Chair , UC Santa Cruz DR. JOHN STEPHENS, Co-Chair , Vantuna Research

Group & UC Los AngelesLee Bafalon, Chevron, USA, Inc. Dr. Milton Love, UC Santa BarbaraArt Boehm, Nuevo Energy Company Annisa Mayer, UC Los AngelesBill Douros, Santa Barbara County, Energy Division Merit McCrea, Captain McCrea’s SportfishingAlison Dettmer, California Coastal Commission Elaine Meckenstock, UC BerkeleyDr. Jenifer Dugan, UC Santa Barbara Dave Parker, CA Department of Fish & GameDan Frumkes, United Anglers of Southern California Dr. Mark Page, UC Santa BarbaraDr. Craig Fusaro, Joint Oil / Fisheries Liaison Office Simon Poulter, Padre Associates, Inc.Michelle Gasperini, Santa Barbara County, John Richards, UC Santa Barbara

Energy Division Theresa Stevens, U.S. Army Corps of EngineersJean Holmes, League of Women Voters Rosie Thompson, SAICPete Johnson, CA State Lands Commission Win Thornton, WINMAR Consulting Services, Inc.John Lane, Minerals Management Service, Marina Voskanian, CA State Lands Commission

Pacific OCS Region Tiffany Welch, U.S. Army Corps of EngineersHerb Leedy, Minerals Management Service, Bonnie Williamson, UC Santa Barbara

Pacific OCS Region James Wiseman, UC Berkeley

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PLENARY ADDRESSES

Introductory Comments, Carolita Kallaur ............................................. 9

Pacific Region Decommissioning Update, Outlook, andPerspectives, Tom Dunaway ......................................................... 11

California State Lands Commission Management Responsibilityand Recent Decommissioning Experience, Paul Mount................ 13

Update on Decommissioning Issues, Bud Danenberger ..................... 14

California State Lands Commission: Decommissioning Policy andRegulations, Dwight Sanders......................................................... 16

Regulatory Framework and Environmental Review Process for theDecommissioning of Oil and Gas Facilities, Simon Poulter........... 18

International Developments: Lessons Learned and Need forPublic Input, W.S. (Bill) Griffin, Jr. ................................................. 20

Plenary Addresses

9

INTRODUCTORY REMARKS

CAROLITA KALLAURAssociate Director for Offshore Minerals Management

U.S. Department of the Interior, Minerals Management Service

Good morning, it’s my pleasure to be heretoday to welcome you to this importantworkshop.

For those of you who may be unfamiliar withthe MMS, the MMS is the agency within theDepartment of the Interior responsible foradministering oil and gas and other mineraldevelopment on the Federal Outer ContinentalShelf (OCS). Offshore California, FederalOCS lands are those submerged lands locatedseaward of State tidelands, which extend fromthe coastline to three miles offshore.

Although the MMS is a relatively small bureau,we play a very significant role in managingdevelopment of our Nation’s energy resources.We manage mineral development on 27 millionacres of the OCS, which supplies over 25% ofthe natural gas and 12% of the oil produced inthe United States. We also collect more than$4 billion annually in revenues from OCS andonshore mineral leases. This money isdistributed to Federal and State Treasuries, toallottees, including Indian Nations, and to theLand and Water Conservation Fund and theNational Historic Preservation Fund.

As the stewards of America’s offshoreresources, MMS has a duty to ensure safe andenvironmentally sound development of ourNation’s offshore oil and gas resources. Thisresponsibility applies not only to developmentbut also to the decommissioning of offshoreproduction facilities once they have reachedthe end of their service life.

As many of you are aware, decommissioningoperations are commonplace in the Gulf ofMexico where there are more than 4000offshore platforms currently in place. Between100 – 200 structures are removed there eachyear. Of the 1200 structures removed to datein the Gulf of Mexico, the majority (80%) havebeen small structures located in less than 100feet of water. To date, there have not beenany platforms removed in the Gulf located inwater depths greater than 400 feet.

In comparison, there are currently 27 oil andgas platforms (23 OCS and 4 State) located off

the coast of southern California. Only sevenoffshore platforms have been removed to date,all from State tidelands. All of the platformswere relatively small structures located in lessthan 150 feet of water.

Industry is in the preliminary stages ofdeveloping plans for removing as many as fiveCalifornia OCS platforms and two associatedonshore processing facilities early in the nextcentury. Three of the platforms are located inwater depths ranging from greater than 600 to740 feet. If scheduling goes as planned, thiscould very well be the world’s first ultra-deepwater decommissioning project. In termsof its combined onshore and offshorecomponents, it will be the largest and mostcomplex decommissioning project ever to beundertaken.

The decommissioning of deepwater oil and gasstructures is a topic that has come to theforefront in the North Sea and is a topic that willbe coming to the forefront in California, and theGulf of Mexico in the near future. The topic isa timely one because it has implications forfuture deepwater development activity in theGulf of Mexico, Pacific Region, North Sea, andother parts of the world. In the North Sea,decommissioning of offshore structures hasbeen stymied by public controversysurrounding the Brent Spar Project, whichinvolved the proposed decommissioning andocean disposal of a large offshore loadingstructure. Due to this controversy, industry hashad to re-evaluate its decommissioningstrategy and consider the long-termimplications for future development in the NorthSea.

In contrast to shallow water, thedecommissioning of deepwater facilities (> 200foot water depths) will present significanttechnical, safety, environmental, and materialdisposal challenges. From a technicalstandpoint, the technology has yet to bedeveloped to remove certain deepwaterstructures. This is particularly true in waterdepths exceeding 400 feet. The environmentalimpacts associated with decommissioning


10

large deepwater structures are also of muchgreater significance due to the size of thestructures, which can be as large as theEmpire State Building. The onshoreinfrastructure required to dispose of thesemassive steel structures also may not exist,which may necessitate consideration of otheroptions such as converting the structures toartificial reefs or other uses.

In the Gulf of Mexico, statistics show that thegreater the water depth the more likelydecommissioned structures are to beconverted to artificial reefs. Of the 1200structures removed to date in the Gulf, about10% have been converted to artificial reefs.However, 40% of the structures located in 100-200 feet of water, and 85% of the structureslocated in 200-400 feet of water have beenconverted to artificial reefs.

Let me assure you, MMS does not have aposition one way or the other as to the rigs-to-reef program here in California. We believethat is an issue that falls primarily within theregulatory jurisdiction of the CaliforniaDepartment of Fish and Game, Army Corps ofEngineers, and the California CoastalCommission. The States of Louisiana andTexas have active rigs-to-reef programs, andMMS is involved to the extent that thedecommissioning of OCS platforms takesplace in a safe and environmentally soundmanner. We are committed to workingcooperatively with all interested parties toensure that this goal is achieved off California.

Although our experience off California islimited, we recognize that the removal ofoffshore structures is a sensitive issue inCalifornia and that the utmost care must betaken to ensure that it is done in a manner thataddresses the needs and concerns of allparties.

To accomplish that goal, we must all workclosely together to develop a consensus onhow to best proceed. That is why publicworkshops such as this are so important. Theyprovide an opportunity for everyone who hasan interest in the subject to share theirviewpoints, discuss issues, and developrecommendations.

Offshore California, as in other offshore areas,we continue to place a very high priority on

safety. We will also continue to work closelywith all interested parties to ensure that theremoval and disposal of platforms is conductedin an environmentally sound manner.

To that end, we are pleased to be co-sponsoring this workshop with the CaliforniaState Lands Commission (SLC). We are alsopleased to have participated with the State insponsoring previous workshops such as the1994 Decommissioning Workshop at UCSanta Barbara and the 1997 California and theWorld Oceans Conference in San Diego.

Before closing, I would like to thank the SLCfor co-sponsoring this workshop with the MMSand UC Santa Barbara and UC Berkeley forthe administrative support they have provided.I also want to thank those who made financialcontributions – the E & P Forum, Chevron,USA, and Torch Operating Company – as wellas those who have made in–kind contributions.

Finally, I would like to thank members of theWorkshop Organizing Committee forfacilitating workshop planning meetings andorganizing the workshop. These individualsinclude Frank Manago and John Smith fromMMS, Pete Johnson and Marina Voskanianfrom the SLC, and Bonnie Williamson from UCSanta Barbara. I also want to thank the manypeople who attended workshop planningsessions and contributed to the development ofwhat I consider to be a well rounded andbalanced program. In particular, I would like tothank the co-chairs of the Workshop SteeringCommittee, Paul Mount of SLC and DickWilhelmsen of MMS, as well as session co-chairs, speakers and panel members for thesignificant time and effort they devoted toorganizing and planning their respectivesessions.

On behalf of the MMS, I welcome yourparticipation in this effort. I want to ensure youthat we will carefully consider the views of allparties as well as the recommendations thatwill be forthcoming. During the open paneldiscussion with the public on day three, we willshare with you our perspectives on theworkshop and recommendations.

I am looking forward to an interesting andproductive workshop and encourage you all toactively participate. We value your input andlook forward to your recommendations.

Plenary Addresses

11

PACIFIC REGION DECOMMISSIONING UPDATE, OUTLOOK,AND PERSPECTIVES

TOM DUNAWAYRegional Supervisor, Office of Development, Operations and Safety

Minerals Management Service, Pacific Outer Continental Shelf Region

I'm going to start off with a short overview of ourRegion. The Minerals Management ServicePacific Outer Continental Shelf Regionoversees development of Federal mineralresources, primarily oil and gas, offshoreCalifornia, Oregon, and Washington. Currently,we manage 83 leases, all of which are off thecoast of California. The Federal OuterContinental Shelf (OCS) off California begins 3miles from the coast adjacent to State tidelands.

We have 23 platforms producing a total ofabout 150,000 barrels of oil a day and 180million cubic feet of gas per day, from 43 of theleases in the Region.

The Pacific OCS Region is organized by majorprogram functions: an Office of EnvironmentalEvaluation, an Office of Resource Evaluation,and an Office of Development, Operations andSafety.

The Office of Environmental Evaluationanalyzes proposed and ongoing offshore oil andgas operations to ensure the activities are donein a way that safeguards the environment. Thisoffice also conducts a comprehensiveenvironmental studies program.

The Office of Resource Evaluation analyzes oil,gas, and other mineral potential on the FederalOCS, using a wide range of geologic andgeophysical information, and provides technicalsupport for marine mineral investigations.

I'm the Regional Supervisor of the third office,the Office of Development, Operations andSafety, which is responsible for properdevelopment of OCS resources on existingleases and the safety and environmentalintegrity of operations on the OCS.

Our office is responsible for the offshoreinspections program, and we have inspectorsoffshore overseeing operations every day of theyear.

This Plenary Session covers Pacific Region

Decommissioning Update, Outlook andPerspectives, so I'll begin with an update.

The newest of the Pacific OCS Region's 23platforms have been in place 8 years; the oldestwas installed 30 years ago this month. ThePacific OCS Region’s facilities range from smallshallow water to world class deepwaterstructures. We have one platform in less than a100 feet of water; we also have two platforms inwater depths of over a thousand feet. Wehaven't had any platforms decommissioned yet,but we had an offshore storage and treatingvessel, a converted tanker, decommissioned in1994. Though it wasn't a platform, thedecommissioning was a technically complexoperation, with separate phases involvingdisconnecting and removal of the vessel, themooring buoy, and a riser section; cutting ofpiles and removal of the mooring base andsubbase from the seafloor; cutting and removalof pipeline and power cable segments; and asurvey of the area to recover debris. ThePacific OCS Region worked cooperatively withall interested parties before, during, and afterthat work. We learned from the experience,and we'll build on what we learned, for futuredecommissionings.

As to outlook, our first platformdecommissionings will likely take place over thenext 5-10 years. Chevron has started theplanning process for decommissioning of their 5platforms. Of those 5, the oldest was installed18 years ago, and the newest only 11 yearsago. The water depths range from around 300feet to about 700 feet. Platform Harvest, offPoint Arguello, is in 675 feet of water. AndPlatform Gail, in the Santa Barbara Channel, isin 739 feet of water.

These deeper waters, which would set adecommissioning world record to date for waterdepths, and the necessarily larger structuresprovide challenges for both industry andregulatory agencies. And these challenges will


12

be met with a collective effort that givesconsideration to the various perspectives andconcerns of all interested parties.

With regard to perspectives, we seedecommissioning not as a surprise, but as anintegral part of each oil and gas project. Thecareful planning for these final phases of theprojects will thoroughly address safety ofoperations and of the environment. Theplanning will be a cooperative process involvingindustry, regulatory agencies, and the public, toensure that everyone's concerns are heard andaddressed.

Plenary Addresses

13

CALIFORNIA STATE LANDS COMMISSION MANAGEMENTRESPONSIBILITY AND RECENT DECOMMISSIONING EXPERIENCE

PAUL MOUNTChief, Minerals Resources Management Division

California State Lands Commission

STATE LANDS COMMISSION

• Created in 1938• 3 Independent Commissioners

Lt. GovernorState ControllerDirector of Finance

• ManagesSovereign lands - 1 million acres1100 miles of coastline30 rivers and 40 lakesSchool lands - 5.5 million acres

OFFSHORE FACILITIESCURRENTLY ON STATE LANDS

• 4 PlatformsEmmyEstherEvaHolly

• 6 Islands4 Thums IslandsRinconBelmont

MINERAL RESOURCEMANAGEMENT

• Oil 60,000 BBL/D• Gas 27,000 MCF/D• Geothermal 5,217,000 Lb/Hour• Mineral 220,000 Tons/Year

Cumulative $ to date $6 Billion

RECENT DECOMMISSIONING

• Chevron 4-H projectHope, Hazel, Hilda, HeidiFour year projectAbout $40 million

• SWARS – Subsea Well AbandonmentCurrently decommissioning wellsand pipelines

• Belmont IslandCurrently decommissioning wellsIsland decommissioning in 1998

LESSONS LEARNED FROM 4-H

• Intensive advance planning andcoordination prevented accidents andminimized environmental effects

• Early and complete coordination with allinvolved agencies

• Provide information early to community onproject

• Must understand the needs of fishermen• Explosives can be used safely underwater

with detailed engineering andenvironmental pre-planning

• SLC engineering staff onsite essential totimely approval of plan modifications andprevention of problems


14

UPDATE ON DECOMMISSIONING ISSUES

ELMER “BUD” DANENBERGERChief, Engineering and Technology Division, Minerals Management Service

EXPLOSIVES HAVE PROVEN TO BESAFE AND EFFECTIVE

• Used in 70% of removals• Not diver dependent• Mitigations have minimized the risk to

turtles and dolphins

WHY 15 FEET?

• Proven to be effective in preventing seafloorobstructions

• Allows margin for error• Reduces operator’s liability risk• District Supervisor may adjust

THREE-FOOT REMOVAL DEPTHMAY BE RISKY

• 3-5 feet scour potential in water depths lessthan 30 feet

• Bottom conditions affect removal depthmeasurements

SERIOUS CONCERNS ABOUTOBSTRUCTIONS

• Any exposed casing stubs or pilings couldremain in place for 100+ years

• Thousands of trawling vessels work in theGulf

PIPELINE BURIAL TO 3 FEET HASNOT ALWAYS PROVEN TO BE

SUFFICIENT

• Hurricane Andrew:9+ pipeline segments were exposed10 segments damaged by mud slides18 segments damaged by anchordragging

• Shrimpers have often raised concernsabout pipeline obstructions

PARTIAL REMOVALS

• Both Marine Board and Workshop supportpartial removals

MARINE BOARD AND WORKSHOPRECOMMENDED CHANGES IN

MITIGATIONS

• Develop guidelines for determining the sizeof explosive charges

• Remove the limit on the number ofdetonations at any one time

• Shorten the observation time to 24 hoursbefore the blast

Plenary Addresses

15

MARINE BOARD AND WORKSHOPRECOMMENDED MORE STUDIES

• Turtle detection and scaring devices• Compare natural reefs and oil and gas

platforms• Advanced explosive and non-explosive

removal technology• Consider deep-water pipeline abandonment

procedures• Evaluate the reef effect associated with

deep-water platforms• Evaluate the habitat value of structures in

cold water environments• Determine the water depth profile for fish

killed by explosives• Consider the effects of platform size on fish

attraction• Evaluate platform disposal options

INTERNATIONAL CONVENTIONS

• London Convention of 1972 (LC)• International Maritime Organization

guidelines

LESSEES ARE RESPONSIBLE FORALL LEASE ABANDONMENT COSTS

STATUS OF STRUCTURE ON THEOCS

Age and Water DepthAugust 1997

Rigs to Reefs

As of August 1997

Removals 93.2%(1,559 platforms)

Reefs 6.8%(113 platforms)

Existing OCS Structures by Age

1,203 1,201

718644

1103 14 6

<10 y

rs.

11-2

0 yrs.

21-3

0 yrs.

31-4

0 yrs.

>40 y

rs.0

200

400

600

800

1,000

1,200

1,400 GOM PAC

Existing OCS Structures by Age

Existing Structures by Water Depth

2,678

732

411

551 8 6 8

<100

feet

100-

200 f

eet

201-

400 f

eet

>400

feet

0300600900

1,2001,5001,8002,1002,4002,7003,000 GOM PAC

Existing OCS Structures by Water Depth

Structures Removed by Water Depth

1,251

245

58 1

<100

feet

100-

200 f

eet

201-

400 f

eet

>400

feet

0

200

400

600

800

1,000

1,200

1,400

Structures Removed by Water Depth

Structures by Age at Time of Removal

563521

326

122

3

<10 y

rs.

11-2

0 yrs.

22-3

0 yrs.

31-4

0 yrs.

>40 y

rs.0

100

200

300

400

500

600

700

Structures by Age at Time of Removal


16

CALIFORNIA STATE LANDS COMMISSION:DECOMMISSIONING POLICY AND REGULATIONS

DWIGHT E. SANDERSChief, Division of Environmental Planning & Management

California State Lands Commission

As we prepare for the approachingdecommissioning and removal of additionalstructures, both offshore and onshore, weshould recall that California is no stranger to oiland gas development. The area of Ojai was thesite of an oil discovery in 1857 and oil wasdiscovered on the coast of Ventura Countysome years later.

In 1890, gas was discovered within the limits ofSummerland in Santa Barbara County and afew years later, in 1894, oil was discovered inSummerland very near to the sea. By 1896,Summerland hosted the first offshore oil andgas development – wooden piers and platformsbegan to appear along the area’s beaches andshoreline. I am sure that most of us at one timeor another have seen pictures of thedevelopments that changed a popularswimming area into a forest of derricks.

By 1920, most pumping activity in the wells wasfinished and the industry moved on to moreproductive prospects, as in the gold rush, thearea was abandoned by man but his structuresremained. During the next 50 years, thesedecaying facilities were a constant reminder ofman’s “What me worry” philosophy.

The vistas of the offshore area of the county ofSanta Barbara began to change in the summerof 1988 with the abandonment and removal ofplatforms Helen and Herman from State waters.I can still use these terms here since as far as Ican determine, decommissioning was notsubstituted for abandonment until 1996 at the‘International Workshop on Offshore LeaseAbandonment and Platform Disposal’ in NewOrleans.

By August 1997, four more platforms, Hope,Hazel, Hilda, and Heidi, were removed from theState waters offshore Santa Barbara County.We are still dealing with some aspects of thisproject, the circumstances of which I am sure

you will hear more of both within and without thecontext of this workshop.

What has changed since the specter ofSummerland? For one, the California StateLands Commission was created by theLegislature in 1938 and given the responsibilityfor the management, development andextraction of mineral resources located on Statesovereign tide and submerged and State schoollands. The State’s sovereign offshore tide andsubmerged lands are those generally locatedfrom the mean high tide line to three nauticalmiles seaward.

The Commission’s oil and gas leases,predominately issued in the fifties and sixties,contain the following language: “At theexpiration of this lease or sooner terminationthereof, the lessee shall surrender the premisesleased, with all improvements thereon, in goodorder and condition, or, at the option of theState and as specified by the State, the lesseeshall remove such structures and fixtures ashave been put on the leased land by the lesseeand otherwise restore the premises, all removaland restoration costs to be borne by the lessee,subject to the lessee’s right to remove hisequipment as provided in the statutes.Notwithstanding any provision of this lease, thelessee shall have the right to remove any oildrilling and producing platforms and other oilfield development and producing equipmenthaving a re-use or salvage value.”

You can tell from the construct of this languagethat our attorneys were not paid on the basis ofthe number of periods used.

To date, the Commission has encouraged theremoval of platforms rather than some form ofabandonment in place. A Spring 1996 article in“Underwater Magazine” by Ross Saxon, Ph.D.entitled, ‘Offshore Lease Abandonment andPlatform Disposal, A Status Report’ opines that

Plenary Addresses

17

the removal of a platform involves five distinctsteps:

1. Obtaining necessary permits and approvals,observed to be a complex, time consumingand difficult job of which I am sure Simon willinform us later

2. Plugging the well3. Decommissioning, defined as ridding the

platform of hydrocarbons4. Removing the platform5. Clearing the site

The Commission’s lease terms, statutoryauthorities and responsibilities, and regulationsgoverning the “decommissioning and removal”of oil and gas facilities offshore are augmentedby the provisions of the CaliforniaEnvironmental Quality Act or CEQA. Throughthe CEQA process, a project’s potential adverseimpacts on the environment are identified andanalyzed. If any of these impacts are found tobe significant, mitigation requirements aredeveloped to avoid, substantially lessen oreliminate such impacts. Once adopted by theCommission, such mitigation is implemented bya Mitigation Monitoring Program administeredby the Commission.

The CEQA process also provides opportunitiesfor the public, public interest groups, othermaritime user groups, and federal, state andlocal agencies to review and provide comments

on the project and its environmentaldocumentation.

Within the context of the Commission’sexperiences in 1988 and 1997, the process hascertainly encouraged debate and discussion,but little consensus on major issues affectingfacility decommissioning and disposition. Forinstance, who will accept liability if some or all ofa structure remains in place; or, what portion ofa structure could, by itself or with augmentation,function as an artificial reef?

To heighten the challenge, the issues haveissues. For example, do artificial reefs nurturemarine life or merely attract it and in either casedo they place marine life at a disadvantage withrespect to sport or commercial fishing activities?Which fishing interests should prevail, sport orcommercial? Which environmental perspectiveshould govern, that which advocates the use ofoffshore structures for artificial reefs or thatwhich holds that no such disposition shouldoccur since such reefs could pose potentialharm to fishing operations?

Unfortunately, I cannot wrap this up with “Have Igot a deal for you.” I do hope, however, to learnfrom the discussions planned in this workshopand from you, the participants. Thank you forthe opportunity to do both.


18

Permittin g Jurisdictions

Platform

Federal OCSMMS/ACOE

Lead Agency

State WatersSLC Lead

Agency

OnshoreCounty or CityGovernmentLead Agency

Onshore Processing Plant

Marine Terminal

Platform

Subsea Well

Lead and Key Agencies• Lead Agencies

− Minerals ManagementService

− Army Corps of Engineers

− State Lands Commission

− County or CityGovernments

• Other Key Agencies

− California CoastalCommission

− Air Pollution ControlDistrict

− Regional Water QualityControl Board

− NMFS/CDF&G

− U.S. Coast Guard

Environmental Review Process• National Environmental Policy Act (NEPA)

− Environmental Impact Statement

− Environmental Assessment/FONSI

• California Environmental Quality Act (CEQA)− Environmental Impact Report (EIR)− Mitigated Negative Declaration

REGULATORY FRAMEWORK AND ENVIRONMENTAL REVIEWPROCESS FOR THE DECOMMISSIONING OF

OIL AND GAS FACILITIES

SIMON POULTERPrincipal

Padre Associates, Inc.

Plenary Addresses

19

Overview of Permittin g RequirementsFedera l OCS State W aters O nshore - County or City

Federal AgenciesMinerals Management Service

- Lease Condi tion/Stipulattions

- Development and Production Plan - Lease Term Pipeline Application

- Pipeline Right-of-W ayEPA - NPDES Permi t

ACOE - Section 10/404 Permit

USCG - Aids to NavigationState Agencies

Cali fornia Coastal Commission

- Consistency Certification - Coastal Development Permit

SLC - Lease Agreement/PermitRW QCB - NPDES Permit

CDF&G - Section 1603

County or C ityPrelminary Development Plan

Condi tional Use Permit

Final Development PlanCoastal Development Permit

Misc. PermitsAir Pollution Control D istrict

- Authori ty to Construct

- Authori ty to Operate

Permit Requirement by Fac ility Loca tion

Major Steps in the Permitting Process

Applicant PreparesDecommissioning Plan

Conduct Pre-applicationMeetings with Agencies

Application Submitted/Completeness Review

Draft EnvironmentDocument Prepared

Lead Agency PublicHearing for Approval of

Proposed Project

Public Hearing toApprove Environmental

Document

Response to Comments/Final Environmental

Document

Draft EnvironmentalDocument Public

Review

Other Agency PermitApplications Deemed

Complete

Project and MitigationMeasure Implementation

Public Hearing forPermit Approval

Draft Permit Availablefor Public Comment

3 to 6 months 1 to 12 months1 to 6 months1 to 6 months

1 to 2 months1 to 2 months1 month1 month

1 month 1 month 1 month 1 to 16 months

Timing

Timing

Timing


20

INTERNATIONAL DEVELOPMENTS:LESSONS LEARNED AND NEED FOR PUBLIC INPUT

W. S. (BILL) GRIFFIN, JR.Director of Special ProjectsPhillips Petroleum Company

INTRODUCTION• Speaking about Decommissioning is only

part of the equation - must listen andinclude feedback into decision

• No communication with the public beforeBrent Spar

WORLDWIDE DISTRIBUTION OFPLATFORMS

DISTRIBUTION• 6500 structures in Continental Shelfs of 53

countries• Cost of total removal estimated at 35-40

billion USD• 4000 structures in GOM cost 5 billion USD• 400 structures in North Sea cost 12-15

billion USD

PLATFORM SIZE COMPARISON• Worldwide 600 larger than Shallow Water

Structures• About 50 larger than Deepwater Structures• About 100 larger than 20 Story Building• About 4500 smaller than 20 Story Building• Deep Water Jacket shown weighs

approximately 20,000 tonnes – Eiffel Towerweighs 7,100 tonnes

PLATFORM SIZE COMPARISON

HISTORY• 1958 GENEVA CONVENTION – GLOBAL

- Set the legal framework to allowindustry to explore and exploitcontinental shelves

- Required total removal of platforms• 1969 USGS - REGIONAL

- 1st State Practice under 1958 GenevaConvention

- Required total removal to 15 feet belowmud line and location dropped to besure no obstruction

• 1972 – LS - GLOBAL- The current authority for disposal at sea

• 1982 UNCLOS - GLOBAL- Supercedes the 1958 Convention for

platforms- Allows for competent body to set

removal guidelines to ensure safetyof navigation and not interfere withother users of the sea

• 1989 IMO GUIDELINES - GLOBAL- Sets removal guidelines to ensure

safety of navigation- After 1-1-98, no structure can be

emplaced on any continental shelfthat is not feasible to remove

• 1990 OSCOM - REGIONAL- Specific guidelines for platform disposal

at sea in NE Atlantic

Plenary Addresses

21

- Must be sea disposed in at least 2000meters of water and 150 nauticalmiles from level

• 1995 OSCOM MORATORIUM -REGIONAL

- After Brent Spar, banned sea disposalat sea in NE Atlantic

- UK and Norway voted against, so notheld to ban

INTERNATIONAL DEVELOPMENTS• LONDON CONVENTION• IMO GUIDELINES• OSPAR

LONDON CONVENTION• New Protocol in 1996• Precautionary Principle

Be sure of results before doing something• Polluter Pays Principle

The party doing the disposal pays all costs• Reverse List

1972 LC List what cannot be sea disposed1996 Protocol list what can be sea disposed

• Waste Assessment Framework (WAF)Procedure to follow for sea disposal

• Will not be in force for several years.Until in force, 1972 LC Valid

IMO GUIDELINESWant to have IMO Review to see if they need tobe revisedSets removal guidelines to ensure safety ofnavigationAfter 1-1-98, no structure can be emplaced onany continental shelf that is not feasible toremove• Minimum Guidelines

Coastal State can require more removed• 74 meters / 4,000 tonnes

All structures in water less than 75 metersdeep and substructures weighing lessthan 4,000 tonnes must be removed

• After 1-1-98 – 100 meters / 4,000 tonnesAll structures emplaced after 1-1-98 in less

than 100 meters of water andsubstructures weighing less than 4,000tonnes must be removed

• After 1-1-98 - DesignMust be shown at time of installation that it

is feasible to be removed – actualdecision made in future when structurebecomes redundant

• Partial Removal AllowedStructures not totally removed must have a

minimum of 55 meters of clear waterabove parts remaining

• Rigs-to-Reefs allowedStructures can be converted to a new use

OSPARReplace separate Oslo & Paris ConventionsWill be enforced by end of 1998Jurisdiction in North East Atlantic• Five Categories

Sea bed completions – to shoreSmall steel – to shoreLarge steel - ?Floaters – to shoreConcrete – left in placeAll structures come to shore regardless ofwater depth except for LARGE steel andthey cannot reach agreement on definitionof large steel

• Not AgreedReverse list or prohibitive list – Will not

have a reverse list or a prohibitive list todecide what disposal

Definition of large steel – IMO definition oflarge steel or a more onerous definition

Exceptions – There will always be need forexceptions to the rule

Cut-off date – After a certain date in thefuture, any structure emplaced will cometo shore for disposal

Topside on large steel and concrete –Some topsides cannot be lifted becauseof design – special considerations

Consultation Procedure – How willcontracting parties give their approval?

PIPELINES AND DRILL CUTTING PILES NOTCURRENT ISSUE, BUT WILL BE AFTERPLATFORMS AGREE

LESSONS LEARNED• Decommissioning is a process not a

construction projectBegan with SPAR in 1991, removed in

1995, disposed in 1999?Engineering is the easy part.Politics is the hard part


22

LESSONS LEARNED (continued)• Expect the unexpected

UK & Operator did not expect outrageTechnical problemsNot structural as drawing showsUnavailable equipment or serviceWeather

• Time is importantDon’t do anything until consequences are

fully understoodDon’t be pushedDead money spent. Only contractors have

a returnMaintaining structure may not be as

expensive as thoughtNew equipment may evolve

• Not all should come ashoreContinue to enhance Marine EnvironmentClean seabed, but dirty atmosphere and

landRecycled material, but not always cost

efficient• Cost, Technology, Safety, Environment

and Regulatory are importantALL must be balanced

• Public must be considered and involvedPrepare information for public as to what

you are planning to do• Communicate and listen

FINDING THE RIGHT BALANCE• Balance Between

Health and Safety of workersEnvironment Impact to Land, Sea and AirCost EffectivenessTechnical Feasibility

• Regulatory work for Politicians• Politicians elected by Public• Target is where the four inter circles

overlapTarget moves by pressure from the public

NEED FOR PUBLIC INPUT• Industry beliefs

Bases their beliefs on Science, Technology& Economics

• Public beliefsBases their beliefs on values and morals

• Hazardous Risk AssessmentIndustry performs calculationPublic

~ If they feel they are in control ~ SAFE~ If they do not feel in control ~ FEAR

NEED FOR PUBLIC INPUT

“IF YOU HAVE THE COURAGE TO SPEAK -YOU MUST HAVE THE DISCIPLINETO LISTEN”

• SPEAK – Give your message• LISTEN – Hear public concerns• IMPLEMENT – Incorporate public

concerns into division or explain whynot

PublicPerception Public

Perception

PublicPerception

PublicPerception

FINDING THE RIGHT BALANCE

RegulatoryFramework

HealthHealth& Safety& Safety

EnvironmentalEnvironmentalImpactImpact

TechnicalTechnicalFeasibilityFeasibility

CostCostEffectivenessEffectiveness

23

TECHNICAL SESSION

The Process of Decommissioning and Removing Offshore and AssociatedOnshore Oil and Gas Facilities

The Plugging Process: Securing Old Gas & Oil Wells for theProtection of the Environment, Steve Fields and Max Martin ........ 25

Offshore Production Facilities: Decommissioning of TopsideProduction Equipment, Dr. Peter Prasthofer .................................. 38

Removal and Disposal of Deck and Jacket Structures,Andy Culwell ................................................................................... 48

Pipeline and Power Cable Decommissioning,Andy Culwell and Jack McCarthy ................................................... 66

Site Clearance and Verification, Jack McCarthy................................... 74

Decommissioning of Onshore Facilities: Technical Issues,Luis Perez....................................................................................... 83

Technical Session

25

THE PLUGGING PROCESS: SECURING OLD GAS & OIL WELLS FORTHE PROTECTION OF THE ENVIRONMENT

STEVEN A. FIELDSDepartment of Conservation, Division of Oil, Gas, and Geothermal Resources

and

MAX M. MARTINTwachtman Snyder & Byrd, Inc.

Reviewed by Members of the Technical Program Subcommittee consisting of representatives from the MineralsManagement Service, California State Lands Commission, Department of Conservation, Division of Oil, Gas, andGeothermal Resources, County of Santa Barbara-Resources Management Division, League of Women Voters,Twachtman Snyder & Byrd, Inc., American Pacific Marine, Inc., and Chevron USA, Inc.

INTRODUCTION

The waters off the coast of California contain atotal of 27 oil and gas platforms. Of the 27, fourare located in state tidelands (within three milesof the coast) and 23 are located in the FederalOuter Continental Shelf (OCS). There are alsosix artificial islands located in state tidelands. Asthe end of service life approaches for thesefacilities, plans for their decommissioning needto be developed.

The decommissioning process begins long beforethe cessation of production. An effective pre-planning program should be established at leasttwo years before decommissioning the structure. Planning is the key to ensuring that the workperformed will be effective, efficient,environmentally sound, and within the financialresources of the owners.

The scope of decommissioning work is definedthrough the coordinated efforts of platformoperators and regulatory agencies who overseethe specific field involved. In California, theseagencies are the Minerals Management Services(MMS), the Department of Conservation, Divisionof Oil, Gas, and Geothermal Resources (DOC),and the California State Lands Commission(CSLC).

PRE-PLANNING

The key to optimizing asset value in adecommissioning project is allowing enoughlead-time to properly create a strategy thatallows an operator to choose the best disposalmethod for their property. The considerations to

be addressed when planning a decommissioningproject are as follows:

Platform/Site Evaluation

Available information regarding the site and thestructure (amount of debris in the site, drawings,inspection records, etc.) will facilitate the possiblesale/reuse of the platform, thus decreasing theoverall liability.

Environmental Considerations

An assessment of the environmental conditionssurrounding the platform site needs to beperformed, thereby informing the operator how thedecommissioning operations might affect thesurrounding marine ecosystem.

Financial Strategy

The owner needs to know the current costs ofdecommissioning a facility (including wellplugging and abandonment [P & A] costs) inorder to accurately accrue them as a liability.

Disposal Planning

Establishing a variety of potential disposalmethods allows the company to derive theoptimal value from the assets being removed.

Contracting Strategy

By formulating a contracting strategy, the ownerwill minimize the overall costs of contractedwork that will be performed duringdecommissioning activities.


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Regulatory Requirements

The regulatory requirements for well plugging andabandonment (P & A) in California are as follows:Minerals Management Services (MMS)

The basic plugging requirements are found in30 CFR 250.110 Subpart G.

Department of Conservation, Division of Oil,Gas, and Geothermal Resources (DOC)

The basic plugging requirements are found inthe California Code of Regulations Title 14Division 2, Chapter 4 beginning with Section1745.

California State Lands Commission (CSLC)

The basic plugging requirements in theCalifornia Code of Regulations Title 2 Section2128(q).

The plugging design must meet or exceedregulatory requirements. These requirementshave been developed in cooperation with industryparticipants through years of experience. Thebasic plugging requirements for all three agenciesare written to have general application to all wells. In that all wells are not the same, specificprocedures may be approved to fulfill theserequirements.

The plugging and abandonment of offshore wellsis performed by the operators of the wells withguidance provided by these regulatory agencies. In state tidelands, the DOC and CSLC directlyoversee all plugging and abandonmentoperations. In outer continental shelf (OCS)waters, the operations are conducted under thedirection of the MMS. Operators and regulatoryagencies work together as a team to successfullyachieve the same goals.

Shutdown Planning

An early step in the process for decommissioningis to plan cessation of production and injectionoperations. The operator designs a shut downplan that will allow plugging and abandonmentoperations to proceed without the threat ofpollution. This plan is designed to safelydiscontinue production and secure the platformand well until the actual P & A operations cancommence.

PLUGGING AND ABANDONMENTPLANNING

Synthesize Information

The plugging and abandonment of wells is one ofthe primary stages of a facility abandonmentprogram. An effective plugging and abandonmentprocedure is critical for the proper sealing of an oiland gas wellbore to safely secure it from futureleakage. Techniques used to accomplish thisprocess are based on industry experience,research, and conformance with applicableregulatory compliance standards and require-ments. The synthesis of practical knowledge,current technology, and regulatory requirementsresults in the most effective wellbore plugging andabandonment possible. Only by planning aheadcan this occur.

When an operator determines a need to plug andabandon wells on a given facility, they begin with areview of the existing well design along withrecords of past work, well past performance, and geological and reservoir conditions. The operatorinvestigates all items that may relate to health andsafety issues as well as regulatory requirements. The operator then designs a program based onreservoir and existing wellbore conditions. Thiswill allow the operator to plan an abandonmentprogram that will satisfy the goal of making thewells safe from future leakage and preserving theremaining natural resources.

Inspection and Testing

A preliminary wellbore / wellhead inspection andsurvey should be performed to document presentconditions. All of the valves on the wellhead andtree are checked to ensure operability; if not, theywill be hot-tapped.

A slickline unit is then installed to check forwellbore obstructions, to verify measured depths,and to gauge the internal diameter of tubing. Theslickline unit is also used to pull safety valves asneeded. A slickline unit is a machine with ahydraulically controlled spool of wire used forsetting and retrieving safety valves, lugs, gas liftvalves, and running bottom hole pressures. Slicklines are also used for a variety of other jobssuch as recovering lost tools and swedging outtubing.

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27

The slickline unit is then removed and a wellservice pump is installed to fill annuli and tubingwith fluid to establish an injection rate intoperforations and/or to pressure up tubing andcasing to check for integrity. Casing annuli arealso pressure tested to check for communicationproblems between casing strings and to recordtest pressures over a period of time.

Well Containment Plan

The operator must design a well containmentplan. This plan includes determining the currentreservoir condition and includes establishingcontingency responses to events that may occurwhile working on the well.

Anytime work is performed on a well, there is achance that something might go wrong. However,proper planning and use of appropriate safetyequipment can reduce the potential for problems. An important piece of equipment on the wellboreis the blowout prevention equipment (BOP). If thewell head tree is to be removed, back-pressurevalves are first installed, followed by removing thetree and then installing the BOP(s). The purposeof the BOP is to be able to close down and controlthe well in the event of a well flow. Prior tocommencing downhole operations, thecomponents of the BOP are function tested andthen pressure tested to ensure that allcomponents are in good working order. Thesetests are sometimes witnessed by representativesof the MMS (for federal waters) and/or the DOC(in state tidelands).

WELL ABANDONMENT

Basic Methods for P & A

The plugging and abandonment of offshore wellsworldwide has been accomplished utilizing threedifferent P & A methods: Rig , Coil Tubing Unit ,and Rigless .

Rig

A rig is the derrick or mast, drawworks, andattendant surface equipment (circulation system,rotating equipment, hoisting system, well controlequipment, power system, pipe and handlingequipment, and any additional heavy equipmentrequired) of a drilling or workover unit. The rig ispowered by gas generators or diesel engines andhas a basic crew of five to six men. This type of

equipment is either a small workover rig that isbrought to the site or an existing drilling derrickthat is already onsite. The rig must have the ratedcapacity to pull the downhole equipment out of thewellbore (including casing if necessary). Using arig to P & A a well proceeds much like a normalworkover on a well.Before working on the well, fluid is either pumpedinto the wellbore or circulated to eliminate anypressures that might be present. Usually backpressure valves are usually installed in the welland the tree or wellhead is removed, after whichthe blowout prevention equipment is installed. After testing the BOP, the tubing is pulled and thepre-planned plugging procedure for the well isfollowed. Well plugging will usually require aminimum of three cement plugs to controlmigration of fluids (gas and oil) and protect freshwater sands. If necessary, rigs have the ability topull tubing, cut and pull casing, recover scrap, setpackers or retainers, and to drill out retainers inthe well.

Coil Tubing Unit (CTU)

These are small units that carry tubing coiledaround a large drum. In the mid-1980's, the coiltubing operations were limited to sand cleanoutsand nitrogen jet services. However, recentadvances have made CTU’s useable inproduction and abandonment operations. Theunits are much like rigs in that they have pumps tocirculate fluid and test BOP’s (on a more limitedscale). Coil tubing has been successfully used toP & A wells in the North Sea, the Gulf of Mexico,Southeast Asia, and the Middle East. Today’sCTU’s have the ability to perform almost any typeof well P & A task that arises. Contemporary unitsoperate with 10,000 psi and come in sizes up to2.5 inches (ID) or larger. In addition, a 15,000 psiunit has been developed.

Offshore California plugging and abandonmentoperations using coil tubing has, to date, beenlimited to use on the Rincon Piers.

Rigless Abandonment

Rigless P & A involves several steps. First, acementing unit mixes and pumps cementbatches through the tubing placed in thewellbore. This results in the placement of thefirst and second (of at least three) cement plugsat different depths. Wireline and electric lineunits assist with the placement of the two


28

cement plugs. The P & A crew verifies the top ofcement plugs by tagging it with the slick lineunits and pressure testing the top of the plugs. This method is used on both the initial andsecondary plug. Afterwards, the platform crane,or a portable crane, is used to remove the verytop portion of tubing from the hole. The crewthen pumps the third cement plug. Well casingsare cut below the sea floor with an electric lineand/or an abrasive cutter, mechanical cutter, orother method. The casing is then pulled bycasing jacks and/or a crane.In the final examination of each plugged andabandoned well, there are no differences in theresults of rig versus rigless methods (Figures 1-4). Step one shows two identical wells that willbe plugged and abandoned with each method. Step two shows these wells after the bottomplugs have been set with the tubing having beenpulled out of the well. Step three shows thebalanced cement plug with the rigless methodand the spotted cement plug with the rig method. It is important to remember that with the riglessmethod the tree is still on, while the rig methoduses BOP’s which have to be tested. Figure 4shows the rigless method having cut theproduction casing with a CIBP (cast iron bridgeplug) set with 200+ feet of cement on top. Therig shows the same with a little more casing outof the hole.

Figure 1. Typical Wellbore Schematic.

Well P&A -Well P&A -Rig vs.Rig vs.RiglessRigless

Step 1Step 1

26" @ 804'

18-5/8" @ 1607'

13-3/8" @4344'

9-5/8" @ 9945'

4-1/2" Liner top@ 9549'

4-1/2" @10,545'

Perforations

Figure 2. Bottom plugs set with tubing pulled outof hole.


Step 2Step 2

26" @ 804'

18-5/8" @ 1607'

13-3/8" @4344'

9-5/8" @ 9945'

4-1/2" Liner top@ 9549'

4-1/2" @10,545'

26" @ 804'

18-5/8" @ 1607'

13-3/8" @4344'

9-5/8" @ 9945'

4-1/2" Liner top@ 9549'

4-1/2" @10,545'

RIGLESS RIG

BOTTOM SQUEEZE

PERFORATIONS

Figure 3. Balanced plug on rigless and stoppedplug with the rig.


Step 3Step 3

18-5/8" @ 1607'

13-3/8" @4344'

9-5/8" @ 9945'

4-1/2" Liner top@ 9549'

4-1/2" @10,545'

26" @ 804'

18-5/8" @ 1607'

13-3/8" @4344'

9-5/8" @ 9945'

4-1/2" Liner top@ 9549'

4-1/2" @10,545'

RIGLESS RIG

300' INTERMEDIATECEMENT PLUG

BOTTOM SQUEEZE

PERFORATIONS

Figure 4 . Rigless with cut casing and CIBP; Rigwith same but with a little more casing out of hole.


Step 4Step 4

18-5/8" @ 1607'

13-3/8" @4344'

9-5/8" @ 9945'

4-1/2" Liner top@ 9549'

4-1/2" @10,545'

26" @ 804'

18-5/8" @ 1607'

13-3/8" @4344'

9-5/8" @ 9945'

4-1/2" Liner top@ 9549'

4-1/2" @10,545'

RIGLESS RIG

300' INTERMEDIATECEMENT PLUG

200' SURFACECEMENT PLUG

W/ CIBP

BOTTOM SQUEEZE

PERFORATIONS

At present, approximately five hundred wells peryear are plugged and abandoned in the Gulf ofMexico (GOM) using the rigless method, asopposed to the 100-120 plugged and abandonedin the GOM using rigs. Acceptance of the rigless

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method (the primary form of well P & A used inthe Gulf of Mexico) has been expanded to NorthSea operations to include both platform wellsand subsea wells. Although rigs have traditionally been used toplug and abandon subsea wells, severalcontractors in the North Sea region haveexperience using a diving support vessel and/ora dynamic positioning vessel for the procedure. Based on research regarding actual North Seajobs, 3.6 days is the average time to plug andabandon non-problem subsea wells using therigless method.

Basic Steps for Well P & A

Remove Downhole Equipment

In certain areas, like offshore California, the firststep that is necessary for well P & A is theremoval of the downhole equipment. This isaccomplished by using a conventional workoveror existing drilling rig that has the rated capacity topull the downhole equipment from the wellbore. The operator is required to make a diligent effortto remove all downhole equipment. This includesitems such as packers, production tubing, gas liftmandrels, and downhole pumps. Past workrecords on the well may be reviewed to determineif the effort has been made prior to commencing P& A operations. However, due to age and theconditions downhole, it is not always possible toretrieve all downhole equipment. Some of theequipment may be stuck in the wellbore due toscale, fill, or breakage. In any case, all downholeproduction or injection equipment that cannot beremoved can be left in the well if approved by theappropriate agencies.

Wellbore Cleanout

After the downhole well equipment has beenremoved, a concerted effort must be made toremove the fill, scale, and other debris coveringperforations that have not been previouslyplugged. The circulating fluid used to clean outthe wellbore is required to have a sufficient densityto control subsurface pressure and should havephysical characteristics capable of removing theunwanted material. Additional tools or additivesmay be necessary to properly clean the wellbore.

Cement Plugging Methods

A cement plug is a volume of cement designed tofill a certain length of casing or open hole and

provide a seal against vertical migration of fluid orgas. There are various methods in which to placecement in the wellbore. The method used isdependent on wellbore conditions and regulatoryrequirements. Cement is pumped into the well(as a fluid) and placed in the desired location. Due to heat and pressure, through time (anumber of hours) the cement hardens.Plugging procedures throughout the worldrequire a minimum of three (3) cement plugs. The first is usually the squeezing of the oldproducing zone to eliminate the influx into thewellbore of any fluid or gas. The second, middleplug, is usually placed near the middle of thewellbore or near a protective pipe shoe. Finally,the surface plug is installed within 200-300 feetbelow the mudline. Most plugs are 100 to 200feet in length. Additional plugs are installedbased on actual wellbore conditions.

Squeezing

Squeeze cementing is the most common methodfor plugging reservoirs. Squeeze cementing isalso used in plugging and abandonmentoperations to place cement below "junk" that maybe left in the wellbore or to get cement outside ofpreviously uncemented (or poorly cemented)casing.Common types of cement squeezes are thebraidenhead method and the bullhead method. The braidenhead method is when cement isplaced in a fashion similar to the balance plugmethod (see below), but then the well is shut-inand additional pressure is placed at the surfacefrom the casing valve to force the cement furtherdown the wellbore. The bullhead squeeze iscement pumped from the surface and forceddown the wellbore by pump pressure from thesurface.

Balance Plug/Displacement

This method is used for middle plug placement. The cement slurry is pumped down pipe, coiledtubing, workstring, or production tubing until thecement level outside the pipe is slightly below thetop of cement (TOC) inside the pipe. The cementthen falls out of the pipe, filling the void left as thepipe is slowly removed. Fluid spacers can beused both ahead and behind the cement slurry toaid in the proper placement of the cement.


30

Dump Bailer

The dump bailer is a tool that contains ameasured quantity of cement that is lowered intothe wellbore on a wireline. The bailer is openedon impact (i.e. striking a bridge plug or cementretainer, etc.) or by electronic activation. Thismethod is limited by the volume of cement thatcan be placed and by the depth at whichplacement can occur. However, the dump bailermethod does have the advantage of accurateplacement of small quantities of cement (i.e., 10to 60 feet). In state tidelands this method ofplacing may not meet regulatory requirements,while in federal waters no specific regulationsprohibit this method of placing cement plugs(when placed in conjunction with cast iron bridgeplugs).

Cement Grade and Quality

In state waters the grade and quality for the typeof cement must meet standards defined by theAmerican Petroleum Institute (API). API defines acompetent cement plug as one that maintains acompressive strength of at least 1,000 pounds persquare inch (psi) and a maximum liquidpermeability of 0.1 millidarcy (md). The operatormust have evidence that the proposed cementgrade meets the minimum standards. All majorcementing companies and P & A contractors useAPI cement. All cement grinds (batches ofcement) are purchased with specification sheetsshowing the properties of the mixture. They alsohave the American Society for Testing andMaterials (ASTM) C-150 Standard specificationsfor Portland cement explained on the same sheet(Table 1).

API cement comes in different classes which arebased on the temperature downhole where thecement is to be placed. Cementing operationsnormally call for pumping in a fluid (which is thevolume of the pipe depth plus 10 or more barrels)before the cement is started so that the cementwill reach the desired location. After the desiredamount of fluid has been pumped in, the cementis started. This procedure reduces thetemperature near the wellbore (or wherever thecement is supposed to go), thereby causing aneed for calculating the bottom hole temperature(BHT) when the cement arrives at the targeteddepth. Some operators run lab tests on thecement before using it in the field to verify thesecalculations, but in doing so it is important to

remember to gather a sample of the mix water tobe used (in the field) and include it in the lab testsample.

As there are many types of cements used in theplugging and abandonment of wells, the operatordesigns the cement slurry with three items inmind: 1) meeting the API definition for acompetent cement plug; 2) meeting APIrecommended practices as detailed in API Spec10; 3) creating a mixture that will perform the jobin the most efficient manner.

Mud Program

All portions of the well not plugged with cementare to be filled with a fluid having a sufficientdensity to exert a hydrostatic pressure in excessof the greatest formation pressure in the intervalsbetween plugs. The purpose of this fluid is tocontrol any possible influx of formation fluids(water, oil, or gas) into the wellbore. State andfederal regulations differ somewhat in the fluidthat is to be placed in the intervals between plugs.

In state tidelands, the fluid must be inert, thedensity of the fluid must exert a hydrostaticpressure exceeding the greatest formationpressure in the intervals between plugsencountered during drilling, and the fluid musthave the proper characteristics to suspend theweight material in the fluid. Excessive mud weightcan be detrimental in produced or depleted wells.If produced zones are pressure-depleted or belownormal pressure, excess mud density can causea leak-off and result in the loss of well control fluid.

Federal regulations require that the fluid only havethe proper density to exert a hydrostatic pressureexceeding the greatest formation pressure in theintervals between plugs at the time ofabandonment.

The fluid that is used to fill all portions of the wellnot plugged with cement can either be mixed on-site or can be used drilling mud or completion fluidbrought from drilling or completion operations (ifsaid fluid is reconditioned). Old mud that has notbeen run through and cleaned is not usable forcontainment purposes in the wells beingabandoned.

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31

Table 1BASIC CEMENTING MATERIALS

A basic cementing material is classified as one that, without special additives for weight control or settingproperties, when mixed with the proper amount of water, will have cementitous properties. This may be asingle ingredient or a combination of two or more ingredients, but they are always used in this combinationof two or more ingredients, but they are always used in this combination even when special additives areused with them. The following are of this class:

Portland Cement Pozmix CementHigh Early Cement Pozmix 140Retarded Cement

API CLASSIFICATION FOR OIL WELL CEMENTS*

Class A: Intended for use from surface to 6,000 feet (1830 m) depth* when special properties arenot required. Available only in ordinary type (similar to ASTM C 150, Type I).**

Class B: Intended for use from surface to 6,000 feet (1830 m) depth, when conditions requiremoderate to high sulfate-resistance. Available in both moderate (similar to ASTM C 150,Type II) and high sulfate-resistant types.

Class C: Intended for use from surface to 6,000 feet (1830 m) depth, when conditions require highearly strength. Available in ordinary and moderate (similar to ASTM C 150, Type III) andhigh sulfate-resistant types.

Class D: Intended for use from 6,000 feet to 10,000 feet (1830 m to 3050 m) depth, underconditions of moderately high temperatures and pressures. Available in both moderateand high sulfate-resistant types.

Class E: Intended for use from 10,000 feet to 14,000 feet (3050 m to 4270 m) depth, underconditions of high temperatures and pressures. Available in both moderate and high sul-fate-resistant types.

Class F: Intended for use from 10,000 feet to 16,000 feet (3050 m to 4880 m) depth, underconditions of extremely high temperatures and pressures. Available in both moderateand high sulfate-resistant types.

Class G&H: Intended for use as a basic well cement from surface to 8,000 feet (2440 m) depth asmanufactured or can be used with accelerators and retarders to cover a wide range ofwell depths and temperatures. No additions other than calcium sulfate or water or both,shall be interground or blended with the clinker during manufacture of Class G or H wellcement. Available in moderate and high sulfate-resistant types.

* Reproduced by permission from API Spec. 10 "API Specification for Materials and Testing for Well Cements." Depth limits arebased on the conditions imposed by the casing-cement specification tests (Schedules 1, 4, 5, 6, 8, 9) and should be considered asapproximate values.

**ASTM C 150: Standard Specification for Portland Cement. Copies of this specification are available form American Society forTesting and Materials, 1916 Race Street, Philadelphia, PA 19103.


32

Verification and Pressure Testing of Plugs

Tagging TOC (Top of Cement)

All cement work is handled using calculatedcement volumes to achieve the appropriate TOC. The two methods most commonly used to ensureproper cement plug placement are: 1) use open-ended pipe to tag the plug (having previouslymeasured the pipe and using that measurementas a point of reference); 2) use wireline tools totag the plug and determining the TOC by lookingat the counter on the wireline.

Pressure Testing Method

The pressure testing of the integrity of eachcement plug by tagging it with open-ended pipe(as required by governmental regulations) hasboth positive and negative points:

• Pressure is exerted only on cross sectionsof the working pipe. This concentratesloads on the area where the pipe touchesthe cement;

• Reliance on the weight indicators may ormay not be accurate at 15,000 psi;

• Shallow plugs might not have enough pipeweight to test;

• When using pipe weight, buoyancy factorsand friction from the pipe against thecasing must be taken into consideration.

Testing with pump pressure for integrity (asrequired) also has both positive and negativepoints:

• Pressure is exerted uniformly on the entirearea of the plug;

• Pump pressure can be checked moreaccurately;

• A recorder can be installed, allowing thepressure to be recorded over time;

• Pressure is in addition to the hydrostaticpressure already on the plug;

• Individual portions of the plug cannot betested.

Swab Testing Method

Swabbing is another method for pressure testingcement plugs. The wellbore fluid is swabbed downuntil the hydrostatic fluid above the plug is belowthe reservoir pressure gradient of the zoneisolated by the plug. The fluid level is monitoredfor a reasonable time to ensure that the wellborefluids have stabilized. If the fluid level has notchanged, plug competency is considered verified. It should be noted that this method is usedexclusively in California.

Certain particulars about the swabbing methodshould be reviewed. They are:

• There is the possibility of running coil tubingin the hole where displacement occursusing nitrogen. This has the same effectas swabbing;

• Swabbing requires more time than othermethods;

• The cement plug could weaken whendifferentially tested, resulting in possiblefailure at a later date when fluid isreintroduced on top of the plug;

• Accurate measurements of bubble riserates are difficult to determine when usingthe swabbing method.

CONCLUSIONS

By referring to past decommissioning projectsand following guidelines set by regulatoryagencies, a formal decommissioning plan can bedeveloped which includes effective and efficientmethodologies for plugging and abandoningwells. Although well P & A is generallyconsidered one of the more sensitive portions ofthe decommissioning process, thorough pre-planning significantly reduces the number ofassociated uncertainties.

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REFERENCES

American Petroleum Institute. 1993. Environmental Guidance. Well Abandonmentand Inactive Well Practices for U.S.Exploration and Production Operations. APIBulletin E3. Washington, D.C.

Amoco Corporation Worldwide Engineering &Construction. June 1997. Gulf of MexicoCase Studies: Current and FurtherDevelopments in Decommissioning. IBCDecommissioning Conference. Aberdeen,Scotland.

California Division of Oil, Gas, and GeothermalResources. 1997. California Laws forConservation of Petroleum and Gas. DOCPub. No. PRC01. Sacramento, CA.

California Division of Oil, Gas, and GeothermalResources. 1997. California Code ofRegulations, Title 14. DOC Pub. No. PRC04.Sacramento, CA.

Fields, Steve. March 1994. Abandonment andRemoval of Offshore Oil and Gas Facilities:Education and Information Transfer: WellAbandonment. Santa Barbara, CA.

Griggs, Mary. March 1994. Abandonment andRemoval of Offshore Oil and Gas Facilities:Education and Information Transfer: Overviewof the Regulatory Framework andEnvironmental Review Process for OffshoreCalifornia. Santa Barbara, CA.

Halliburton Company. 1995. Cementing Tables-1995. Duncan, OK.

IBC Conference. Dec 1996. Well Plugging andAbandonment. Houston, TX.

Journal of Petroleum Technology. May 1996. CoilTubing Technologies Update.

Journal of Petroleum Technology. June 1997. Coil Tubing Applications.

Journal of Petroleum Technology. August 1997. Cementing Operations.

Smith, Jack L. 1993. Problems Associated withCoiled Tubing Operations During WellAbandonment. California Division of Oil, Gas,and Geothermal Resources (unpublishedstudy).

World Oil. March 1997. C-1 Cementing.

Wygle, Peter R. 1995. Blowout Prevention inCalifornia. California Division of Oil, Gas, andGeothermal Resources Pub. No. MO7.Sacramento, CA.


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Minimum Cased Hole Plugging RequirementsState (California)

1. A cement plug shall be placed opposite all perforations extending to a minimum of 100 feet above theperforated interval, liner top, cementing point, water shut-off holes or the zone, whichever is higher(1745.1[c]).

2. The location and hardness of the cement plugs must be verified by placing the total weight of the pipestring, or an open-end pipe weight of 10,000 pounds and by application of pump circulation. DOC towitness location and hardness (1745.6).

3. Inside cemented casing, a cement plug at least 100 feet long must be placed above each oil or gas zonewhether or not the zone is perforated (1745.1[d]).


5. A 100-foot cement plug above the shoe of the immediate or second surface casing (1745.1 [d]).


7. A 100 foot plug across the freshwater/saltwater interface or opposite any impervious strata betweenfresh and saltwater zones (1745.1 [d]).


9. In the event that junk cannot be removed from the hole and the hole below the junk is not properlyplugged, then cement plugs must be placed as follows (1745.2):

(a) Sufficient cement must be squeezed through the junk to isolate the lower oil, gas, or freshwaterzones and a minimum of 100 feet must be placed on top of the junk (but no higher then the seabed).

(b) If the top of the junk is opposite uncemented casing, then the casing annulus immediately abovethe junk must be cemented with sufficient cement to insure isolation of the lower zones.

10. Anytime casing is cut and recovered, other then for the surface plug, a cement plug must be placed fromat least 100 feet below to at least 100 feet above the stub (1745.3).

11. The location and hardness of the cement plug must be verified by placing the total weight of the pipestring, or an open-end pipe weight of 10,000 pounds and by application of pump circulation. Division towitness location and hardness (1745.6).

12. No annular space that extends to the ocean floor must be left open to drilled hole below. A minimum of200 feet of the annulus immediately above the shoe must be plugged (1745.4).

13. A cement plug at least 100 feet long must be placed in the well with the top between 50 and 150 feetbelow the ocean floor. All inside casing strings with uncemented annuli must be pulled from below the

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surface plug. The casing must not be shot or cut in a manner that will damage outer casing strings andprevent re-entry into the well (1745.5).

14. The location and hardness of the cement plug must be verified by placing the total weight of the pipestring, or an open-end pipe weight of 10,000 pounds and by application of pump circulation. DOC towitness location and hardness (1745.6).

15. All portions of the hole not plugged with cement must be filled with a inert fluid of sufficient density toexert hydrostatic pressure exceeding the greatest formation pressure encountered while drilling suchinterval. DOC will test the mud to determine that it meets minimum requirements (1745.7).

16. All casing and anchor piling must be cut and removed from not more than 5 feet below the ocean floor,and the ocean floor clearing of cleared of obstruction (1745.8).

FEDERAL

30 CFR SUBPART G-- ABANDONMENT OF WELLS

250.110 General Requirements

The lessee shall abandon all wells in a manner to assure downhole isolation of hydrocarbon zones,protection of freshwater aquifers, clearance of sites so as to avoid conflict with other uses of the OuterContinental Shelf (OCS), and prevention of migration of formation fluids within the wellbore or to theseafloor. Any well which is no longer used or useful for lease operations shall be plugged and abandonedin accordance with the provisions of this subpart. However, no production well shall be abandoned untilits lack of capacity for further profitable production of oil, gas, or sulphur has been demonstrated to thesatisfaction of the District Supervisor. No well shall be plugged if the plugging operations would jeopard-ize safe and economic operations of nearby wells, unless the well poses a hazard to safety or theenvironment.

250.111 Approvals

The lessee shall not commence abandonment operations without prior approval of the District Supervi-sor. The lessee shall submit a request on Form MMS-124, Sundry Notice and reports on Wells, forapproval to abandon a well and a subsequent report of abandonment within 30 days from completion ofthe work in accordance with the following:

(a) Notice of Intent to Abandon Well . A request for approval to abandon a well shall contain the reasonfor abandonment including supportive well logs and test data, a description and schematic of pro-posed work including depths, type, location, length of plugs, the plans for mudding, cementing,shooting, testing, casing removal, and other pertinent information.

(b) Subsequent report of abandonment . The subsequent report of abandonment shall include adescription of the manner in which the abandonment or plugging work was accomplished, includingthe nature and quantities of materials used in the plugging, and all information listed in paragraph (a)of this section with a revised schematic. If an attempt was made to cut and pull any casing string, thesubsequent report shall include a description of the methods used, size of casing removed, depth ofthe casing removal point, and the amount of the casing removed from the well.

250.112 Permanent Abandonment

(a) Isolation of zones in open hole . In uncased portions of wells, cement plugs shall be set to extendfrom a minimum of 100 feet below the bottom to 100 feet above the top of any oil, gas, or freshwaterzones to isolate fluids in the strata in which they are found and to prevent them from escaping into


36

other strata or to the seafloor. The placement of additional cement plugs to prevent the migration offormation fluids in the wellbore may be required by the District Supervisor.

(b) Isolation of open hole . Where there is an open hole below the casing, a cement plug shall be placedin the deepest casing by the displacement method and shall extend a minimum of 100 feet above and100 feet below the casing shoe. In lieu of setting a cement plug across the casing shoe, the followingmethods are acceptable:

(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effectiveback-pressure control and shall be set not less than 50 feet and not more than 100 feet above thecasing shoe. The cement plug shall extend at least 100 feet below the casing shoe and at least 50feet above the retainer.

(2) If lost circulation conditions have been experienced or are anticipated, a permanent-type bridgeplug may be placed within the first 150 feet above the casing shoe with a minimum of 50 feet ofcement on top of the bridge plug. This bridge plug shall be tested in accordance with paragraph(g) of this section.

(c) Plugging or isolating perforated intervals . A cement plug shall be set by the displacement methodopposite all perforations which have not been squeezed with cement. The cement plug shall extend aminimum of 100 feet above the perforated interval and either 100 feet below the perforated interval ordown to a casing plug, whichever is the lesser. In lieu of setting a cement plug by the displacementmethod, the following methods are acceptable, provided the perforations are isolated from the holebelow:

(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effectiveback-pressure control and shall be set not less than 50 feet and not more than 100 feet above thetop of the perforated interval. The cement plug shall extend at least 100 feet below the bottom ofthe perforated interval with 50 feet placed above the retainer.

(2) A permanent-type bridge plug shall be set within the first 150 feet above the top of the perforatedinterval with at least 50 feet of cement on top of the bridge plug.

(3) A cement plug which is at least 200 feet long shall be set by the displacement method with thebottom of the plug within the first 100 feet above the top of the perforated interval.

(d) Plugging of casing stubs . If casing is cut and recovered leaving a stub, the stub shall be plugged inaccordance with one of the following methods:

(1) A stub terminating inside a casing string shall be plugged with a cement plug extending at least100 feet above and 100 feet below the stub. In lieu of setting a cement plug across the stub, thefollowing methods are acceptable:

(i) A cement retainer or a permanent-type bridge plug shall be set not less than 50 feet abovethe stub and capped with at least 50 feet of cement, or

(ii) A cement plug which is at least 200 feet long shall be set with the bottom of the plug within100 feet above the stub.

(2) If the stub is below the next larger string, plugging shall be accomplished as required to isolatezones or to isolate an open hole as described in paragraphs (a) and (b) of this section.

(e) Plugging of annular space . Any annular space communicating with any open hole and extending tothe mud line shall be plugged with at least 200 feet of cement.

(f) Surface plug . A cement plug which is at least 150 feet in length shall be set with the top of the plugwithin the first 150 feet below the mud line. The plug shall be placed in the smallest string of casingwhich extends to the mud line.

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(g) Testing of plugs . The setting and location of the first plug below the surface plug shall be verified byone of the following methods:(1) The lessee shall place a minimum pipe weight of 15,000 pounds on the cement plug, cement

retainer, or bridge plug. The cement placed above the bridge plug or retainer is not required to betested.

(2) The lessee shall test the plug with a minimum pump pressure of 1,000 pounds per square inchwith a result of no more than a 10 percent pressure drop during a 15-minute period.

(h) Fluid left in hole . Each of the respective intervals of the hole between the various plugs shall be filledwith fluid of sufficient density to exert a hydrostatic pressure exceeding the greatest formation pres-sure in the intervals between the plugs at time of abandonment.

(i) Clearance of location . All wellheads, casings, pilings, and other obstructions shall be removed to adepth of at least 15 feet below the mud line or to a depth approved by the District Supervisor. Thelessee shall verify that the location has been cleared of all obstructions in accordance with 250.114 ofthis part. The requirement for removing subsea wellheads or other obstructions and for verifyinglocation clearance may be reduced or eliminated when, in the opinion of the District Supervisor, thewellheads or other obstructions would not constitute a hazard to other users of the seafloor or otherlegitimate uses of the area.

(j) Requirements for permafrost areas . The following requirements shall be implemented forpermafrost:

(1) Fluid left in the hole adjacent to permafrost zones shall have a freezing point below the tempera-ture of the permafrost and shall be treated to inhibit corrosion.

(2) The cement used for cement plugs placed across permafrost zones shall be designed to setbefore freezing and to have a low heat of hydration.

250.113 Temporary abandonment.

(a) Any drilling well which is to be temporarily abandoned shall meet the requirements for permanentabandonment (except for the provisions in 250.112 (f) and (i), and 250.114) and the following:

(1) A bridge plug or a cement plug at least 100 feet in length shall be set at the base of the deepestcasing string unless the casing string has been cemented and has not been drilled out. If a ce-ment plug is set, it is not necessary for the cement plug to extend below the casing shoe into theopen hole.

(2) A retrievable or a permanent-type bridge plug or a cement plug at least 100 feet in length, shall beset in the casing within the first 200 feet below the mud line.

(b) Subsea wellheads, casing stubs, or other obstructions above the seafloor remaining after temporaryabandonment will be protected in such a manner as to allow commercial fisheries gear to pass overthe structure without damage to the structure or fishing gear. Depending on water depth, nature andheight of obstruction above the seafloor, and the types and periods of fishing activity in the area. theDistrict Supervisor may waive this requirement.

(c) In order to maintain the temporarily abandoned status of a well, the lessee shall provide, within I yearof the original temporary abandonment and at successive l-year intervals thereafter, an annual reportdescribing plans for reentry to complete or permanently abandon the well.

(d) Identification and reporting of subsea wellheads, casing stubs, or other obstructions extending abovethe mud line will be accomplished in accordance with the requirements of the U.S. Coast Guard.


38

OFFSHORE PRODUCTION FACILITIES: DECOMMISSIONING OFTOPSIDE PRODUCTION EQUIPMENT

DR. PETER PRASTHOFERTechnical Manager

Offshore Decommissioning Communications Project

EXECUTIVE SUMMARYThe removal and disposal of topside facilities isan integral part of the overall decommissioningactivity for an offshore platform. Topsides canvary significantly in size, functionality andcomplexity, and hence, a range of decommis-sioning options has been identified in technicalstudies. The technologies to implement themare not all equally mature and, in general,removal is a more complex operation thaninstallation. One feature common to all options isthat the facilities will need to be cleaned and allprohibited substances removed in accordancewith regulations.

The environmental impact of each option hasgenerally been shown to be small. Otheraspects to be considered are health and safetyand cost. Opportunities for reuse are drawingincreased attention, but are limited by the costsof refurbishment of the older facilities and theevolution of stricter technical standards. Further,particularly for the larger facilities, componentswere generally designed for a specific set offunctional requirements that may not fit theoperating and processing demands of a newfacility.

The diversity and range of complexity of topsidefacilities suggest that no one option is likely to bethe most appropriate in all cases, particularlywhen seen in the context of the decommission-ing of the total installation.

INTRODUCTIONThe purpose of this paper is to provide somebackground into the issues associated with theremoval and disposal of the topside facilities ofoffshore platforms. It discusses the manyaspects that have to be considered, anddescribes the complexities that must be takeninto account in developing a plan for removaland disposal of topside facilities. Topsidefacilities refer to the deck supporting structureand the plant for drilling, processing and export

of oil and/or gas, and the utilities, accommoda-tion and life support facilities.

The document addresses the key issues relatedto the technical state of the art, safety andenvironmental considerations, including energyusage, cost, and opportunities for reuse andrecycling. Areas are identified where furthertechnical or scientific studies are warranted. It isintended that discussion of these issues, thesignificance of which vary among differentdecommissioning options and different types offacilities, will lead to a better understanding ofthe framework within which a balance has to beachieved between the protection of theenvironment and safety, health, technologicaland economic considerations.

DESCRIPTION AND SPECIALCONSIDERATIONS“Topsides”, “topside facilities”, or “deck” is theterminology used, sometimes interchangeably,for the facilities which include the plant forprocessing oil/gas and accommodation. Alsoincluded, for the purpose of this report, is thesteel supporting structure, either separate orintegrated with the facilities, that supports thefacilities on the substructure. The steelsupporting structure is sometimes called “thedeck” or “module support frame”.

Topsides may vary greatly in functionality andcomplexity, from large integrated production,drilling and quarters platforms (PDQ) withaccommodation for 200-300 workers, toprocessing only (manned or unmanned), drillingonly, quarters only, gas compression or variouscombinations. Topside weights range fromseveral hundred to a few thousand tonnes in theGulf of Mexico and the southern North Sea toover 15 thousand tonnes offshore California, andto 10-40 thousand tonnes for very large PDQstructures such as those in the northern NorthSea.

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The configuration or arrangement of topsides istypically dictated by the capacity of available liftvessels used for installation. Topsides may beintegrated, modular, or hybrid versions thereof,as illustrated in Figures 1, 2 and 3, respectively.

Figure 1. Integrated topsides / deck.

An integrated topsides refers to a system wherethe process facilities are installed in the deckstructure in the fabrication yard and the facilitiesare hooked-up and commissioned onshore. Thecompleted deck structure with the integratedfacilities is then installed offshore onto the jacketor substructure. Integrated topsides are usuallyinstalled by a single offshore lift and are,therefore, limited to a weight of several thousandtonnes. A modular configuration is typically usedfor larger topsides where the deck structure issubdivided into modules or rectangular boxesthat can be lifted by available crane vessels. The modules are supported on the jacket orsubstructure by a module support frame. Process facilities are yard-installed in themodules and then the interconnect and hook-upbetween the modules is performed offshore. Many of the very large topsides use a hybridconfiguration where, in addition to the modules,process facilities are integrated into the modulesupport frame.

Figure 2. Modular topsides / deck.

Figure 3. Hybrid topsides on concrete gravity-based structure.

OPTIONS FOR REMOVAL/DISPOSAL

The primary removal/disposal options aresummarized in the chart in Figure 4 . Thedecision as to removal options and the variousdisposal and reuse options will need to be madeas part of the overall assessment for decommis-sioning of the installation. In any event, theplatform will need to be cleaned and allprohibited substances removed in accordancewith all regulations. Well established industryprocedures are in place for this purpose (seeAppendix A, p. 46).

REMOVAL

Removal consists of removing the integrateddeck or the deck modules and the modularsupport frame (MSF). This may be achieved byany of the following:

ÆÆ Remove in one piece;ÆÆ Remove groups of modules together;ÆÆ Remove in reverse order to installation;ÆÆ Piece-small removal.

REMOVAL IN ONE PIECEThe advantage of lifting off the topsides in onepiece, as illustrated in Figure 5 , is that it requiresthe least amount of work to be carried outoffshore. The method requires a heavy lift cranevessel (HLV) with sufficient lifting capacity, or alarge specialized decommissioning vessel. Thecurrent generation of HLV’s would limit thismethod to topside weights in the 3 - 5000 tonnerange (when safety factors and other constraintsare taken into account) and no specializeddecommissioning vessels have yet been fullydeveloped or built.


40

Figure 4. Topsides Removal / Disposal Options

Figure 5. Removal in one piece.

One-piece removal of topsides is more practicalfor small platforms (e.g., the gas fields of thesouthern North Sea) which have topsidestypically in the 1,000 to 2,000 tonne range. Thelarger platform decks (e.g., located offshoreCalifornia in the northern sector of the NorthSea) are too large to remove in one lift using aconventional HLV as the weight of some of thetopsides facilities is in excess of 25,000 tonnes.

A major problem/drawback in the one-pieceremoval scenario is both how and where tooffload the topsides onshore, particularly sinceonshore cranes do not have the capacity to liftlarge modules. Depending on the loadingcapacity of the quayside, it may be possible to

skid the topsides to the quayside. The otheroption would be to lift the topsides onto a cargobarge which could be moored alongside thequayside and the modules deconstructed on thebarge itself.

LIFTING OF COMBINED MODULESA recent study by an offshore contractor for thetopsides of a large modular northern North Seaplatform has shown that removing the topsidesin groups of two to four modules at a time can bean effective option. This takes advantage of theincrease in HLV capability that has occurredsince the installation of the early large NorthernNorth Sea platforms in the mid 70’s. This optionis illustrated in Figure 6 . The advantage of thismethod is in reducing the time that heavy-liftvessels are required, since fewer lifts arenecessary when compared to the reverseinstallation method, where modules are liftedindividually.

This method, in addition to the preparationsdescribed below under Reverse Installation,needs sequencing, surveying and the fabricatingand attaching of lift points as well as additionalstrengthening to allow for combined lifting. Theposition of the modules on the platform and theirweight will dictate both whether or not combinedremoval is possible and which modules may belifted at one time. Handling for onshore logisticswill be difficult for the large units.

OFFSHORE OIL & GAS

FACILITY

DECOMMISSIONING

OIL & GAS PROCESSING

EQUIPMENT & PIPING

DECK & JACKET

STRUCTURE

SENT TO SHORE

ONSHORE SCRAPING

MOVED TO NEWLOCATION &

REINSTALLED

DISPOSED OF INDEEP WATER

CONVERT TO AN

ARTIFICIAL REEF

REFURBISHED& REUSED

SOLD FOR SCRAP

WASTE TO LANDFILL

RECYCLE STEEL

WASTE TO LANDFILL

PARTIAL REM OVAL

TOPPLE IN PLACE

SINGLE PIECEPLACEMENT OFF-SITE

MULTI-PIECEPLACEMENT OFF-SITE

OFFSHORE OIL & GAS FACILITYDECOMMISSIONING DECISION TREE

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Figure 6. Lifting of combined modules.

REVERSE INSTALLATION −INDIVIDUAL MODULES

This option, illustrated in Figure 7, involvesdismantling the topsides and deck in the reverseorder in which they were installed, i.e., removingthe topsides modules and deck components oneat a time. Reverse installation requires thechartering of moderate capacity crane bargesand/or heavy-lift barges for the larger modules.Surveys of pipework, cabling, module structures,etc. will need to be made to establish the extentof the module preparation required prior to lifting.The following measures will be necessary:

Æ The structural integrity of the modules wouldneed to be checked, strengthening installedwhen deemed necessary, and centers ofgravity of the loads established using jackingsystems;

Æ Re-install lifting padeyes and slings or installlifting frames;

Æ All inter-module connections will need to besevered.

Preparation and lifting sequences will need to beplanned in detail in order to maximize utilizationof topside facilities such as accommodation andpower and minimize the time the lifting vessel ison site.

Figure 7 . Reverse installation.

Piece Small Removal

Another method to remove all or part of thetopsides is to deconstruct them on the platformusing mechanical and other cutting devices,along with the platform cranes, temporary deckmounted cranes and/or crawler cranes. Thepieces can then be loaded into standard cargocontainers which, when full, can be offloadedonto a supply vessel and transported to shore. When the platform cranes need to be removed,lifting operations would revert entirely to thetemporary deck mounted cranes or crawlercranes. The advantage of this method is thatneither an HLV or cargo barges are required,hence offshore spread costs are substantiallyeliminated. (A smaller crane vessel would berequired at the end of the operation to removethe deck mounted cranes). On the other hand,however, this method is time and labor intensiveand hence individual circumstances for aspecific platform will determine whether it ismore advantageous than the other methods.Piece small removal is illustrated in Figure 8 .

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Figure 8. Piece small removal.

DISPOSAL

There are three primary methods of disposal: refurbish and reuse, scrap and recycle, anddispose in designated landfills. In practice, acombination of those methods is likely to beemployed, consistent with generally acceptedwaste disposal hierarchies. This means that tothe extent that facilities or components of thosefacilities (such as pressure vessels andcompressors, for example) can be refurbishedand reused, and demand exists for thisequipment, this will be the first method utilized.Whatever material or equipment cannot berefurbished or resold will then be sold for scrapand recycling, except for those elements thatcannot be scrapped and recycled and henceneed to be disposed in designated licensedlandfills. While opportunities for reuse aredrawing increased attention, there are inherentlimitations in the cost of refurbishment, theevolution of stricter technical standards and thefact that, particularly for the larger facilities, manycomponents were designed for a specific set offunctional requirements that may not fit theoperating and processing demands of a newfacility.

In all cases, the facilities will have to be cleanedas necessary, and some materials, such as LSA,will require special handling and controlleddisposal by specialized contractors. Additionalinformation on cleaning is given in Appendix A(p. 46).

The steel support structure for the productionfacilities, sometimes referred to as module

support frame, may either be removed with theproduction facilities, or could alternatively bedisposed with the jacket as an integral part of anartificial reef. This structure is purely a steelframework and does not contain any hydrocar-bons or other equipment or materials.

CONSTRUCTION EQUIPMENT ANDNEW TECHNOLOGY

To-date crane barges have essentially been theonly means to remove topside facilities (andjackets). These barges can be traditionaloffshore construction barges with lift capacitiesin the hundreds of tons range, to ship shapevessels in the 2 - 3,000 ton range, to the verylarge semi-submersible dual crane heavy liftvessels with combined lift capacity in the order of14,000 tons. Removed facilities are typicallylowered onto a transport barge to be taken to ashore facility. In some cases it can beadvantageous to put the removal facilitiesdirectly on the deck of the heavy lift vessel, thenusing the heavy lift vessel for transport to shore.

The realization that a growing number of largerinstallations will have to be decommissioned inthe next few years has fostered the developmentof alternative concepts to the use of cranebarges for deck removal. These range from asystem using a truss structure in combinationwith standard transport barges, to the evolutionof unique decommissioning vessels, such ascatamaran type vessels that could act in "forklift"fashion to remove and transport a completedeck. Some of these concepts are only on the

E.

A. B.

D. F.

G. H.

C.

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drawing board, others have had various degreesof engineering studies performed, and some, likethe truss and barge system will actually betested on a real installation in the Gulf of Mexicothis year.

EXPERIENCE TO DATE

The largest experience base with platformremoval rests in the Gulf of Mexico, with some1100 platforms decommissioned to date,although only 38 of those were in water depthsover 200 feet, and none in water depths inexcess of 400 feet. Topsides were typically inthe 800 to 1000 ton range or less, with amaximum in the order of 3,000 tons, ascompared to weights on the order of 8,000 tomore than 16,000 tonnes offshore California. Ofinterest, however, is an established and growingmarket for reuse. One recent statistic claimsthat over the last three years, 25 percent ofremoved decks were stored for potential resaleor reuse.

Probably the largest facility decommissioned todate is the Odin platform in 103 m (340 ft) ofwater in the Norwegian North Sea. The topsidesconsisted of 6 modules and a flare boom locatedon top of a module support frame. Total weightof those topsides was approximately 7600tonnes, with three of those modules weighingover 1500 tonnes each, one just over 1000tonnes, two in the 800 tonne range and the flareboom weighing just over 100 tonnes. The jacketweighs about 6200 tonnes. To date, thetopsides have been removed and taken to shorefor reuse and recycling, and part of the jackethas also been removed. The modules wereremoved individually (essentially reverseinstallation) by a heavy lift semi submersiblecrane barge with dual cranes, maximum liftcapacity of 14,000 tonnes. They were placed onthe deck of the heavy lift vessel and taken to theshore facility in two trips. Two other recentlydecommissioned North Sea platforms hadtopside facilities in the 4000 tonne range andwere also taken to shore for reuse and recycling. In one case a final figure of 99.7 percent forreuse or recycling was achieved at the end of theproject.

There is, however, experience also with theremoval of larger individual modules in the North

Sea for platform refurbishment or upgradeprojects.

KEY ISSUES

This section describes the key technical, safety,environmental and cost issues as they relate tothe various structural configurations andmethods of removal and disposal.

TECHNICAL ISSUESIn most cases, the removal of topsides is likely tobe the reverse process of the installation.However, the removal process is inherently morecomplex than the installation process since it hasto take into account modifications, bothstructural and through addition/deletion ofequipment during the 20-30 year service life ofthe platform. This, together with an assessmentof the structural integrity of the lifted parts, isessential to allow safe lifting operations whenthese topsides components (or modules)weighing several thousand tonnes are removed.

SAFETY ISSUES

Safety issues relate primarily to personnel safetyduring multiple heavy lift operations. Hydrocar-bon and other residues must be removed to theextent that they do not impact hot work and otheroperations during cutting and lifting. Structuralintegrity is of utmost importance to ensure safetyduring heavy lifts. Further, these operations areinherently more complex than during installation,especially when the removed topsides elementsmay need to be placed and tied down ontobarges moving under the effect of sea swells. Athorough safety assessment would be requiredfor each platform and this would be a key factorin understanding the overall balance of options.

ENVIRONMENTAL ISSUES

These issues relate primarily to removal ofhazardous material such as NORM/LSA scale,cleaning and disposal of hydrocarbon and otherresidues in situ and at the disposal site, potentialfor pollution at the final destination, and to theenergy use (including CO2 emissions) in variousremoval/ disposal options.The technology for removal of hazardousmaterial and cleaning of hydrocarbon and otherresidues is generally well proven (see detailed


44

description in Appendix A, p. 46). Technologyand experience can be extrapolated and there isa good track record. Although, topsides will betaken to shore for recycling/reuse, somecleaning operations and removal of someequipment may be carried out offshore. Onceonshore the potential pollutants will be disposedof in a controlled manner in licensed disposalfacilities.

Energy consumption can be high for topsidesremoval, particularly where heavy lift vessels arerequired for an extended period of time.

COST ISSUES

The costs associated with removal and disposalonshore of the topside facilities are significant,accounting for 30-40 percent of the total removalcosts of the installation, which in the North Seacan range from the upper tens of million USdollars to 200-300 million US dollars. Thiscompares to removal / disposal costs in the Gulfof Mexico in the order of 1-2 million US dollarsfor the relatively small installations removed todate.

Costs are driven by complexities discussedearlier such as strengthening to ensure structuralintegrity, the costs of cleaning and preparing thedeck for offshore disposal, and the high cost oflarge-crane vessels and supporting spread andequipment (especially if lengthy operations areinvolved). The difference in size and complexity,and particularly the larger offshore operationsand weather constraints imposed by the severeNorth Sea environment accounts for the largedifference in costs between North Sea and Gulfof Mexico removal.

Cost estimates for different removal/disposaloptions can be generated for the specifics ofeach individual topside facility, including suchconsiderations as size, weight, modular vs.integrated, complexity, amount of cleaningrequired, etc and the availability and marketrates for construction vessels and equipment atthe time. This will be a significant factor to beweighed in the overall balance of differentoptions.

CONCLUSIONS

The removal and disposal of topside facilities isan integral part of the overall decommissioningactivity for an offshore platform. Topsides canvary significantly in size, functionality andcomplexity, and hence, a range of decommis-sioning options has been identified in technicalstudies. The technologies to implement themare not all equally mature and, in general,removal is a more complex operation thaninstallation. One feature common to all options isthat the facilities will need to be cleaned and allprohibited substances removed in accordancewith regulations.

The environmental impact of each option hasgenerally been shown to be small. Otheraspects to be considered are health and safetyand cost. Opportunities for reuse are drawingincreased attention, but are limited by the costsof refurbishment of the older facilities and theevolution of stricter technical standards. Further,particularly for the larger facilities, componentswere generally designed for a specific set offunctional requirements that may not fit theoperating and processing demands of a newfacility.

The diversity and range of complexity of topsidefacilities suggest that no one option is likely to bethe most appropriate in all cases, particularlywhen seen in the context of the decommission-ing of the total installation.

RECOMMENDED FUTURE STUDIES

Because of the uniqueness of each offshoreinstallation, specific engineering studies will berequired to determine the cost and technicalfeasibility in each individual case.

There are, however, some aspects that willbenefit from further generic studies:

Æ Further investigation of technical andeconomic feasibility of the range of alterna-tive removal methods, including the trussand barge method and specialized decom-missioning vessels proposed by variouscontractors.

Æ Further evaluation of reuse potential and theapplicability of various technical standards toextended life facilities.

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REFERENCES

Bibliography of related reports:

AURIS Environmental. August 1995. AnAssessment of the Environmental Impacts ofDecommissioning Options for Oil and GasInstallations in the UK North Sea. Preparedfor UKOOA Limited.

E & P Forum. July 1996. Removal / Disposal ofLarge North Sea Steel Structures. Report No.10.14/243. London.

National Environmental Research Council for theDepartment of Trade and Industry. April1996. Scientific Group on DecommissioningOffshore Structures, First Report.

National Research Council. 1996. AnAssessment of Techniques for RemovingOffshore Structures. Committee on Tech-niques for Removing Fixed Offshore Struc-tures. Marine Board, Commission on Engi-neering and Technical Systems, WashingtonD.C.

Various general and technical publications andconference proceedings, including but not limitedto:

Strategies for Successful Abandonment. 1995.October 1995. IBC Conference, London.

Gulf of Mexico vs. North Sea PlatformAbandonment. March 27, 1996. One daybusiness conference, Houston, TX.

Minimizing the Impact of Decommissioning. February 1996. Institute of PetroleumConference.

International Workshop on Offshore LeaseAbandonment and Platform Disposal. April1996. New Orleans, LA.

Decommissioning Projects and Techniques, IBCConference. June 1997. Aberdeen, Scot-land.


46

APPENDIX A:CLEANING AND REMOVAL OF POTENTIALLY HARMFUL MATERIALS

A1. GENERAL DESCRIPTION

FLUSHING OF VESSELS AND PIPEWORK

Vessels, tanks and piping will be classified as to whether or not they have contained hydrocarbons. Thoseclassified as having contained hydrocarbons would have to be flushed to remove residual hydrocarbons. Procedures for such cleaning have been developed which are regularly exercised in the preparation ofpipework for cutting or other such work in potentially flammable atmospheres. Elements of theseprocedures are presented in Section A2.

The objectives for cleaning in these instances are to eliminate the explosion and fire risks associated withhydrocarbon residues and to remove the potential for release of any hydrocarbons or pollutants into themarine environment. Prior to the cutting up of structures for full or partial removal, it would be necessary tofollow a procedure similar to that outlined in Section A2.

Each of the non-hydrocarbon systems will require separate consideration to determine the need forflushing and cleaning.

REMOVAL OF POTENTIALLY HARMFUL MATERIALS FROM TOPSIDE FACILITIES

A combination of the following activities may be found on individual platforms:

• oil production/processing • water injection• condensate production/processing • gas re-injection• gas production/processing • power generation• hydrocarbon pumping/loading • drilling • accommodation and support

Each of these facilities will have specific requirements for preparation for decommissioning.

As part of the disposal of the topsides, any material that cannot adequately be cleaned will be removed foronshore disposal. Among the materials to be considered on a particular platform are the following:

1. Hydrocarbons or potentially hazardous chemicals contained in the following vessels or equipment:

• transformers • paint containers• coolers • batteries• scrubbers• separators

• fire extinguishing / fighting equipment

• heat exchangers • pumps• tanks for drilling consumables inc. bulk storage of muds, etc.

• engines• generators

• biocide containers • oil sumps• diesel tanks inc. bulk storage tanks

• tanks• hydraulic systems

2. Quantities of heavy metals (e.g., lead, zinc, mercury, cadmium, etc.), if any, in biologically availableform.

Where such elements are used on offshore installations they are predominantly in metallic form and thusnot directly or easily available to the biological food chain. Bolts and other items made from alloyscontaining the above metals will not need to be removed before abandonment.

3. Other undesirable substances such as radiation sources.

4. Light bulky materials such asÆÆ life boats

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ÆÆ life jacketsÆÆ thermal insulationÆÆ lightweight panelsÆÆ accommodation module fittings.

5. Chemicals used in drilling.

The principal use of chemicals on offshore installations is as additives in drilling muds employed in drillingthe wells in the early phases of an oil or gas field development. It would be unlikely for there to be anysuch chemicals left on a platform at the time of removal. However, in the event of small quantities ofchemicals remaining on the platform, e.g., corrosion inhibitors, such materials would be shipped back,preferably in their original containers, for disposal at appropriate reception facilities onshore.

EXISTING PROCEDURES

For each of the above, procedures will already be established for maintenance work requiring cleaningand dismantling of the various systems. In general, the procedures necessary to prepare a hydrocarbonsystem for “hot work” would satisfy the requirements of being substantially “hydrocarbon free” prior todisposal. Such procedures have been developed by each operator over a number of years and are inroutine day-to-day use.

A2. ELEMENTS OF STANDARD INDUSTRY PROCEDURES FOR FLUSHING OF TANKS ANDPIPEWORK

After the plant has been taken off stream, cooled down and pumped out, all items of equipment must thenbe depressured, drained and vented.

DEPRESSURING

Normal practice is to dispose of hydrocarbon gasses to fuel gas or flare systems.

As systems become depressured they should then be isolated by valving and subsequent blanking.

DRAINING

Prior to equipment being isolated, it is essential that it should be drained as far as is possible via fitteddrain points.

Adequately sized drain lines should be installed at the lowest points and sized in accordance withoperator’s engineering practices.

VENTING

Where flammable or other harmful materials are to be vented, the point(s) for release must be located inorder to preclude any possibility of vapors encroaching upon areas where personnel are working or wherethere is likelihood of ignition.

PURGING AND FLUSHING

Pipework can be flushed or purged using either steam, water or inert gas. For many applications, water isused as the primary cleaning method. However, steam cleaning is sometimes used but has a higherdegree of safety implications.

Pipelines which carried wet oil or hydrocarbons will require flushing with sea water to obtain a satisfactorylevel of cleanliness, i.e., when the system is substantially hydrocarbon free. The pipeline will then be filledwith sea water and sealed.


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REMOVAL AND DISPOSAL OF DECK AND JACKET STRUCTURES

ANDREW S. CULWELLVice President, Special Projects

American Pacific Marine, Inc.

INTRODUCTION

The removal of deck and jacket structures isthe core of the decommissioning of anoffshore oil and gas facility. This paperdiscusses the objectives of the decommis-sioning process along with the methodologiesused to meet those objectives. There aremany challenges to the decommissioningprocess created by water depth and theassociated large mass of the platformstructure. There are also limitations ofequipment and techniques which must beanalyzed in order to choose the bestcombination of resources and technologies tobest fulfill the operational and environmentalcriteria established for the decommissioningsite. The removal of offshore oil and gasfacilities in California will include a wide rangeof structures from man made islandsconstructed of concrete and rock fill, towooden piers with concrete caissons, to steelplatforms in water depths ranging from 45 feetto 1200 feet.

Disposal issues are complex and are tied tothe industrial capacity, environmental factors,and political climate of the decommissioningarea. These variables narrow the availablechoices for disposal of the deck and jacketmaterials. A number of decommissioningproject case histories on the U.S. West Coastare illustrated and discussed in this paper,along with descriptions of the methodologiesand equipment used. These examples of pastprojects reveal some advances in technology,increased regulation by governing agencies,and an ongoing focus on safety.

This document reviews the state of the arttechnologies available to remove these marinestructures, and reviews the rationale for theselection of resources and methodologies withgiven variables in structure location, size anddesign.

REMOVAL AND DISPOSAL GOALS

The removal of offshore oil facilities should beaccomplished using methodologies which areefficient while offering the highest possiblemargin of safety for the workers andmaintaining the smallest possible impact onthe environment. Safety should always be theforemost consideration, with environmentalimpact and efficiency being weighed on acase by case basis.

Perhaps the most critical question is, howmuch of the structure should be removed? The presence of a structure over a number ofyears has created a marine ecosystem. Thisstructure may be an obstacle to commercialfishing and a resource for sport fishing. Partsof the structure may be imbedded in the seafloor to the extent that total removal will createmore disturbance to the environment thanpartial decommissioning in place. All of thesefactors must be considered in generating aremoval plan (factors which dictate the limitsof the removal).

The water depth may influence these optionsand impacts. A structure in shallow waters islikely to be easily accessible by the public, andpublic safety at the site following removal mustbe considered. A structure in deep watersmay be partially decommissioned with allremaining materials far below the watersurface. Further, the extreme mass of a deepwater structure is a significant challenge, notonly for the initial removal process, but for thedisposal process as well. The scrapping anddisposal capabilities on the U.S. West Coastare limited, and these limitations must beconsidered as a part of structure removalplanning. The massive quantities of marinegrowth and the disposal of this materialcauses air quality issues at the disposal sitedue to the odor. Air emissions are also animportant consideration in areas with airquality problems.

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CASE HISTORIES IN SHALLOWWATER AND DEEP WATER

The following case histories will illustrate anddiscuss some of the major offshoredecommissioning projects completed to date(Figure 1 ). It should be noted that the largestcrane barge used for these projects inCalifornia has been rated at a 500 toncapacity. Future decommissioning projects onlarger platforms in California may require abarge crane capacity ten times greater toremove these massive structures.

Figure 1. Facilities Decommissioned on theWest Coast.

Aminoil Ellwood Pier

Ellwood Pier is located north of Goleta,California and is one of several oil productionpier facilities still remaining in California. Thispier is no longer a producing facility, and isnow used for crew and material transfer. Thisfacility had five concrete caissons withproduction wells positioned 700 feet beyondthe terminus of the pier today. This section ofpier and the caissons were decommissionedin 1979. The pier was made of steel H-pilecolumns supporting a timber deck, terminatingat the five concrete caissons which wereconnected by steel trusses and covered with acontinuous timber deck.

The timber deck was removed and the pileswere cut off by divers below mudline. Theconcrete caissons were demolished usingexplosive shape charges. The 15 poundconical charges were positioned around theperimeter of the structures and detonated toreduce the caissons to pieces with maximumdimensions of approximately six feet. Reinforcing steel was cut by divers. The steeltrusses were cut above water by rigging crewsand below water by divers using arc-oxygentorches. The concrete rubble was reduced toa pile which did not extend above a waterdepth of -15 feet at low tide and was left inplace. The steel was recovered and scrappedonshore. The use of explosives in openwater, a common practice prior to 1980, hasnot been allowed in recent years fordecommissioning work in California. Explosives continue to be used below mudlinefor pile and conductor severing.

Texaco Helen and HermanPlatformsPlatforms Helen and Herman, originallyinstalled in the late 1950's in State Waters,were decommissioned in 1988 followingproduction shutdown and well plugging in1973. These structures were located offshoreGaviota, California in 100 feet of water and 85feet of water respectively and represented theearly design of offshore oil platforms withsimple tubular construction and anchor pilesdriven down through the annuli of the platformlegs. Both structures had been moved to thesite for installation on cargo barges andplaced in position on the sea floor with a bargemounted crane. The decommissioning ofthese platforms was the first large scaleoffshore oil platform decommissioning projectperformed in California, and therefore therewere many unanswered questions regardingdisposal options. An artificial reef constructionfrom the jacket materials was proposed duringthe project permitting and planning phase,however political opposition to the proposedreef site in Santa Monica Bay killed the plan. Deep water dumping was also considered anddiscarded. The only remaining disposal optionwas onshore scrapping, and this methodologywas carried out to dispose of the materials.


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Platform Helen was a 20 leg structure andHerman was a 4 leg structure. The marinegrowth accumulated on the structures wasover 15 inches thick near the surface with upto 12 inches of hard growth. The structureswere in poor condition after 15 years exposurewithout cathodic protection. Platform Helenhad a number of 2 inch diameter pipelinesrunning to subsea completions with a 6 inchand 8 inch production pipeline to shore. Platform Herman also had a 6 inch and 8 inchproduction pipeline to shore. The pipelines forboth platforms were decommissioned in placewith a section through the surf zone removedcompletely. All onshore facilities and pipelineswere removed. The deck packages andjacket structures were removed in sectionsweighing from 100 to 400 tons. The cutsbelow the water line were made by diversusing arc-oxygen torches. The jackets wereattached to the sea floor by piles inside thelegs. The piles on Helen were severed 1 footbelow natural mudline using a mechanicalcasing cutter. This method proved to be lessthan reliable, as most of the cuts wereincomplete and had to be completed by diversdeployed down the inside of the 33 inch piles. The slope or “batter” of the outside legsproved to be a problem for the casing cutter,even though a centralizer was used. The pileson Herman were cut from the outside bydivers after excavating a foot below thenatural mudline because the interior of the pilehad been grouted, leaving it inaccessible forcutting tools.

The Helen and Herman platforms togetherhad a steel weight of approximately 3000 tons. The marine growth probably added 1000 tonsto this figure. Disposal was performedonshore in Long Beach at a private yard withwaterfront access. The size of the jacketstructures, soaring about 80 feet above thedeck of the barge, presented a significantproblem for dismantling. The 500 ton derrickbarge “Wotan” used to remove the structureswas required to offload the materials at thedock. This process was feasible because allof the materials were brought in together on 3barges. The onshore dismantling requiredtwo large crawler cranes to safely take downthe tall tubular structures.

Chevron Hope, Heidi, Hilda andHazel PlatformsThe Chevron Hope, Heidi and Hilda platforms,located in State Waters off Carpinteria,California in water depths of 137', 126', 106',and 96' respectively, were decommissioned in1996 immediately following well plugging (P &A) operations. The decommissioning project,sometimes called the 4-H Project, waspostponed for one year due to air emissionpermitting delays, caused by strict limitationson air emissions imposed by the Environ-mental Protection Agency (EPA) on SantaBarbara County and the classification ofdecommissioning emissions by the SantaBarbara County Air Pollution Control District(APCD) as non-exempt. Emission offsetswere required by the APCD to keep emissionlevels below target ceilings, and the timerequired to create those offsets resulted in thedelay of the project. These platforms wereinstalled between 1958 and 1965 and were insound structural condition at the time of theirdecommissioning. Disposal options includingonshore scrapping and artificial reefconstruction were weighed in the permittingand project planning phase. The artificial reefoption was not selected because at thebeginning of the permitting process in 1992,the State Lands Commission and the CoastalCommission were not favorably disposedtoward this disposal method. Later, interestemerged in the artificial reef approach by theAmerican Sport Fishing Association, and theconcept was seriously analyzed for the 4-HProject; however, the late timing createdpermitting obstacles and there were questionsas to the cost effectiveness of the method forthis particular project. Therefore, onshorescrapping was used again as the disposalmethod of choice. Several potential sites inthe Terminal Island area of the Port of LongBeach were selected for a dismantling andscrapping process similar to the oneperformed in 1988 for Platforms Helen andHerman. One of the lessons learned herewas that future projects should includeanalysis of the artificial reef option for disposalfrom the outset of the permitting and planningphase.

Platforms Hope, Heidi and Hilda and Hazelwere technically advanced designs at the time

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of their installation (See Figure 2 ). The Hope,Heidi and Hilda jackets had two large diametercaisson legs which served as the flotation forthe jackets during installation as they weretowed to the site on their sides. This platformdesign concept was used as late as 1977 forthe Thistle “A” platform installed in the NorthSea. The Hope, Heidi and Hilda platformswere anchored to the sea floor by piles driventhrough sleeves in the large caisson legs andthrough sleeves in smaller caissons at thebase of the opposing legs.

Figure 2. Platforms Hope, Heidi, and Hildadesign. This illustration is typical of platformsize in water depth ranges from 100 to 140feet.

The Hazel jacket was a “gravity structure”design in which the platform was floated outon its buoyant caissons and ballasted on siteby filling the caissons with sand and cement. A gravity structure by definition is secured tothe sea floor by gravity alone and is notanchored by steel piles. Hazel was a typicaltubular steel jacket structure sitting on largediameter caisson bases (See Figure 3 ). These caisson bases floated the structure tothe site when empty, and became the anchorfor the structure when jetted 18 feet into thesea floor and filled with ballast material. Thisgravity structure concept developed in the1950's was later used for platform design inthe treacherous Cook Inlet near Anchorage,

Alaska, and more recently has been used forconcrete platform structures fabricated inNorwegian fjords and floated on the gravitybases which are later ballasted with sea waterand/or crude oil storage.

Figure 3 . Platform Hazel design. Thisplatform is a “gravity base” design and had noanchor piles.

The production well P&A process wascompleted during a two year period on thefour platforms. The dismantling of productionequipment followed, removing all productionequipment and piping with hydrocarbonresidue from the structure.

The removal of the 4-H platform structuredecks was completed as the reverse of theinstallation process. This scenario is typicalbecause the deck package lifts that weredesigned for installation are the safest andmost practical configuration for removal. Themarine equipment of the 1960's includedderrick barges with capacities in the maximumrange of 500 tons. Today we find derrickbarges lifting more than 10 times that amount,but the package to be removed must beengineered for the lift, and many times, thepackage is removed in a configuration similarto its original installation. Equipmentavailability is also a factor to be considered. Construction barges are plentiful in California,but the largest barges, such as the D/B Wotan


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used on this project, have a capacity ofapproximately 500 tons. If heavier equipmentis needed, it must be imported from otherareas at a significant cost. The 4-H deckswere removed in sections weighing 100 to 350tons and placed on cargo barges for transportand offloading at a dockside facility inTerminal Island. It must be noted that the airemission permit process was difficult due tothe stringent requirements in Santa BarbaraCounty. The option of importing largerequipment with significantly more capacity,greater horsepower, and higher fuelconsumption would probably have been overthe emission limitations imposed on the ownerby the APCD.

The removal of the 4-H platform jacketsoffered many technical challenges in that thestructures were designed to float on their ownbuoyant legs, and therefore there was noinherent design strength for lifting them. Thelarge caisson legs, measuring up to 18 feet indiameter, had a mere ½ inch wall thicknessand had been designed to withstand only themaximum pressures anticipated in the launchmode with partial flooding. Therefore de-watering the legs to lift the structure off bottomwas risky at best with anticipated pressuresmeeting or exceeding design ratings, resultingin the requirement for another alternative to liftthe structure. The answer for the recovery ofthe delicate but massive legs was theutilization of a pair of 250 ton capacityhydraulic gripping tools attached to 2 of thepile stubs on the legs. Further, it wasnecessary to cut the legs in up to 3 verticalsections to reduce the weight of the lifts tomeet the capacity of the crane. The mosteffective cutting technique in depth rangesaccessible to divers continues to be arc-oxygen torches, and this method was used forthe majority of underwater structure cuts. Thismethodology is not as effective, however,when cutting through multiple well casingstrings grouted together.

The severing of the legs in 3 sections as wellas the pile and well conductor severingrequired below the bottom of the leg structurerequired methodology which would be efficientand reliable. The technology for abrasivewater jet cutting has progressed to the pointwhere it has been successfully used for manypile and conductor cutting operations on

decommissioning projects, however it has notyet achieved the reliability of explosive cutting. The abrasive water jet methodology was usedfor intermediate cuts in the well casing stringsinside the caisson legs for sectioning the legsin 3 parts; and it was also used for theremoval of casing strings outside of the legs. However this methodology does not haveguaranteed success and many cuts wererepeated or completed by divers workinginside the caisson legs after cuts proved to beincomplete. The piling and well casing cutswere performed far below the existing mudlineto reach a depth below the bottom of thestructure. It was crucial to the safety of theheavy lifts that these cuts be complete andreliable because they could not be examinedfor verification. Explosive cuts have beenproven to be the most reliable cuttingmethodology in use, and 45 pound explosivecharges were employed on each of the pileand well casing strings locations. Thesecharges were effective in completely severingthe piling and well conductors below mudlineon 100% of the explosive cuts performed. Anumber of conductor cuts below mudline hadto be made by divers due to access blockageof the casing annuli by grout. These cutsrequired divers to work inside the caissonlegs, cutting the bottom of the structure clearas well as the conductors and casings.

The removal operation revealed anothercomplication - the legs of Hope, Heidi, andHilda were partially filled with grout orhardened drilling mud, increasing the legweight beyond the capacity of the crane. Mudremoval operations ensued, with diverspumping off the solid materials to storagetanks on the deck of a cargo barge. Thesetanks were offloaded in Terminal Island andthe material was transported to an approveddump site.

The Hazel platform, a gravity structure, waspartially decommissioned in place. Thegravity base caissons were nearly coveredwith accumulated materials and shells in amound under the structure. Because of thecaissons’ excessive weight and the distur-bance to the sea floor which would be causedby their removal, this part of the structure wasdecommissioned in place.

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The 4-H platforms had 20 intra field and fieldto shore pipelines and 9 power cables. Platform Hope was receiving and shippingproduction from platforms Grace and Gail,and these pipelines had to be rerouted aroundthe Hope platform to facilitate the decommis-sioning of the structure (See Figure 4 ). Otherpipelines were disconnected from theplatforms, capped, and the ends were buried3 feet below mudline. The pipeline and powercable decommissioning was performed by the165 foot workboat M/V American Patriot. Most of these pipelines are buried where theyreach shore, and those that sometimesbecome exposed are adjacent to pipelines stillin production. Therefore, no landfall pipelineremovals were performed; however, thedecommissioned pipelines were groutedinternally through the surf zone anddecommissioned in place.

The steel mass of the 4-H platforms was inexcess of 10,000 tons. The total weight ofmarine growth removed was in excess of2700 tons. Disposal was performed onshoreat a 20 acre dockside facility in TerminalIsland. Steel scrap was reduced to market-able sizes and sold. The crane capacitiesonshore were very limited and it wasnecessary for the removal derrick barge tooffload the structures at the dock. Thepackage heights were designed to be limitedto approximately 30 feet to avoid dismantlingproblems on the dock after offloading. Thevolume of the scrap required numerous tripsto the dock to offload the cargo barges. Debris at the platform sites was removed bydivers working aboard the 165 foot workboatM/V American Patriot and transported toCasitas Pier for land transport and disposal.

Exxon SALMThe Exxon SALM or Single Anchor LegMooring, was installed in 1980 in Federal OCSwaters using a combination of a drill ship andderrick barges to complete the construction. Itwas decommissioned in 1994 using a derrickbarge. The SALM was positioned in 500 footwaters off Goleta, California and had a 750foot long Offshore Storage and TreatmentVessel (OS&T) permanently moored to themooring structure.

Figure 4. Pipeline Bypass at Platform Hope.The pipelines from Platform Grace originallyterminated at Platform Hope, and productioncontinued to shore in the Hope pipelines. Areroute of the pipelines around the platformkept the Hope pipelines in service for PlatformGrace production.

The SALM was comprised of a base structureapproximately 52 feet in diameter anchored by6 piles. The riser and buoy structuresconnected by universal joints to each otherand to the base plate resemble a largeautomotive drive shaft supporting a mooringyoke to the OS&T at the surface. Pipelinesrunning from the Hondo platform sent crudeoil and gas production up the riser and buoystructure, through swivel fittings at theuniversal joints and finally to the OS&T fortreatment prior to offloading. The OS&Tprovided storage of the crude oil and deployeda mooring hawser to tankers for mooringduring the offloading of produced oil emulsion.The OS&T facilities layout is shown in Figure5.


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Figure 5. OS&T Abandonment Project Facilities Layout. Exxon OS&T Abandonment.

The removal of the SALM was the first deepwater decommissioning project performed inCalifornia. The structure was 14 years old atthe time of the removal operation, was in goodcondition and marketable for reuse in otherareas. Therefore, the scrapping and artificialreef questions did not apply to this project.

The removal of the SALM system, like manydecommissioning projects, was performedusing many of the same techniques appliedfor the installation. In fact, the derrick bargeused for the installation work, the D/B LongBeach (formerly D/B 300), was also used forthe removal operation. The OS&T vessel wasdisconnected and towed to Ensenada, Mexicofor temporary storage; however, in spite ofestablished plans, the vessel was turned awayby Mexican authorities, underscoring thepotential uncertainties inherent in crossinginternational borders in the decommissioningprocess. The vessel was finally towed to adock in the Port of Los Angeles for storage. The large yoke on the vessel’s stern had to besupported by a large buoy which had beenstored in the Port Hueneme area after theinstallation. The attachment of this buoy wasaccomplished by a delicate ballastingoperation combined with the use of winchesand a derrick barge.

The riser and buoy sections of the structurewere removed using saturation divers. Thehydraulically actuated pins which had securedthe structure to the base during installationwere found to be operational, replumbed andthen retracted to disconnect the riser structurefrom the base structure. A ballastingoperation on the buoyant riser and buoystructures (reducing the lift forces), combinedwith the attachment of a wire for controlledrelease at the base structure (reacting againstthe buoyancy), were used to recover the buoyand riser to the surface. The de-ballasting ofthe structure and attachment of transportbuoyancy to the riser, further raised the SALMto a horizontal attitude for towing. The buoywas towed to the Port of Los Angeles fortemporary storage.

The base structure was removed in a moretypical fashion for decommissioningoperations. Saturation divers disconnectedthe pipelines and capped and covered theends with concrete mats to ensure thepassage of trawl nets over the site in thefuture. The 6 anchor piles were severed 15feet below the natural seafloor using abrasivewater jet cutting technology operated remotelyfrom the surface (see Figure 6 ). All of thesecuts were successful. The base structure wascut into 7 sections by saturation divers using

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Figure 6 . SALM Base Structure. Exxon OS&T Abandonment.

arc-oxygen torches and rigged for removalwith the derrick barge.

The SALM and OS&T structure were resoldand are now in operation overseas. The basestructure was scrapped onshore.

Global PerspectiveThe number of platforms decommissionedeach year exceeds 100 structures, most ofwhich are located in the U.S. Gulf of Mexico. Most of the structures decommissioned todate have been located in relatively shallowwater. The Exxon SALM described above andthe Brent Spar removed from the North Seaare two deep water examples which did nothave the tremendous mass of the majority ofdeep water structures which will be decom-missioned in the future.

The challenges for the future will centeraround the removal and disposal of thesemassive structures. The environmentalimpacts of onshore disposal of thesestructures will be much greater than theimpacts seen in the disposal of smallerstructures, while the alternatives fordecommissioning in place and artificial reefsmay see an increase in potential benefits.

The removal of massive deep water structuresmay come first to California waters. Thesedecommissioning projects will require largercapacity and more capable heavy liftequipment, support tugs, and transportbarges, with an associated increase in airemissions. The removal of the deckpackages of these newer structures mayprovide opportunities for reuse in other areasof the world, reducing the disposal dilemmaswhich must be faced. The total removal of thejackets for onshore scrapping would createmany impacts including air emissions, marinegrowth disposal issues, and the quandary ofinsufficient sites for such activities.

The removal of the shallow water structurescontinues each year and we see similarscenarios to those recent decommissioningprojects in California described above. Reuseof oil production platforms is quite common inthe Gulf of Mexico. A reuse scenario couldsee an entire structure removed in one piece,transported and placed back on the sea floor. Another scenario on a larger structure couldbe the removal of the decks and jackets inseparate lifts with reassembly at anotherlocation. In a different scenario, jackets anddeck packages are removed from the fieldand reconditioned and upgraded onshore in afabrication yard, followed by reinstalled at a


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new offshore location. The obstacles to theinstallation of new offshore oil productionfacilities in California, makes these reusescenarios much less likely to occur here.

ENGINEERING AND PLANNING

Organize LogisticsThe planning of a decommissioning projectbegins with the identification of the equipmentnecessary and available to do the work. Thechoice of derrick barges, tug boats, and cargobarges along with the disposal plan will be thebasis for an analysis of environmental impactusing this equipment (See Figure 7 ). Themost efficient means of removing the structuremust be developed with all of the potentialvariables in mind. The owner must not onlychoose the most effective equipment spread,but ensure that it is available and can be successful in completing the work outside ofany potential environmental windows such asthe whale migration periods. Air emissionslimitations have been an issue in the past;however, new legislation may have exemptedoil production facility decommissioning workfrom these limitations.

Special Tool Design

The lifting of structures which have been inservice for many years, and which may havebeen extensively modified since theirinstallation, will probably require the designand fabrication of special tools and rigging tocreate lift points, and perhaps attachmenttools to connect the rigging to those heavylifts.

Engineer Heavy Lifts

The heavy lifts must be engineered to ensurethat the lift is made safely and within thecapacity of the crane used (See Figure 8 ). The dynamic loading conditions offshore addadditional risk to the heavy lift, making theengineering effort a central issue. A weighttake-off for the package to be lifted must begenerated to accurately calculate the mass ofthe lift. The rigging of a lift bridle of at least 4parts, as well as the use of special tools orspreader bars, add complexity to the lift. Thecenter of gravity (CG) must be identified, andthe rigging centered on this location (SeeFigure 9 ). A package which is not liftedaround the CG may have three of its four loadslings taking all of the load, creating excessiveloading on those parts. A more significantmiscalculation could result in an unstable loadwhich has the potential of hitting the craneboom or dropping portions of the lift. The

Figure 7. Equipment Spread – Shallow Water Decommissioning. This illustration compares themass of the petroleum platform to the removal equipment. The platform is in 140 feet of water with a500 ton crane barge (300 feet LOA) and cargo barge shown.

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Figure 8. Lift Plan – Crane Chart. The heavylifts are engineered with the load weight anddimensions, center of gravity, rigging, andcrane capacity limits charted. This planningverifies that the crane can complete the liftwithout the boom touching the load, and thatthe working radius (capacity is sufficient tocomplete the lift.

engineered lift will specify specific rigging,crane radius to be used, weight take-offs forthe lift which include the rigging weight, liftpoint location and type, plus a contingencyfactor.

Additional planning must be engineered toprovide a means of aborting a lift after theload has been raised a few inches. A lift abortcould be necessary due to mechanicalmalfunction on the crane, changing swellconditions, or a rigging failure. Tubularstructures or any structure sitting on columnsmust have guides on the columns at the cutpoints which allow for approximately 1 foot ofvertical travel before the load clears. This willenable the operator to lower the load withinthe guide if an abort is necessary.

Engineer Materials Transport

The heavy lift barge which has just rotated alift package away from the platform underdynamic load conditions must have a place toset that load without delay. Therefore, it isimperative that planning include the cargobarge load. Each large lift may be placed in a

Figure 9. Lift Plan – Lift Points and CG Locations. The chart shows the center of gravity (CG) and liftpoints for the heavy lift preparations.

predesignated position on the barge, aposition which has been verified relative tobarge stability in the roughest seas anticipated(See Figure 10 ). Sea fastening is engineered to efficiently secure the load to the barge fortransit.

Figure 10. Materials Transport Planning. The sketch shows the plan for cargo bargeloading. This planning also incorporatesengineered sea fastening for each load andstability calculations.


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Plan / Engineer DisposalEvery package that is placed on a barge mustbe eventually offloaded. The method ofcomplete onshore disposal will require a craneequal to the barge crane for offloading, or thepackage may be reduced in size while at thedock. This may be impractical as the sizereduction ties up high cost marine equipmentfor extended periods, and the new reducedlifts must be engineered and rigged as well. Alternative disposal means such as artificialreefs will require extensive engineering andplanning which is combined with biological andenvironmental data.

PROJECT RESOURCES

Heavy Lift Equipment vs. DepthRangesStructures located in less than 200 foot waterdepths, and located in moderate environmentssuch as the U.S. West Coast are typically of asize which can be dismantled by a 500 toncrane with 160 to 200 feet of boom. Thestructure age can also be a critical factor asplatforms installed within the past 15 yearsmay have been assembled with larger deckpackages requiring larger lifts for a stableremoval sequence. Jackets may be sectionedat will to suit the capacity of the equipment.

Support VesselsSupport vessels are the backbone of anoffshore decommissioning project and thecentral vessel is the derrick barge. All derrickbarges require tugs to maneuver them andsometimes place anchors. Some advancedderrick barges may be equipped with adynamic positioning (DP) system which usesonboard computer controlled thrusters toaccurately hold the vessel on station whenintegrated with a navigation system in lieu ofanchors.

A 500 ton capacity derrick barge of approxi-mately 300 foot length over all (LOA) andoperating on the U.S. West Coast may requireas much as a 3000 horsepower (hp) tug toprovide towing and anchor handling. Theanchors used may be 5 to 10 tons in weight

deployed on up to 2 inch wire rope anchorwires without chain, and can be expected tohold a tension of approximately 10 times theirweight (Danforth Type) in sand. A 5000 toncapacity derrick barge of approximately 600foot LOA may work with the assistance of upto a 25,000 hp tug set up to operate in moreharsh environments such as the North Sea. Anchors used may be 15 tons or more inweight “piggybacked” with 2 anchors permooring leg comprised of anchor chain.

Crew boats are commonly used in Californiabecause of the close proximity of the majority of platforms to land. Platforms which are inexcess of 15 miles from a point of onshorecrew transfer are typically out of practicalrange for daily shift changes by crewboat. Platforms which are out of range will requirepersonnel accommodations during theiroperating life and the decommissioningequipment used to dismantle them will alsoneed to accommodate the crews. Helicoptertransport is an alternative to offshoreaccommodation, but is plagued in Californiaby the coastal fog during the summer monthsand Santa Ana wind conditions in the wintermonths.

Tugs and cargo barges are needed to stageand transport removed materials andpackages. Cargo barges which are availableas a part of the typical marine transportmarket may range from 180 feet LOA to 400feet LOA. These barges must be documented by the American Bureau of Shipping (ABS)with a Load Line Certificate to legally transportmaterials on the open sea in U.S. waters. Tugs in the range of 1500 hp for smallerbarges and 3000 hp to 5000 hp for the largerbarges are utilized for towing and maneuver-ing. The cargo barges must be moored on aremote mooring near the decommissioningsite to receive multiple lifts from the derrickbarge which may occur hours apart.

Special ToolsSpecial tools may be required for certain liftapplications or perhaps robotic cuttingapplications. For example, the recentdecommissioning of Platforms Hope, Heidi,Hilda, and Hazel required a number of specialtools. Hydraulic grippers were adapted tospecial buoyant lift rigging for 500 ton lifts.

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The buoyant rigging allowed another specialtool, an A-frame with a 38 part lift blockassembly, to stab onto the established grippertools underwater. The A-frame was used forthe removal of leg sections which had to beextracted through up to 20 feet of bottommaterial. The loads to be encountered onthese lifts could not be entirely engineered,and the A-frame provided a great margin ofsafety without risk to the crane boom. Theseare just a few samples of special toolsprovided on one project.

PersonnelThe platform decommissioning project willvary in personnel commitment by the size ofthe equipment used. The working window ofopportunity due to equipment availability, orenvironmental restrictions may also affect thesize of the decommissioning team. A smalldecommissioning project on a single platformin shallow waters may require only 40 to 50personnel to operate the marine equipmentspread. A moderately sized project withmultiple platforms in shallow waters mayrequire 75 to 100 personnel. A deep waterdecommissioning project with largerequipment may require in excess of 150personnel.

DEMOLITION OF CONCRETESTRUCTURES

Concrete structures offshore include caissonswith piers and concrete and rock islands. These facilities are typically located in waterdepths of 45 feet or less. The concretestructure’s extreme weight creates somechallenges to reduce the structure intosections for removal and there are a numberof demolition techniques available:

Diamond Wire SawingA wire rope impregnated with industrialdiamonds is fed through holes drilled into theconcrete structure and the ends of the wireare connected together to form an endlessloop. The loop is driven on the deck with ahydraulic powered sheave and pullingpressure is applied to force the wire loop tocut the concrete and reinforcing steel until theholes it has penetrated are connected by the

cut. This method typically requires access toboth sides of the holes being drilled tofacilitate feeding the wire through. The resultis a clean and straight cut which is not limitedby the thickness of the concrete.

Abrasive Water JetA high pressure water jet is directed at theconcrete with an abrasive garnet or copperslag mixture. The water jet bombards thestructure at pressures of 10,000 to 50,000 psiand the abrasive multiplies the cutting forces. This tool typically is directed with a roboticfeed assembly which controls the rate of travelfor the cut and will sever the reinforcing steelalong with the concrete. The method can beemployed to cut concrete thickness up toseveral feet.

Expansive GroutA number of holes are drilled into the concretestructure and filled with an expansive grout. The grout expands as it hardens, cracking thesurrounding concrete. This method reducesthe concrete to rubble which must behammered to expose reinforcing steel for finalcuts with a torch.

Hydraulic SplittersA number of holes are drilled into the concretestructure and a hydraulic splitting tool isinserted. The tool expands hydraulically andcracks the surrounding concrete. This method reduces the concrete to rubble whichmust be hammered to expose reinforcingsteel for final cuts with a torch.

ExplosivesExplosives may be used in small quantities indrilled holes through the concrete to reduce itto rubble.

Impact DemolitionThe oldest and most familiar method forreducing concrete is direct impact to thestructure. A wide range of tools may be usedincluding hydraulic powered impact hammersoperated from excavators or special supportmachines, and wrecking balls or toolsmanipulated from cranes. Reinforcing steel ismanually cut when using this method.


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REMOVAL PREPARATIONS TODECK PACKAGES

Installation of Remote Moorings forCargo BargesThe cargo barges required to receivematerials should have a means to moortemporarily in the field. This serves to reducefuel consumption, and allows tug crews torest. As a lift is being prepared, the tug cantake the barge under tow and maneuveralongside the derrick barge to receive thepackage. The barge and tug will depart thefield for the disposal site when the barge isfully loaded.

Deck Package Lift PreparationsDeck package lifts will require lift pointfabrication and installation prior to the arrivalof the derrick barge. Crews will pre-rig asmuch as possible to reduce the duration of thederrick barge utilization. Preparatory cuttingof decks may be performed in conjunction withengineering calculations for a modifiedstructure analysis, to minimize the cutting timerequired to separate the packages for their lift(See Figure 11 ).

Figure 11. Preparations to Deck Packages. This isometric shows the cut lines forseparation of two deck modules for lifting.

Preparations for Alternate UseAny alternate use or disposal option mayrequire specific preparations (relative to thatoption). The re-use of a structure may require

many protective measures to preserve theequipment on board during the transfer.

REMOVAL PREPARATIONS TOJACKETS

Marine Growth RemovalMarine growth will be removed at theunderwater cut points to facilitate diver cutsusing arc oxygen torches. The removal of allmarine growth prior to removal of the structurehas not been economically feasible. Theremoval of marine growth is accomplished bythe use of a 10,000 psi hydroblaster which isoperated by divers. The seawater jet removesthe marine growth to within millimeters of baremetal.

Preliminary Cuts on JacketsPreliminary cuts on a jacket in shallow watersmay be made to prepare for removal, inconjunction with engineering calculations for amodified structure analysis. These may takeplace before or after deck package removalsas dictated by engineering. Deeper waterremovals may also allow for preliminary cuts,as many of the members on the jacket wereprimarily for installation loads during a bargelaunch of the jacket.

Methodology for deep water cuts may includethe use of saturation divers to depths of over1000 feet; however saturation divingoperations in excess of 600 - 700 feet arerare. The question of the use of divers forextreme depths depends on the projectedsafety of the operation and the cost of usingdivers versus remote intervention means. Cutting techniques using remote systemscould include Atmospheric Diving Systems(ADS), a manned system which operates anabrasive water jet cutting tool or a mechanicalequivalent. Other systems include heavy workRemotely Operated Vehicles (ROV) whichcarry similar tools in work packages on board. Remote applications have been cost effectivein performing cuts in extreme depths, howeverheavy rigging is a tremendous challenge forremote intervention techniques. Thereforeprogressive lift methodology is a likely choicefor the removal of jackets in deep water asdiscussed below. Deep water jacket removal60

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techniques have not been implemented todate, and specific methodologies must bedeveloped and proven in the field.

REMOVAL OF DECK PACKAGES

The strategy for the removal of deckpackages centers on several factors. First,the capacity of the derrick barge combinedwith the available space on the cargo bargewill determine the maximum lift size. Second,the capacity of the offloading crane chosenmust also be within the limits of this packagesize. Third, it must be determined if thepackage and the remaining portions of thedeck packages will support themselves whenthe specified load is cut free and removed. Finally, the package itself must have theintegrity to be lifted, or additional measuressuch as the use of spreader bars orstrongback members may be taken to reducethe loads on the package. The choice ofreuse of the package or scrapping may havesome bearing on the size and configuration ofthe package chosen.

The deck package will be transported to theoffloading location. A decommissioningproject in Southern California is likely tooffload in the Port of Los Angeles or LongBeach. The only likely alternative to scrappingthe deck packages is reuse. Packagesdestined for reuse may remain on the cargobarges for shipment to another location forrefurbishment and sale. Other alternativessuch as artificial reefs are typically not appliedto the deck packages. Deck packageconfigurations are the easiest to scrapbecause they are comprised mainly of flatplate and beams. Conversely, thehydrocarbon residue which may be present onportions of the deck package would make thecleaning requirements excessive in order toincorporate the package into an artificial reef.

PILE AND CONDUCTOR SEVERING

The jacket is typically anchored to the seafloor by anchor piles. These piles may bedriven over 200 feet into the sea floor andmust be cut off at a specified distance belowthe mudline to remove the jacket. Thisdistance has been 1 to 5 feet below mudline in

California state waters and 15 feet belowmudline in Federal waters. Piles are groutedto the structure near the base, and may havewell conductors inside. Most platforms do nothave wells drilled through the anchor piles, buthave a conductor bay in the center of thestructure. Intermediate piling cuts may berequired to separate the jacket into verticalsections, as the piling may extend well up intothe jacket structure, particularly on the shallowwater platforms.

Conductor severing and recovery will mostlikely be completed as a part of the wellplugging process. The conductors maycontain multiple strings of well casing, groutedtogether. Mechanical casing cutters aretypically used in this application if a drill rig isavailable for deployment of the tools. Abrasive water jets may also be used to makethese cuts at the designated elevation belowmudline. The conductor may be lifted thenwith the drill rig through the structure andsectioned as it is lifted to facilitate offloading. The conductors, like the rest of the structurewill be heavily fouled with marine growth. When the conductor is pulled up through theconductor guides located at each horizontalmember elevation, the marine growth will bestripped as it passes through the guide. Jackets with excessive marine growth orjackets in poor condition may incur damage asthe conductor is pulled up. Modification to theconductor guide or removal of the marinegrowth on the conductor may then beconsidered.

The mechanical casing cutter is perhaps theoldest method for cutting well conductors. The casing cutter is a drilling tool deployed ona drill pipe string. The cutting tool has 3blades which fold up against the drill pipe. When hydraulic (drill water) pressure isapplied to the tool, the blades are forcedoutward as the tool is rotated by the powerswivel on the drill floor. The carbide tippedblades cut through the casing strings untilpenetration is complete through the outerconductor. Drillers can watch the backpressure on the drill water to determine whenthe cut is complete. The cut can be verifiedafter the recovery of the tool, by the marks ofpenetration on the blades. This method is not100% reliable, as the outer conductor will


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deform significantly as the blade is forcedthrough.

When final penetration is reached, thehydraulic back pressure will reduce, but thecut may not yet be complete. The finalverification is the successful verticalmovement of the conductor. The casingcutter methodology is problematic forconductor removals in which close toleranceconductor guides on the jacket are smallerthan the deformed cut end of the conductor which must pass through the guide duringrecovery.

Abrasive water jet technology has beensuccessfully used in recent years to cutmultiple string well casings. The abrasivewater jet leaves a clean, machine like cut inthe casing strings. Several different systemsare in use. The pressures range from 10,000psi with a high volume output to 50,000 psi ata lower volume output. The abrasive isintroduced at the cutting nozzle tip and maybe sent down a hose dry by air pressure or ina water based solution. The abrasive ispropelled by the water jet after beingintroduced into the cutting jet, and cuts thesteel and grout as it hits the target. Casingstrings with void areas rather than groutedannuli have been a problem for thismethodology. The water gap between casingstrings dampens the energy of the water jetand causes an incomplete cut. Inconsistentabrasive delivery can also be a problem. Thesystems which have an air delivery of the dryabrasive grit are limited to shallow waterapplication. The systems using a fluid deliveryof abrasive have been used in water depthsexceeding 600 feet. The abrasives typicallyused are garnet and copper slag. Someoperators have been reluctant to use copperslag because of the environmental implica-tions of the copper content; however, the level of copper present in the slag material isrelatively low, and there are no restrictions onits use. The most versatile aspect of thiscutting technology is the relatively small toolsize, and it’s potential and historic use byremote intervention systems such as ROV’sand ADS to depths exceeding 1100 feet. Thecasing cuts which are completed belowmudline cannot be verified visually. The tooloperators have used microphones for audio

feedback and hydraulic back pressure readoutto gauge whether the cut is being completed. The rotational cutting speed of the tool is setby the operator’s “feel” for the cut and by theknown capability of the tool. These methodsare at best, only indications of cuttingperformance in progress, and there have beena significant percentage of incomplete cuts onprevious decommissioning work in Californiaand in the Gulf of Mexico. The abrasive waterjet technology continues to develop and will bea popular technique for cutting applications inthe future.

The use of explosives to cut conductors, wellcasings and piles has been the most reliablemethod in use for many years. The openwater use of explosives has been restricted inrecent times, but applications below mudlinecontinue to be permitted with minimal impactsto marine life. The bottom cuts on anchorpiles and conductors required for the removalof jacket structures must be clean to allow fora safe lift from the surface. A barge makingsuch a lift in dynamic conditions at sea wouldcertainly exceed its lift capacity if anincomplete cut left the load secured to the seafloor. This potentially dangerous conditiondictates the use of the most reliable methodfor making these cuts, and explosives haveproven to be nearly flawless in their reliability. An explosive cut is sized according to thediameter and wall thickness of the member tobe cut, along with the number of strings. Atypical charge for these cuts is a cylindricalexplosive container which is lowered down theconductor or pile to the designated cutelevation and detonated from both ends tocreate a “collision charge”. The force of thedetonation at the ends moves toward thecenter of the cylinder and moves outhorizontally when the two explosions collide. This horizontal force creates the directionalcutting energy to sever the pile or conductor(See Figure 12 ). The methodology isextremely safe, as the explosive cannot bedetonated without an explosive detonator. The detonator (blasting cap) is attached to adetonation cord which is secured to each endof the explosive. Modern blasting caps are detonated by high voltage and are notsensitive to radio waves as others have beenin years past. Because the detonation cordmay be several hundred feet long, the vessel

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supporting the operation can move clearbefore a blasting cap is ever installed. Thevessel continues to move away, paying outelectrical wire to the blasting cap beforedetonation is applied to the wire with highvoltage. The recent decommissioning ofPlatforms Hope, Heidi and Hilda employed theuse of explosives for the majority of bottomcuts with a 100% success record. Spottingaircraft and boats were used to verify thatthere were no marine mammals in range ofthe blast area prior to each detonation. Thecharge size for the typical cuts on shallowwater platforms is approximately 45 lbs.

Figure 12. Pile and Conductor Severing UsingExplosives. The used below mudline forconductor and pile cuts are typically bulkcharge cylinders which are simultaneouslydetonated from top and bottom. The explosiveforce meets in the middle of the chargeredirecting the cutting forces to the horizontalplane.

JACKET REMOVAL

Jacket removal can be accomplished invarious degrees and using a number ofmethodologies. All jacket removal operationswill take place following the completion ofpipeline decommissioning. The mostcommon removal scenario for shallow waterjackets is complete removal of the jacket. This method will leave nothing on the sea floorexcept the mound that accumulates under

each jacket during its operating life. Thismound is comprised of drill cuttings, shellsand other organic material from marine life onthe structure, and collected sediments forstructures in depositional areas. The jacketremoval is completed after bottom cuts havebeen completed below mudline on the anchorpiles. The entire jacket is removed in sectionsor as a single lift if possible.

Deep water structures present much greaterchallenges for complete removal. Theimmense weight of the structures as well astheir extreme depth, places a one stepremoval outside the limits of existingtechnology. A method known as “progressivetransport” reduces the structure to packagesfor shipment in a cost effective manner. Thestructure is rigged between two barges andlifted after the pile severing operation iscomplete. The jacket is winched vertically offthe bottom and the barges are moved intotowards shallow water until the jacket touchesbottom again. The upper portions of thejacket can now be removed above the watersurface and the rigging is reattachedunderwater for another lift. The remainingstructure is vertically lifted again andtransported to shallow water where it is againreduced and rerigged. This process can berepeated as needed to completely recover thejacket.

Jackets can be partially removed with aportion decommissioned in place. Thismethod would involve the removal of theupper portions of the jacket such that theremaining structure was well below thesurface, and clear of concerns aboutnavigation hazard. The remaining structurewould be in effect an artificial reef.

Another approach to decommissioning inplace is jacket “toppling”. The jacket is pulledby winches on anchored barges after pilesevering, and the structure is toppled on itsside. The jacket structure on it’s side will bewell below the water surface.

The deep water platforms in water depths ofmore than 400 feet are candidates forprogressive transport, partial removal in placeand decommissioning by toppling. Shallowwater platforms are more likely candidates for


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complete removal at the site. Californiaplatforms Helen, Herman, Hope, Heidi, andHilda have all been completely removed at thesite, and were located in water depths from 85feet to 139 feet. Platform Hazel wasdecommissioned using partial removal inplace due to her extremely heavy gravitystructure caisson bases below the mudline.

DEBRIS REMOVAL

Debris removal is performed within a specifiedradius of the decommissioning site. The mostrecent California decommissioning projectshave involved debris removal within a 1000foot radius of the platform site. There aremany ways to locate and remove debris; thechoice may be affected by the equipmentavailable in the area and the water depth. Apreliminary survey of the site with side scansonar can provide a target listing and locationfor existing debris.

A common method for debris removal in theU.S. Gulf of Mexico is the use of trawl nets torecover debris. Heavy nets called “gorillanets” are used from trawl vessels to gatherdebris. Divers can assist in completing thedebris recovery operation as required.

Diver recovery with ROV assistance is aneffective technique when heavy trawl vesselsand equipment are not available. This methodhas been successfully used on all Californiadecommissioning projects to date. The ROVis deployed with color scanning sonar to locatedebris items on the target list provided by thepreliminary side scan data. Differential GlobalPositioning System (DGPS) satellitenavigation is integrated with an acoustictracking system to provide real time positiondata on the ROV during search and recoveryoperations. The ROV locates the debris andremains on location to guide the diver to theposition with a recovery line. The supportvessel recovers the debris and the diver asthe ROV continues to the next debris target. This method is effective for debris recovery inless than 200 feet of water.

Deeper water recovery work may be moreeconomically performed using remoteintervention techniques. Well site clearance

has been performed in California in waters exceeding 300 foot depths using ROV’s andmanned submersibles for recovery of debristargets. The ROV recovery operations usinglight work ROV’s are performed by attaching arecovery line from a spool on the ROV. TheROV is recovered with the line and the line istransferred to a winch for recovery of thedebris target. Large work ROV’s and mannedsubmersibles have been used to attachrecovery lines from the surface. The remotemethod is altered slightly with largerequipment in that the ROV or mannedsubmersible remains on bottom during thedebris target recovery and uses sonar torelocate the recovery wire for the next target.

MATERIAL TRANSPORT ANDDISPOSAL

Material transport is most commonly achievedon cargo barges. These barges are availablein the existing marine transport market up to alength of 400 feet. Larger barges, if required,would not be commonly available and wouldcarry a significant cost.

Onshore scrapping has been the method ofchoice in California to date. The distance tothe scrapping facility is critical due to the highcost of marine equipment. If barges are to beshuttled from the decommissioning work inthe field for offloading, the shorter theduration, the fewer cargo barges and tugs arerequired. The existing scrap facilities inCalifornia are not set up for scrap reduction oflarge packages. These facilities are fed bynumerous small scrap companies whichreduce small volumes of scrap into market-able sizes of approximately 3 feet square andless. Because of this existing marketcondition, a steel scrap reduction andprocessing operation must be created toreduce these large packages to marketabledimensions. The scrap reduction process iscostly and waste products must be hauled to adump site. Most of the existing scrapprocessed in the Los Angeles area is shippedin bulk carriers to the Far East for sale there.

The debate over where to put artificial reefs,and who might be responsible has left thesteel scrap yards with the business of

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reducing these structures. Still there is a highlevel of interest in creating these reefs. Theconstruction of an artificial reef would requireenvironmental study, an engineering plan forthe layout of the reef, and a significantcommitment of marine equipment to place thematerials.

Relocation and reuse of platform structures iscommon in the U.S. Gulf of Mexico, andstructures are commonly lifted and relocatedwithin a few miles to be set up for productionagain. This scenario is unlikely in California;however packages with enough value towarrant transport to other areas may betransported from California decommissioningprojects. This was the case for the ExxonSALM and OS&T decommissioning projectcompleted in 1993.

CONCLUSIONS

The removal and disposal of deck structuresoffers many options for reuse and recycling ofmaterials. The deck structures may haveviable equipment and components for use atanother facility. A newer deck package maybe transferred intact for installation on a newjacket. Older structures which are scrappedoffer the type of configuration which is best forrecycling (i.e., flat plate, beams, paintprotected condition).

The removal and disposal of jacket structurespresents many challenges. The extensivemarine growth, deterioration of the materials,grouting of jacket piles and members, alongwith the size of the structure make offshoreremoval difficult. Reuse options are limited,especially on the U.S. West Coast. Onshorescrapping is very difficult with small structures,and may present tremendous challenges forlarger structures. These obstacles make thesearch for alternatives worthwhile, and createa potential for the use of jacket structures asartificial reefs when relocated or partiallydecommissioned in place. These removaloperations can be completed in an environ-mentally sound and safe manner with existingtechnology while creating jobs and increasingcommerce. The disposal of the materials is apotential resource which can bring economicand/or environmental benefits.

REFERENCE

Exxon Company U.S.A. August 1994. ExxonOS&T Abandonment Final Report.


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PIPELINE AND POWER CABLE DECOMMISSIONING

ANDREW S. CULWELLVice President, Special Projects

American Pacific Marine, Inc.and

JOHN C. McCARTHYEngineering Geophysicist

Minerals Management Service, Pacific OCS Region

INTRODUCTION

Offshore California oil and gas platforms aretypically served by one to three pipelines. These pipelines range from 4 to 20 inches indiameter and move production fluids to otherplatforms or to onshore processing anddistribution facilities. Some pipelines are usedto return treated produced water to a platformfor offshore disposal or injection. The specificproperties of the fluids transported in a pipelinemay change during its service life of 30 ormore years.

In addition, to reduce air emissions, Californiaproduction platforms are designed for, or havebeen converted to, electrical power. Thispower is provided by the regional onshoreelectrical distribution network and reaches theoffshore facility via power cables traversing thesea floor like oversized extension cords.

To a casual onshore observer, the ultimateconsequence of terminating production fromoffshore oil and gas fields is the removal ofassociated offshore and onshore facilities. Thepresence or absence of pipelines and powercables related to these facilities is a lessobvious, but still important, factor to consider indecommissioning.

DETERMINING OBJECTIVES

It is difficult, if not impossible, to develop anadequate engineering plan for decommission-ing pipelines or power cables until specificdeterminations are made regarding theirdisposition. Without question, decisionswhether, or not, to remove or decommission in-place are a basic element in determining thescope of work. Federal regulations allow

decommissioned OCS pipelines to be left in-place when they do not constitute a hazard tonavigation, commercial fishing, or undulyinterfere with other uses of the OCS. Californiaregulations are similar in allowing pipelines tobe left in-place when they are not considered ahazard or obstruction, although California StateLands Commission policy requires removal,when feasible, of pipeline segments in the surfzone to a depth of -15 feet MLLW (mean lowlow water). There are few examples wheretotal removal or decommissioning in-place isthe only preferred option because pipeline andpower cable alignments typically traverse arange of environmental settings that requiredifferent solutions to address a variety ofdecommissioning objectives that are, at times,conflicting.

From an operator’s perspective, highest priorityis usually given to assuring worker safety in thecontext of pursuing regulatory compliance andminimizing the risk of future liability, atminimum expense. Regulatory agencies withprimary oversight responsibility for pipeline andpower cable decommissioning also tend toplace emphasis on assuring worker safety, butcost is of less concern than the need to fulfillregulatory mandates to minimize adverseenvironmental impacts and user conflicts, suchas preclusion of commercial trawling. Theinterests of other stakeholders usually focus onone or more of the issues already mentioned tothe exclusion of all others.

One of the keys to optimizing decisionsregarding pipeline and power cable dispositionoptions is to find an acceptable balancebetween conflicting interests that is sufficientlyflexible to address the variety of conditions thatmight be present along the alignment. The

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other key is to have a clear and accurateunderstanding of existing conditions based ona pre-decommissioning survey of pipeline andpower cable alignments.

Useful preliminary information regardingconditions along pipeline and power cablealignments can be obtained from a number ofsources. Reviews of historical records, suchas pre-installation surveys, as-built documen-tation, external pipeline surveys and records offishing conflicts provide background informa-tion applicable to the design of an adequatepre-decommissioning survey.

Pre-decommissioning surveys are used tocharacterize conditions along pipeline andpower cable alignments. Surveys on recentCalifornia projects have employed side-scansonar to provide reconnaissance-leveloverviews and are usually supplemented withdetailed video and sonar documentation, usingan ROV (Remotely Operated Vehicle), in areaswhere significant conditions are suspected. The results of pre-decommissioning surveysshould be evaluated in the context of availablehistorical documentation to aid in determiningwhether specific segments of an alignment aresubject to major changes over time. Burialconditions may change seasonally in shallowwater, high energy environments and spansmay migrate.

Careful documentation provides a basis fordetermining preferred disposition options byidentifying conditions, like high spans, thathave potential to interfere with other uses suchas commercial trawling. Documentation canalso provide insight into whether or notpreclusion is even an issue because otherfactors, like high relief seafloor features, maypreclude trawling. Pre-decommissioningsurveys are also used to identify environmentaland engineering conditions that might requirespecial safety or environmental protectionmeasures during the conduct of a decommis-sioning project.

ENGINEERING, PLANNING ANDEXECUTION

The majority of pipelines on the U.S. WestCoast have been installed with a “bottom tow”technique, meaning that the pipes were welded

together at a staging area at the onshorelandfall position and, with temporary buoyancyattached, were pulled offshore by an anchoredbarge. Many pipelines were pulled in bundlesof two to three pipelines to an offshore facility. Upon completion of the tow, the buoyancy wasRemoved by divers, remotely operatedvehicles (ROV’s), or boats dragging sweepwires. The bottom tow method is significant forthe decommissioning process because pullsleds were used on the leading end of thepipeline and are typically left in place near theplatform. Connecting spools were installed bydivers to complete the installation. Theremoval process must consider the dispositionof these pull sleds and any remaining riggingleft after the temporary flotation was removedfrom the pipeline. Most pipelines on the U.S.west coast have not been buried by theinstallation contractor. Some pipelines indepositional areas of sand transport havenaturally become buried, and others remainuncovered for the majority of their length.

Engineering and Planning for PowerCable RemovalThe power cables which run from shore to theoffshore facility are armored with one or twolayers of steel armor wire, with internal highvoltage wires which were typically designed tocarry in excess of 30,000 volts. These cablesare four to six inches in diameter and are quiteheavy. Sub-sea power cables, when buried orlying flat on the sea floor, are not a hazard totrawl fishing and have typically been decom-missioned and abandoned in place with theends buried below mudline. The weight of thecables creates a challenge for recovery,because if they are to be recovered in onepiece, a large powered reel as large as 35 feetin diameter would be needed along with linearcable engines (a hydraulic powered, rubbercoated steel track assembly which captures thecable and pushes the cable through the tool). The potential reuse of these cables isquestionable and therefore the cable may moresimply be cut into pieces as it is recovered;however, the disposal of the cables is difficultbecause of the complexity of separating thearmor, the insulation and the copper wire. It ismost likely that an onshore dump site is theultimate destination of a recovered powercable. All decommissioned power cables to-


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date have been abandoned in place with theexception of the Hondo SALM described inCASE HISTORIES.

the planning for power cable removal wouldinclude the set up of a retrieval system and arigging and cutting methodology to quicklysever the power cable. Burial issues aregenerally not critical, as the power cable canbe recovered in spite of a burial condition dueto the high strength and relatively smalldiameter. A disposal plan would be required ifa power cable is removed.

Power Cable RemovalPower cables are more typically abandoned inplace than removed. The removal processwould involve attaching the cable to a recoverywinch by divers. The cable end can then beretrieved so that a linear cable engine can beset up to drive the cable up onto the recoveryvessel and a hydraulic shear can be used tosection the cable for stowage and transport.

Engineering and Planning forPipeline RemovalPipeline removal operations require engineer-ing pre-planning to determine the methodologyfor removal and the size and capacity ofremoval equipment. Historic documentation ofthe pipeline operation and conditions prior tofinal shutdown are necessary to identifyresidual fluids and gases in the pipeline. Shutdown documentation should reveal themethodology used for final cleaning andflushing of the pipeline, which will provide datafor an estimate of the extent of additionalcleaning required for decommissioning.

Determining the most appropriate removaltechniques will require data from recentpipeline surveys or a dedicated pre-decommissioning survey. Data requirementsinclude: pipeline burial locations, burial depth,water depth along the route, nearby pipeline orstructure locations and environmentalinformation such as the position of kelp bedsand hard bottom habitats.

In addition, engineering planning requiresknowledge of pipeline characteristics such asdiameter, wall thickness, density and locations

of weight coat (if present), flanges, pull sleds,and pipeline crossings.

Assembled data are analyzed to determinehow much of the pipeline will be removed. Survey data from the removal locations areused to determine the type of excavationequipment required as well as any environ-mental precautions which must be taken. Forexample, anchor plans must be developedaround the kelp beds and hard bottom habitats. The barge capacity, both for recovering thepipe and storing the pipe, must be evaluatedalong with auxiliary equipment such as cargobarges and tug boats. The methodology forcutting the pipe may be critical, especially if along length of pipeline is to be recovered. Theprotective coatings and weight coat typical ofmost pipeline sections to be removed makepipeline severing difficult, because thesecoatings must be removed in order to cut thepipe with a torch.

Disposal is a critical issue for pipeline removalbecause reuse of the steel is not feasible dueto the coatings on the pipeline. Typically,pipelines must be cut into lengths as short as 6feet and hauled to an approved dump site onland. This process is costly and the methodol-ogy chosen to process the material fordumping is important, in order to achieve acost effective result.

Pipeline Removal PreparationsSurveyThe pipelines will be surveyed or existing datawill be studied to determine the location offlanges, crossings, kelp, and hard bottomhabitats.

CleaningPipelines are cleaned using a process called“progressive pigging”. This process involvessending a series of polyethylene (poly) foam“pigs” and cleaning pigs through the pipelinewith chemical agents and flush water toremove all hydrocarbons. The pig is a foambullet shaped plug which is slightly larger indiameter than the inside diameter of thepipeline. The pig is introduced into the pipelinethrough a “pig launcher” (a pressure vesselconnected to the end of the pipeline). The piglauncher has a diameter larger than the

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pipeline to allow insertions of the pig by hand,and a hatch or flange which is closed behind. The pig is pushed from the launcher into thepipeline by pumping air, nitrogen, water orchemicals into the launcher behind the pig. Ameasured amount of fluid or gas is pumpedbefore a second pig is inserted into thelauncher. The progression continues until therequired number of pigs with the correspondingamount of driving chemicals or flush water issent through the line, removing all remaininghydrocarbons. The pigs are received in a “pigcatcher”. The pig catcher is similar to the piglauncher. The pig catcher, located at theopposite end of the pipeline, is plumbed toallow fluids or gas to flow through, pushing thepigs to the end of the catcher.

The types of pigs available that may be used isbased upon the condition of the pipeline,previous cleaning history, and the expectedbuildup of wax, corrosion, or other residue fromhydrocarbon production, as listed below:

1. Low Density Poly Pig - A low density pigcan pass through partially blocked pipelinesbecause it can radically deform as it is pushedthrough. This pig seals the push fluid or gas toensure that all liquid in the pipeline is displacedby the fluid or gas behind the pig.

2. Medium Density Poly Pig - A mediumdensity pig can pass through blockages withmoderate force applied and can move somematerial collected on pipeline walls.

3. High Density Poly Pig - A high density pigpasses through blockages with higher forceapplied and will move material collected onpipeline walls.

4. Brush Pig - This pig has wire brushes orother types of brushes to remove materialresidue left by previous pigs.

5. Scraper Pig - This pig has a number ofhard scrapers built in to scrape the moreresistant residue off pipeline walls.

6. Poly Pig - Final flushing is completed usinga poly pig.

Progressive pigging is necessary to ensure thatthe pigs do not get stuck in the pipeline. The

use of a high density or scraper pig on the firstrun could scrape enough material to stop thepig and block the pipe. Pushing the first one ortwo pigs with several barrels of de-greaser orsurfactant will soften and dissolve hydrocarbonresidue in the pipeline, allowing the denser polypigs to remove the majority of material beforeusing a scraper pig. It should be noted that apipeline which has been kept clean or wascleaned at the time of shutdown, may onlyrequire low density poly pigs and flush water forfinal cleaning. Verification of the pipelinecleaning is based upon flush water qualitychecks which may rely on visual verificationthat there is no hydrocarbon “sheen” ormeasurements by instrumentation.

Flush water is typically pumped down disposalwells, processed for disposal, or trucked to anapproved dump site.

Pipeline Removal OperationsPipelines will generally be removed offshorethrough the surf zone and capped. Theremoval may be completed by an anchoredbarge or work boat with adequate winch andcrane capacity to pull the pipe aboard and liftsections to a cargo barge or boat for transportto shore. The onshore pipeline may beremoved completely, or some sections may beabandoned in place due to their transitionthrough a sensitive environment such as afragile beach bluff. The pipeline end seawardof the surf zone, typically in water depthsexceeding 15 feet MLLW (mean lower lowwater), is capped with a steel cap and jetteddown 3 feet below mudline by divers.

Divers will cut the pipeline with an arc oxygentorch at the platform and install a cap on theend. A tent may be used over the cut point tocatch any residual hydrocarbons, however, theprogressive pigging operation will usually cleanthe pipeline well enough to avoid anyhydrocarbon releases. The pipeline end isburied below the mudline, typically by diveroperated jetting. The pipeline end mayalternatively be covered by a concrete mat asshown in Figure 1 . The mat provides a coverfor the pipeline end that will not hinder a trawlnet. A pipeline pull sled at the platform maycreate an obstacle for fishing. The sled wouldneed to be removed or buried with the pipeline


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end to eliminate the potential snagging hazardfor trawl nets.

Figure 1. Flexible Concrete Mat Pipeline EndTreatment. Exxon OS&T Abandonment Plan.

The recovery of removed pipeline sections isaccomplished by rigging a winch wire to thepipeline and lifting it to the barge. A crane maybe used in conjunction with the winch to hoistthe pipeline onto the recovery vessel. Thepipeline removal operation will typically createforces on the pipeline which result in bucklingand bending. These structural failures have noimpact on the removal process and allow forlower cost removal operations. Excavationmay be required to remove the pipeline, or itmay be recovered without excavation if enoughlifting force can be applied.

Pipeline crossings may be an obstacle todecommissioning, particularly if the pipeline tobe decommissioned crosses under a liveproduction pipeline. A pipeline crossing is theintersection of two or more pipelines, generallyat some location away from the platform site. The crossing of the newest pipeline is usuallybuilt up 1.5 to 2 feet above the older existingpipe with a steel frame bridge and/or cementbags. This crossing creates a mound whichmay be a trawling obstacle. The removal ofone of the pipelines at a crossing creates anelement of risk, and if the pipeline is to beremoved entirely, the abandonment in place ofseveral hundred feet of the pipe at the crossingmay be advisable to avoid any possibledisturbance of the pipeline in service.

Pipeline Disposal

Pipeline materials must be transported by truckor barge to an approved dump site. The scrap

value of the steel in the pipelines is exceededby the cost of removing the pipeline coatings;and therefore a scrapping disposal option isnot viable. The pipeline materials must bereduced in length in accordance with thedimensions dictated by the selected dump site,and may be as short as 6 feet. A hydraulicshear may be used effectively to section thepipeline materials to meet these requirements.

CASE HISTORIES

Exxon, Hondo-to-SALM Pipelines and PowerCableThe first deep water (approximately 500 feet )pipeline and power cable decommissioningproject off California was associated with theremoval of Exxon’s Single Anchor Leg Mooring(SALM) and Offshore Storage and Treatmentvessel (OS&T) in 1994. The SALM/OS&Tfacility was installed in 1980 to transfer,process and store production from platformHondo until the onshore Las Flores CanyonProcessing Facility became fully operational.

This project included decommissioning threeshort (approximately 1.6 miles) pipelines and apower cable that connected the SALM toplatform Hondo (Figure 2 ). A number offactors were considered in determining thescope of work to be performed. The criticalfactors that influenced the decision process inthis case were:

(1) The work area was situated adjacent toactive, high volume pipelines, requiringcareful planning and execution whenestablishing the derrick barge mooring.

(2) Operations requiring saturation divingneeded to be minimized to enhance safety.

(3) The area was considered a productivetrawling area by commercial fishing op-erators.

The condition of the pipelines and powercables were well documented along theiralignments in a number of recent surveys. The most recent of these surveys showed 75%of the length of the two smaller (6 inch and 8inch) and 56% of the larger (12 inch) pipelineswere buried. After considering the options, itwas determined that they could be abandoned

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in place if adequate measures were taken toassure the severed ends would not significantlyinterfere with trawling.

Figure 2. OS&T Abandonment Project FacilitiesLayout. Exxon OS&T Abandonment.

A total of eight primary work vessels wereemployed during the course of decommission-ing the SALM/OS&T and associated pipelinesand power cable. The project required that afour leg mooring system be established for thederrick barge. Precision mooring techniqueswere used to install and remove the fouranchors without incident in spite of their closeproximity to active pipelines in deep water (upto 650 feet).

Prior to disconnecting, the pipelines wereprogressively “pigged” using standardmaintenance procedures and sequentiallyflushed with sea water to remove hydrocar-bons. Each line was flushed until watersamples passed static sheen tests on twoconsecutive flush cycles. The flushedpipelines were severed by divers about 100feet from the SALM base and the spool piecesretrieved for onshore disposal. During pipelinecutting operations, underwater containmenttents were used to collect any traces ofresidual oil that may have been trapped. Thecut ends were sealed with mechanical plugsand each cut end was covered with an articulated concrete mattress (Figure 1 ),because it was not practical to bury the ends tothe required three foot depth using divers.

The power cable system serving theSALM/OS&T facility was somewhat unusual

because the dynamic nature of the SALMsystem required a portion of the cable to besuspended above the sea floor using a three-point mooring buoy (Figure 2 ). Except for thesuspended catenary portion, the 5 inchdiameter power cable was buried along itsalignment. The cable was cut by divers wherethe catenary contacted the sea floor and thesevered end of the cable was buried to a depthof 3 feet. The balance of the cable andassociated mooring system were retrieved foronshore disposal.

Subsequent trawl testing over the abandonedpipelines and power cable, especially over thesevered ends, verified that the area could betrawled with conventional fishing gear. Thelease is still an active component of the SantaYnez production unit and, if it is laterdetermined that the pipelines or power cableimpede commercial trawling operations,appropriate remediation would be relativelyeasy to implement during platform decommis-sioning.

Texaco, Helen and Herman

Platforms Helen and Herman were installed inthe late 1950’s in water depths of 100 feet and85 feet, respectively, offshore Gaviota,California. They were decommissioned in1988 after a 15 year shut down period. Thepipelines’ cathodic protection was notmaintained during the long shut down.

Platform Helen had a 6 inch and 8 inchdiameter production pipeline which cameashore under a train trestle. Platform Hermanhad a 6 inch and 8 inch diameter productionpipeline which came ashore further north onthe Hollister ranch. Both of these areas wereenvironmentally sensitive and at each locationthe pipelines were visible on the beach. TheHerman pipelines passed through a delicatebeach bluff. The decommissioning planrequired the removal of a minimum of 800linear feet of pipeline through the surf zone,and the removal of all of the onshore pipe. Theends of the pipeline were to be capped andburied below mudline at the nearshore cutpoint and the offshore terminus.

A progressive pigging operation was initiatedfrom a crane barge at the platform sites to


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ensure that the pipelines were clean. Theoperation was started after the pipelines weredisconnected from the platform. The piggingoperation revealed leaks in the dormantpipelines, and repairs were made to providethe pipeline integrity necessary to run the pigs.

Following the installation of several Plidcoclamps, the pigging operation was completed. A pig launcher was installed underwater at theplatform site and the flush water was collectedonshore in vacuum trucks and discharged atan approved dump site. A pig receiverinstalled at a valve box onshore collected thepigs at the end of the cleaning run.

The pipelines were then capped and buriedbelow mudline at the platform sites and thecrane barge was relocated to the landfalllocations of the pipelines. The pipelines werecut on the beach by a rigging crew andapproximately 1000 feet offshore by a divingcrew. The crane barge pulled the cutsegments offshore, through the surf zone, andrecovered them for transfer to a cargo barge. The severed ends were capped and buriedbelow the mudline and the remainder of thepipeline, outside the surf zone, was abandonedin place.

The rigging crew on the beach used a bulldozer, an excavator and a rubber tired loaderto remove the onshore portion of the pipelineand valve boxes. The excavations werebackfilled and shaped to natural contours.

Chevron Platforms Hope, Heidi, Hilda, andHazelPlatforms Hope, Heidi, Hilda and Hazel wereinstalled from the late 1950’s to the early l960’sin water depths of up to 139 feet offshoreCarpinteria, California. These platforms had atotal of 14 pipelines ranging from 6 inches to12 inches in diameter. Each of the pipelineswas thoroughly cleaned and flushed usingprogressive pigging techniques prior tosevering.

The pipelines from Hope to shore were alsoused for Platform Grace and Gail production. A 10 inch and 12 inch pipeline from Graceterminated at Platform Hope where productionwas transferred to the Hope to shore pipelines. Therefore the decommissioning of Platform

Hope required a reroute of the pipelines so thatthe Hope to shore lines could continue inproduction. The reroute added two bypasssections of pipeline to the existing lines,rerouting the Grace pipelines around Hope andconnecting to two of the Hope to shorepipelines. Platform Heidi also had productionpipelines terminating at Hope to share thepipelines to shore.

The landfall of the Hope to shore pipelines atCasitas Pier is typically buried. This burialcondition, combined with the continued use oftwo of the three Hope to shore pipelines, madea surf zone abandonment of the unusedpipeline unwise. Removal activities in closeproximity to active pipelines would havecreated unnecessary hazards.

Similarly, the Hazel to shore pipelines areburied at a landfall near Casitas pier. Hildaproduction pipelines terminated at PlatformHazel to share the Hazel to shore pipelines. These pipelines were abandoned in place inthe surf zone.

All of the pipelines abandoned in place in thesurf zone were grouted out to a water depth of-15 feet at MLLW. The grouting operationserves to keep the pipeline weighted down todiscourage any exposure in the future throughthe surf zone area.

Offshore at the platform sites, the cleanedpipelines were cut free of the platform risers,capped and buried three feet below mudline.

These platforms had approximately 8 powercables, although some of them were out ofservice. The power cables were approximately4 inches in diameter with an armor jacket. These cables were abandoned in place bycutting the end free from the structure andburying the end three feet below mudline.

Ventura Tanker Berth Pipelines

The Ventura Tanker Berth was installed in thelate 1940's before the construction of theVentura Harbor breakwater, and consisted ofeight moorings surrounding a pipeline terminuswith loading hoses to connect to tankervessels. The tanker berth had one 20 inchdiameter crude oil emulsion pipeline and one 8

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inch diameter gasoline pipeline. Maintenancedredging of Ventura Harbor was eventuallycompromised by the presence of thesepipelines, although the burial depth wassignificant.

The plan for decommissioning was designedaround the removal of approximately 1500 feetof each pipeline where they crossed the harborchannel entrance and became a potentialhazard to maintenance dredging operations. The entire pipeline was grouted internally priorto removal.

The grouting operation was preceded by a “hottap” of the pipelines onshore, meaning that anaccess hole was drilled with a hot tap toolassembly, designed to contain any internalgases under pressure. Although the idlepipeline was depressurized when it wasoriginally shutdown, a pressure buildup due toexternal heat or chemical reaction waspossible during the period it was inactive. Thisprecaution was taken due to the potentialpresence of explosive or poisonous gasesremaining from the crude oil emulsion residuein the pipeline.

The hot tap gas samples from the 20 inchpipeline verified that there were no hazardousgases present. The pipeline was cold cut witha hydraulic powered reciprocating saw andterminated with a welded flange where a pigreceiver was installed. A pig launcher wasinstalled on the offshore end of the pipe bydivers. Several pigs were introduced into theoil pipeline and the pipeline was cleaned andflushed. The flush water was processed fromthe pipe termination onshore through theremaining pipeline to the existing tank farmnearby. The water was transferred from thetank farm to a processing facility via connectingpipelines. The 8 inch pipeline had beensevered by dredging and was not cleaned.

Grouting operations filled the 20 inch pipelinefrom the onshore access point to the offshoreterminus. The 20 inch and 8 inch pipelineswere then removed in the specified area nearthe breakwater. Divers cut the pipelines intosections and rigged them for recovery onto awork boat. This removal operation requiredextensive excavation to uncover the pipelines. Airlifting techniques were used by the divers to

uncover the pipe at burial coverage exceeding15 feet.

CONCLUSIONS

A clear and balanced understanding ofdecommissioning goals and accurateknowledge of conditions that characterizepipeline and power cable alignments are thenecessary prerequisites for making reasonabledecisions whether or not to remove or abandonin-place. Experience to-date indicates thatremoval will be the preferred disposition optionfor pipeline and power cable segments when:

• they have characteristics that mightinterfere with commercial trawling or otheractivities.

• they are located in water depths less than–15 feet (MLLW) or onshore (pipelinesonly) and not deeply buried.

• they are located in areas subject tomaintenance dredging (navigation chan-nels and designated anchorages).

Mitigation might also be considered as analternative to removal when it can bedemonstrated that it would be effective (e.g.,shrouding severed ends or flanges witharticulated concrete mattresses).


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SITE CLEARANCE AND VERIFICATION

JOHN C. McCARTHYEngineering Geophysicist

Minerals Management Service, Pacific OCS Region

INTRODUCTION

The last stage in decommissioning offshorefacilities is site clearance. Site clearance isthe process of eliminating or otherwiseaddressing potentially adverse impacts fromdebris and seafloor disturbances due tooffshore oil and gas operations.

Though infrequent, the cumulative sum ofmaterials lost overboard in the vicinity of anoffshore facility can become significant over atime frame that may exceed 30 years. Itshould be understood that the debrisassociated with an offshore site is rarely aresult of intentional dumping. Virtually all of itcan be attributed to accidental lossesassociated with routine activities, some ofwhich may not be directly related to activitieson the facility. Vessels service platforms on afrequent basis to transfer supplies andpersonnel to and from shore bases. Tires,commonly used as fenders on service vesselsand platforms, are occasionally lost during theinevitable contacts that occur. Lessfrequently, a load of supplies may be droppedoverboard during transfer. Materials are alsolost during construction and routine mainte-nance. Moorings for service vessels failperiodically, leaving anchors and associatedground tackle (i.e., chain, cable) on theseafloor.

Except for the unusual case where a loss isconsidered an operational or environmentalrisk, immediate recovery is not considered apractical or necessary option. Piecemealsalvage is not cost effective and usuallyaddresses no functional objective as long asthe structure remains on location and the lostmaterial poses no risk. Some debris mayeven enhance the value of the artificial habitatassociated with the structure. However, oncethe structure is removed, regulations andlease terms require that the location be left ina state that will not preclude or undulyinterfere with other uses. Site clearance tends

to focus on eliminating debris that haspotential to interfere with other activities.

Site clearance also attempts to address suchissues as seafloor disturbances around thefacility. Mounds of shell debris from repeatedmaintenance cleaning of biofouling from thestructure can accumulate around its base. Such accumulations, combined with mud,cuttings and cement discharged during drillingoperations, have been observed to reach athickness of more than 20 feet above theoriginal seafloor at shallow water locationswhere dispersion was minimal. At some sites,anchors from large construction vessels mayscar the seafloor with deep furrows and mudmounds. Mitigation may be a more effectiveand environmentally preferable solution than“restoration” when dealing with fishingpreclusion issues related to these types of siteconditions.

The level of effort required to locate, assessand resolve potential problems associatedwith debris and seafloor disturbances dependson potential uses of the area, environmentalsetting, platform age and the frequency ofcertain activities associated with the operationof the facility being removed. Clearing thelocation around a typical offshore Californiaproduction platform with 20 to 40, or more,wells and an operational history that mayexceed 30 years, can be a major part of thetotal decommissioning effort.

GOALS AND PLANNING

The primary goal of site clearance is to clearthe location impacted by the facility andassociated activities by removing all potentiallyhazardous materials and eliminating, ormitigating, conditions that might interfere withother uses. For all practical purposes, “otheruses” tends to mean commercial trawlingoperations, as navigation or military use areusually not significant factors associated withoffshore California facility sites. Secondary

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goals include clearing the site cost effectivelywith minimum adverse impacts.

Clearing an offshore industrial site mayappear to be a simple task but experience hasshown it is not one to be taken lightly if a highstandard is to be achieved. The strategy forclearing an offshore location must addressconditions that tend to be very site-specific. An adequate strategy for one location mayprove ineffective or unnecessary at another. The following factors should be consideredwhen planning site clearance.

Determine Disposition Option

To date, all site clearance operations offCalifornia have occurred at sites where totalremoval of facilities, except for pipelines andpower cables, was the only disposition optionapproved. This may not always be the case, asconsideration is being given to dispositionalternatives that might include leaving part of astructure on location, especially in deep water. Obviously, the scope of site clearance work willbe determined by the disposition option chosen.

Determine Alternative Uses

As previously noted, one of the primary goalsof site clearance is to condition a location sothat it is available to commercial trawlingoperators; assuming, of course, the facility isto be completely removed. Consultation withrepresentatives of the trawling industry andfisheries regulators should be the basis fordetermining a site’s suitability for anycontemplated use. Information fromrepresentatives of other fisheries (commercialand recreational) and fisheries researchersshould also be considered. The environ-mental setting of the area to be cleared alsoneeds to be considered. Some facilities maynot be located in an environment suitable fortrawling or any other use that requires specialsite conditioning. The effort and expense ofsite clearance, beyond removal of potentiallyhazardous materials, may not be beneficial insuch cases.

Review Operational History

Regulatory agencies and operators maintainrecords that are useful in estimating the scopeof site clearance effort that may be required.

Examples include “lost item” and mooringmaintenance records, surveys that documentseafloor debris and documented userconflicts, such as Fisherman’s ContingencyFund claims.

Usually, the lead regulatory agency forreviewing the decommissioning project is inthe best position to comprehensively assesssuch records. The lead agency also reviewsthe operational history of the lease if it is beingrelinquished. These reviews determine, inpart, the size of the area that may have beenimpacted by all oil and gas activities, fromexploration through decommissioning. Onsome leases, there may be unresolved siteclearance issues related to early explorationdrilling in the 1950s and 1960s, that would notbe addressed if the focus is only on theimmediate area surrounding the facility beingdecommissioned. In such cases, siteclearance may only clear a small area in afield of obstructions and the site may not betrawlable unless there is a plan to addressconditions present in the surrounding area.

Conduct Pre-clearance Surveys

The two most recent decommissioningprojects off California employed “pre-clearance surveys to estimate the extent ofthe debris field (see CASE HISTORIES). Themost effective pre-clearance surveys employvery high-resolution side scan sonar techniqueto efficiently and accurately locate potentialdebris and other features of interest overrelatively large areas. Earlier Californiadecommissioning projects relied more ondiver observations and ROVs (RemotelyOperated Vehicles) equipped with videocameras and sector scan sonar. Thesetechniques are more suitable for locating,assessing and assisting in removal andremediation near a work site or at previouslysurveyed locations. They are less effectivethan side scan sonar as a primary tool forsystematically searching and locating debrisover large areas and should not be dependedon for that purpose unless the area is smallerthan a few hundred feet in diameter.

There are a number of advantages inconducting a pre-clearance survey using sidescan sonar. The technique is effective forproviding a comprehensive overview of the


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distribution of debris over a large area, thusproviding some degree of assurance that far-field debris are not missed. Side scan surveysalso provide information useful in assessingthe potential for alternative uses of the sitebecause it can document seafloor conditions,such as high relief rocky habitat, that precludetrawling. Although pre-clearance side scansurveys have, until recently, been consideredto be an extra decommissioning expense,experience indicates the information gainedcan result in significantly lower ROV and divecosts by allowing more efficient use of thosemore expensive and time consumingtechniques. Information from surveyscompleted prior to beginning removal work ona facility can also be used as a planning toolfor minimizing adverse impacts on anysensitive habitat that may be located near thework area. However, one should be awarethat the quality of the side scan sonar surveyscan vary. The effectiveness of side scansonar surveys for site clearance applicationsis improved by optimizing target detectionrather than seafloor mapping capability. Pre-clearance surveys conducted primarily todocument sensitive habitat prior to facilityremoval may need to be followed by a secondsurvey, optimized for target detection, after thestructure is removed (see CASEHISTORIES).

CLEARANCE AND VERIFICATIONSTRATEGIES

Equipped with a comprehensive understand-ing of the site, with an emphasis on applyingthe results of a thorough evaluation of a pre-clearance survey, one should have a clearidea of the distribution and types of conditionsthat will require attention to prepare the site foralternative uses. As previously noted, most ofthe effort spent actually clearing the siteinvolves removing debris. However, theremay be other conditions at a site that requirealternative methods of remediation.

Debris Removal

Debris removal within a fixed radius of anoffshore structure is usually an element of thefacility removal contract. Debris density isusually highest near the structure, thus much,if not most, of the debris associated with a

facility is salvaged during its removal using thesame equipment.

The salvage methods used during the removalof a facility depend primarily on using thedivers and ROVs already on location whilethey are working near the base of thestructure. This is an ideal arrangement forremoving large or awkward items, as heavy liftequipment is already on location. However,once the structure has been dismantled andremoved, the use of divers to locate andremove relatively small items scattered overan extended area is not cost effective. Goodplanning, based on a high quality pre-clearance survey, assures that all itemsrequiring large capacity lift capability will beremoved before demobilizing the derrickbarge. Usually, any heavy items that remainon the seafloor are within the capacity of asuitably rigged anchor handling vessel,although most debris are actually salvagedusing the dive/ROV support vessel.

Following removal of the facility andassociated near-field debris, the mostcommon method in the Gulf of Mexico forremoving items that might remain is to trawlthe area with nets. Site clearance trawling inthe Gulf has resulted in the development ofspecialized, heavy-duty trawling gear withreinforced mesh, commonly known as “GorillaNets”. These nets are dragged across theseafloor, often using a saturation pattern oftraverses designed to provide 100% coverageof the clearance area in four directions (i.e.,headings at 90° intervals). This may be oneof the most efficient and cost effectivemethods to assure significant debris isremoved over large areas. However, to date,such methods have not been used to clear awest coast site because suitable vessels arenot generally available and the need to clearsites has been too infrequent to justifymobilizing and maintaining such a capabilitylocally. It should also be noted that most westcoast platform sites are located in waterdepths greater than the 300 foot cut-off depthfor site clearance in the Gulf of Mexico. Deploying this type of gear in water depthsgreater than 500 feet would require signifi-cantly larger winch capacity and greaterhorsepower. Either factor might make thismethod a less viable alternative to removaltechniques currently in use off California.

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Local trawling vessels, with few exceptions,employ very small nets for deep water trawlingand most of their available power is used tohandle the very long cables required. Localvessels also tend to be efficiently sized and,thus, would be difficult to retrofit with thesignificantly larger power plants and winchesneeded to operate larger, heavier gearsuitable for removing debris. The narrowmargin of reserve power available in the localtrawl fleet is part of the reason seeminglyminor seafloor debris can cause them majorproblems.

Recent site clearance operations off Californiahave relied primarily on ROV and divermethods for debris removal, although somelocal trawlermen have unintentionallyparticipated in such work. An ROV equippedwith sector scan sonar, video camera andusing acoustic tracking, integrated with theprimary surface navigation system, is theprincipal method employed to relocate andassess sonar targets from pre-clearancesurveys. The advantages of an ROV vs. adiver are safety, ability to function for extendedperiods at great water depth, and the ability ofsonar to locate targets beyond the range ofvisibility. The principal disadvantage of anROV is the limited range of manipulativefunctions it can perform compared to humanhands, which is why divers are still used forsalvage operations at water depths less than afew hundred feet. Even in shallow water,ROVs are used to minimize diver time duringsearch and assessment operations.

At water depths beyond a few hundred feet,salvage contractors rely almost solely on ROVmethods. The most common strategy is to fitan ROV manipulator arm with a tool, suitablycustomized so that it is capable of attaching aline to the object. The line is then run to asurface vessel equipped with an adequatelysized winch and the item retrieved. This is atedious but effective method for the majority ofdebris encountered, although other methodsmay be needed for unusually awkward orheavy items. In such cases a separate,dedicated salvage operation may be required.

The heaviest item that might be routinelyencountered are abandoned work boatmoorings. Salvage of existing and knownabandoned moorings is usually part of the

facility removal operation. However, it wouldnot be unusual for a platform to have 10 ormore mooring failures during a functional lifeof 30 years. Records may be inadequate forassuring all lost moorings were recovered,which is a reason to conduct a careful searcharound all known mooring locations forevidence of orphaned moorings. Sonar willusually detect any orphan moorings capableof causing problems for trawlers.

Other Remedial Methods

Some potential obstructions may beabandoned in place if adequate measures aretaken to remediate the problem. Typicalexamples are the severed ends of pipelinesand power cables. Regulatory requirementsrequire cut ends to be buried or otherwiseconditioned so that they will not interfere withtrawling. Burial is usually accomplished bydivers using hydraulic jetting equipment. However, bottom type, pipe diameter or waterdepth may preclude burial. In such cases,some other form of end treatment, likearticulated concrete mats or shrouds, maysuffice to assure trawlability. Similartreatments may also be suitable forremediating other potential snags, like pipelineflanges.

Another class of features that can causeproblems to trawlers are major seaflooralterations such as deep scars and mudmounds caused by mooring large workvessels such as the derrick barges used forremoving structures. The seafloor perturba-tions caused by anchoring usually heal withtime, due to natural processes, but it mightrequire years. Past attempts at remediatingsuch features have shown mixed results andsome alternative mitigation that is advanta-geous to the affected user may be a morepractical and immediate solution.

A more difficult seafloor alteration toremediate are the mounds of shell debris,mixed with drill cuttings and cement, that canaccumulate under shallow water facilitieswhere dispersion is minimal. The recentplatforms decommissioned by Chevron (seeCASE HISTORIES) were characterized by20+ foot high mounds that are untrawlableand some form of alternative mitigation forpermanent preclusion may be the only


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practical option. In deep water, suchaccumulations tend to be dispersed over alarger area, although cement accumulationsaround well risers may have potential fordamaging trawl gear. If relief is notexcessive, articulated concrete mats may be apossible solution for remediating some ofthese conditions.

Verification

The best method to test the adequacy of siteclearance operations, when conditioning fortrawling is the objective, is to trawl the areawith the type of gear that will be used. Trawling tests were used to verify the twomost recent California decommissioningprojects (see CASE HISTORIES). In bothcases, local fishermen were contracted, butthe projects were quite different in execution.

In the shallow water Chevron project, a verydense pattern of trawl passes was scheduled,covering an area within a 1000 feet radius ofeach platform site. GPS navigation was usedto accurately locate the position of each snagencountered and documented snags weresystematically remediated and retrawled. Theshell mound features that remained after thestructures were removed were found to beuntrawlable with conventional gear. Themounds were also trawled with roller gear butsome snags were still experienced. Othersnags were encountered outside theclearance area, while making turns to line upfor the next traverse. Some of these snagswere caused by obstructions remaining fromearly exploration drilling.

In the Exxon project, the clearance area wasrelatively large, about 2 square miles, and inwater depths that ranged from 300 to 700 feet. Although thorough, the clearance effort wasconsidered an interim measure as the lease isstill active and may need to be cleared againwhen it is relinquished. In this instance, trawltesting objectives focused only on areas withpotential to cause problems. Because of thedeep water and the difficulty in positioning thesmall (approximately 40 foot opening) net,acoustic tracking was installed on the net toassure precise knowledge of its positionrelative to the targeted test areas. The onlysnag encountered during test trawling wasattributed to natural features.

When a site is not being conditioned fortrawling, the most appropriate verificationmethod is to conduct a post-clearance sidescan sonar survey with methods similar tothose used in the pre-clearance survey. Acomparison of data from both surveysprovides a comprehensive picture of what wasaccomplished during clearance operationsand is an excellent method for documentingthe final condition of the site.

Off-the-shelf software/hardware systems arenow available that facilitate the construction ofmosaics from sonar data, making suchprojects less labor intensive and more precisefor use in before and after comparisons. Some software allows side scan sonar data tobe interfaced with sector scan sonar used inROV operations. The data can also bemanipulated to help locate and classifypotential debris targets that are hidden inbackground clutter on conventional facsimiledisplays of sonar data. The use of these dataenhancement and analysis techniques willallow more definitive verification of futureoffshore site clearance projects.

CASE HISTORIES

Exxon, Santa Ynez Unit, SALM andOS&T Site

The first and only major site clearance projectrelated to decommissioning a federal oil andgas facility off California occurred in 1994following the removal of Exxon’s SingleAnchor Leg Mooring (SALM) and OffshoreStorage and Treatment Vessel (OS&T). TheSALM/OS&T facility was situated inapproximately 500 ft of water, about 3.5 milessouth of Gaviota, CA and was used totransfer, process and store production fromplatform Hondo between 1980 and 1994. With the addition of output from two new oiland gas platforms, all Santa Ynez Unitproduction was pipelined onshore to the newLas Flores Canyon processing facility, makingthe SALM/OS&T facility redundant.

There were a number of precedent settingaspects to the SALM/OS&T site clearanceproject which made it a challenging exercise,including:

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ÆÆ Deepest water site cleared on the federalOCS (possibly the world?)

ÆÆ Motion of the OS&T around its mooringhad potential to distribute debris over alarge area

ÆÆ Trawlers wanted access to the areaalthough it was still under lease and siteclearance, arguably, could be delayeduntil production ceased, 10 to 20 yearslater.

Exxon had already arranged for a siteclearance program as part of the removalcontract for the SALM/OS&T facility. The areaproposed for clearance included areas aroundthe SALM base, derrick barge moorings usedfor decommissioning, and at a number ofother specified locations with suspectedpotential to impede trawling. Exxon’s initialproposal met or even exceeded precedent,given the water depth. However, the MMSdetermined that a much larger area needed tobe documented and cleared, if necessary, tobe confident that the area being reopenedwould be trawlable.

The principal factors considered in reviewingExxon’s site clearance program included:

ÆÆ dispersed debris field

ÆÆ potential for debris from other activities inthe vicinity, especially pipeline construc-tion

ÆÆ presence of natural obstructions in thearea had been documented on priorsurveys (high relief rocks)

ÆÆ three partially exposed pipelines and apower cable decommissioned in-place,including the articulated concrete matsused to cover severed ends of pipelines

ÆÆ Seafloor scars caused by derrick bargemoorings, power cable moorings, pipelayoperations and removal of SALM basepilings

ÆÆ Documented loss of a large anchor from atanker

After re-evaluating all these factors, Exxonagreed to significantly expand the scope ofsite clearance. Site clearance was conductedin two phases. The removal contractor wouldstill perform phase 1 - “Facility Removal AreaClearance” and the additional area specifiedwould be included in phase 2 - “Outer

Operational Area Clearance.” Both phasesused a three stage approach to site clearance: (1) pre-clearance sonar search, (2) targetevaluation and remediation, (3) trawl testingfor verification.

Phase 1 - Exxon’s facility removal contractorsurveyed a 1500 ft radius area around thecenter of the SALM base using a 500 kHz sidescan sonar. Side scan sonar was also usedto relocate the lost tanker anchor. An ROVmounted sector scan sonar was used tosurvey a 200 ft radius around each of the fourderrick barge moorings to document anchorimpacts.

All unidentified sonar targets were assessedusing ROV video and potential obstructionswere salvaged using the removal equipmenton site. The cleared areas were then testtrawled by a licensed commercial trawlerusing standard trawling gear. No obstructionswere reported.

Phase 2 - Following SALM/OS&T removaloperations, a second side scan sonarreconnaissance was conducted overapproximately 2 square miles of seafloor,between Platform Hondo and the OS&T site. The water depth ranged between 300 and 760feet and the survey included the area clearedby the removal contractor in Phase 1. The500 kHz side scan sonar system wasequipped with acoustic tracking integratedwith surface navigation to facilitate accuratesonar target location. Sonar range andtransect spacing provided better than 200%coverage of the survey area.

The Phase 2 side scan sonar survey located270 sonar targets (including seafloorfeatures). All sonar targets were cataloged,mapped and their sonar images classified forfollow-up evaluation using an ROV.

The second stage of phase 2 clearanceoperations included ROV target identificationand salvage. Approximately 60% of the sonartargets were selected for evaluation with anROV because they had sonar signatures thatsuggested potential debris or obstructions. The ROV was equipped with sector scanningsonar and acoustic tracking to relocatetargets, and video for evaluation and documentation. Targets considered to be


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potential trawling hazards, were salvagedusing the ROV. This required equipping theROV with an appropriately designed tool toenable a cable to be attached to the item forrecovery. A total of 36 items of debris wereultimately recovered in phase 2. Tires werethe most common type of debris recovered(50% of total). A number of items wererecovered from the area cleared in phase 1. We assume this was a consequence of thephase 1 contractor knowing a morecomprehensive, site clearance effort wouldfollow.

The final stage in phase 2 site clearance wasverification using conventional trawl gear. Trawl verification efforts focused on specificareas where residual conditions might posesome risk of “snags” or net damage. The sizeof area, water depth and small size of deepwater trawl nets used in the local fisheriesmade a typical 200% to 400% trawlverification strategy impractical, and probablyunnecessary, given the thorough clearanceeffort already implemented. Intensive trawlverification was also considered premature inthis case because the area could be subject toadditional clearance efforts when productionceased on the active lease at some,undetermined, future date. Although trawlverification concentrated on the highest riskareas, and employed acoustic tracking toassure the net passed over potential hazards,no obstructions were encountered. Netdamage did occur on one pass; however, thetrawl operator believed the damage wascaused because he strayed into high reliefrocks outside the designated test areas.

The clearance effort following removal of theSALM/OS&T facility appears to have beensuccessful as there have been no reportedgear damage or losses during the year it hasbeen accessible to trawlers. At the time this isbeing written, the three step approach to siteclearance used by Exxon (i.e., pre-clearancesonar reconnaissance, evalua-tion/remediation, verification) serves as aworking model for evaluating future CaliforniaOCS site clearance proposals.

Chevron, “4-H” Platform Sites

The most recent offshore site clearanceoperations conducted off California occurred

in 1996 following Chevron’s decommissioningand removal of four platforms on Californiastate leases seaward of Santa BarbaraCounty, between Carpinteria and Summer-land. Platforms Hilda, Hazel, Hope and Heidi,commonly referred to as the “4-H” platforms,were installed between 1958 and 1965. Atotal of 134 wells were drilled from these fourrelatively shallow water facilities (depthsranged from 98 to 141 feet). The primaryobjective of site clearance operations at the“4-H” platforms was to condition the areasimpacted by the facilities so that they could betrawled. The effort expended by Chevron andtheir contractors in trying to accomplish thatobjective may be one of the most intensivesite clearance exercises related to offshore oiland gas decommissioning, to date.

Factors considered in developing a siteclearance strategy included:

ÆÆ older, debris potential uncertain

ÆÆ shallow water, debris probably concen-trated close to platform

ÆÆ significant accumulations of shell debris,mixed with, cement and drill cuttings atthe base of the platforms.

Prior to commencing removal of thestructures, a side scan sonar and bathymetrysurvey of the seafloor within a 1400 footradius of each platform was conducted. A 500kHz sidescan sonar system was used withrange and transect spacing adequate toachieve a theoretical 400% coverage of theseafloor around each platform structure. Thepre-decommissioning survey was used tolocate debris and confirm the locations ofactive pipelines, power cables and sensitivehabitat that would need to be avoided duringdecommissioning operations.

During the course of structure removaloperations, debris located in the pre-decommissioning side scan sonar survey wasremoved by divers with ROV assistance. Facility elements abandoned in-place, such aspipelines, were buried by divers usinghydraulic jetting technique.

Following removal of the “4-H” platforms anddebris, a second, post-decommissioning, sidescan sonar survey was conducted over anarea that encompassed a 1000 foot radius

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around each platform site and the area aroundthe two temporary moorings used duringremoval operations. The post-removal surveywas used to verify debris removal bycomparing results to the earlier survey and tolocate any new or residual features that mightbe a potential problem for trawl verification. Swath bathymetry studies were alsoconducted to document the mounds of shelldebris that characterized all four sites.

A licensed commercial fisherman, usingconventional trawling gear, was contracted todetermine if the sites were adequatelyconditioned to allow snag-free, trawlingoperations. Trawl testing was conducted on avery dense, saturation grid employing 102,2000 ft long traverses at each platformlocation (i.e., the area covered by the secondside scan sonar survey). Trawl passes werespaced 40 ft apart with one half the traversesoriented N-S and the other half, E-W. Theinitial trawling trials occurred over a fourmonth period in late 1996 (total of 46 workingdays) and a total of 25 snags were docu-mented. More than half (14 of 25) werebelieved to be associated with pipelines orpower cables; another 5 were located on theshell mounds at the old platform sites. Actually, more snags would have beenrecorded if attempts to trawl across themounds had not been suspended early in thetrawl testing program. The remaining 6 snagsthat were documented were associated withundetermined or natural features, or wereencountered adjacent to, but outside, thedesignated clearance areas. By the timetrawling trials with conventional gear weresuspended (12/96), about 80% of the plannedtrawling was complete.

Chevron responded to the results of the initialtrawl testing with additional efforts focused oneliminating snags, including two associatedwith an old drilling site outside the designatedclearance zone. Later, in mid-1997, furthertrawl testing was attempted over the shellmounds using roller gear of the type Chevronhad previously supplied to Santa BarbaraChannel trawl operators as mitigation forproblems alleged to be associated with one oftheir OCS pipelines. Preliminary reportsindicate the roller trawls were significantlymore successful in traversing the mounds butsnags were still experienced.

As this case history is being written (9/97), theshell mound issue remains unresolved. Commercial trawl fishermen want the moundsremoved to clear the area for their activities. However, others consider these relief featuresto be potential habitat that may enhance hookand line fisheries (commercial and recrea-tional) and diving opportunities.

SLC project conditions require Chevron toconduct a follow-up seafloor survey one yearafter project completion, if warranted. In themeantime, it is clear that the shell mounds arenot trawlable. However, this may be a classicexample of a site condition that cannot, orshould not, be directly mitigated. The moundsare about 200 to 220 feet in diameter and theirrelief above the original seafloor ranges from22 to 26 feet. The average volume of materialcontained in each mound is estimated to be inexcess of 8,000 cubic yards. The environ-mental impacts, that would result fromremoving, transporting and disposing of morethan 30,000 cubic yards of material, would besignificant. In such instances, alternativemitigation that addresses the needs of theaffected users should be considered.

CONCLUSIONS

Site clearance activities associated with themost recent offshore California oil and gasdecommissioning projects are among themost thorough and sophisticated everperformed by the industry. Sonar search andmapping technology is being used effectivelyto document site conditions and the industryhas shown considerable diligence inaddressing potential user problems. In spiteof these unprecedented efforts, some of theeffects of production activities may not beeasy or practical, or even reasonable, toremediate. High relief shell mounds thatremained at the sites of four recently removedshallow water platforms will locally precludesome activities of one user group, althoughthey may well enhance opportunities forothers. Experience, to date, does not providemuch precedent for dealing with the conflictinginterests in such cases but they are anopportunity for alternative mitigation whichcould be more advantageous than eliminatingcertain types of obstructions when all interestsare taken into account.


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REFERENCES

Case HistoriesFugro West, Inc. February 1997. Chevron

State Platform Abandonments, PostAbandonment Debris Surveys, PlatformsHope, Heidi, Hazel & Hilda, Santa BarbaraChannel, California. Report prepared forAmerican Pacific Marine, Inc. by J. Babbittand J. Carothers, (Fugro West WO #96-7722/8401).

Exxon Company, U.S.A. August 1994. ExxonOS&T Abandonment, Final Report. Prepared by Exxon staff and contractors.

Fugro West, Inc. March 1996. Chevron StatePlatform Abandonments, Pre-Abandonment Debris Survey, PlatformsHope, Heidi, Hazel, Hilda, Santa BarbaraChannel, California. Report prepared forAmerican Pacific Marine, Inc. by J. Babbitt,D. E. Stutts, J. Carothers, (Fugro WestWO# 96-83-7721).

Fugro West. July 1994. OS&T LocationClearance Inspection, Santa BarbaraChannel, California. Report prepared forOPI International, Inc., by J. Babbitt.

Pelagos Corporation. July 1995. OS&TLocation Clearance Survey, OS&T FacilityAbandonment Project, Santa BarbaraChannel, California. Report prepared forExxon Company, U.S.A.

State Lands Commission, State of California. 1997. Project Completion Report, ChevronU.S.A. Production Company, “4-H” Plat-forms Abandonment at Carpinteria. Prepared by A. J. Naughton, (SLC File #s:W410654, PRC 1824, PRC 3150).

Side Scan SonarEG&G (no date). Side Scan Sonar, A

Comprehensive Presentation. Preparedby: EG&G Environmental EquipmentDivision, 151 Bear Hill Rd., Waltham,Massachusetts 02154 (most recentversion of this manual may still be avail-able from EG&G at the above address).

Klein Associates, Inc. 1985. Side Scan SonarTraining Manual. Prepared by CharlesMazel (this or more recent versions maystill be available from: Klein Associates,Inc., Undersea Search and Survey; KleinDrive; Salem, New Hampshire 03079).

Trabant, Peter K. 1984. Applied High-Resolution Geophysical Methods. Off-shore Geoengineering Hazards, Chapter 5- Side Scan Sonar (pp. 61-81). Generalreference on offshore geophysical surveymethods, published by InternationalHuman Resources Development Corpora-tion (IHRDC), Boston 265p., (1SBN 0-934634-85-8).

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DECOMMISSIONING OF ONSHORE FACILITIES:TECHNICAL ISSUES

LUIS F. PEREZSanta Barbara County Energy Division

Santa Barbara, CA

Decommissioning and removal of offshorefacilities in most cases have onshorecomponents that need to be considered at thesame time that any offshore project isconsidered. Although the goals ofdecommissioning projects, whether offshore oronshore, are substantially the same,decommissioning of onshore facilities presentsa different set of technical challenges from thoseof offshore facilities. Decommissioning is alsoaffected by the different types of existing oil andgas facilities that are auxiliary to offshoredevelopment. Those facilities may include oiland gas processing facilities, marine terminals,pipelines, and storage facilities among others. Generally, the goal of decommissioning is torestore the site to its original, prior to oil and gasdevelopment state, or for some otherpredetermined and approved land use. Onshore facilities are generally decommissionedby removing aboveground facilities, testing forcontamination, remediating if necessary,recontouring, and revegetating the site.

REMOVAL

Removal is defined as the proper decommis-sioning, dismantling and disposal of all aboveground facilities, appurtenances and any otherobstruction or structure constructed for theoperation of the oil and gas facility. In addition,removal also refers to the proper unearthingand disposal of underground facilities such asunderground tanks and pipelines if deemedenvironmentally preferred.

Removal is typically done as a series of stepsthat include draining, cleaning and flushing allvessels; removal of all vessels, above groundpiping, and appurtenances; removal of allbuildings and foundations; removal ofunderground sumps, cables and piping; andloading and transporting of materials orequipment by truck to be recycled, sold, soldfor scrap or disposed at an appropriate landfill.

During the draining and cleaning of all vesselscare is taken to ensure no materials are spilled. In the cleanup of tanks, tank bottoms andresiduals are removed using vacuum trucks orsump pumps. Tank walls are washed to baremetal with diesel and water. Tank bottoms,residuals and cleaning wastes are treated andrecycled where possible by utilizing a mobiletreatment unit or at an approved treatment andrecycling facility. The removal of all vessels and above ground piping entails unbolting equipment and cuttingequipment into sections (if the equipment is notreusable) that can be easily transported to anappropriate recycling or salvaging facility, or fordisposal. Underground components include sumps,foundations, piping, underground tanks,electrical cables and conduits, and cathodicprotection cables. Underground componentsare removed using trenching equipment andthen are cut into transportable pieces. Decommissioning of pipelines used to ship oil,gas, and sometimes produced water generallyentails inspection of the pipelines concurrentwith survey and preparation of the site, followedby purging and capping of the pipelines. Pipelines are left in place or removeddepending on burial depth and location. Pipelines that are buried less than 3 feet indepth are usually excavated and removed. Typically, pipelines are removed in creekcrossings and other exposed areas to preventfuture erosion. In some cases, pipelines areslurried with cement to ensure that their integrityis preserved through time.

CONTAMINATION TESTING

Prior to facilities being removed, a preliminaryinventory of existing equipment and hazardousmaterials should be collected. In addition,historical information can be used to ascertainpotential sources of contaminants and types of


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contaminants that may be encountered withinthe facility to be decommissioned. Historicalinformation is also useful for documentation ofprevious spills or other incidents. The nextstep would be to conduct a preliminary surfaceand subsurface investigation. Typically, thesampling program at this stage should includea soil gas survey, shallow soil borings,chemical analysis and the preparation of apreliminary assessment report.

The initial sampling should take place in areassuspected of having the greatest probability ofsubsurface contamination. Sampling locationscan be determined based on visual inspec-tions, review of the site history and site surveysand evaluation by a qualified contractor. Trenches are usually excavated and earthmaterials examined, specially in formertreatment, storage and processing areas of thefacility. The results of the preliminary investigation areused to determine if significant contaminationhas occurred. If it has, then an EnvironmentalAssessment may be necessary to define theextent of the contamination. The Environ-mental Assessment will consist of moreextensive testing including: soil testing, soilvapor testing (if applicable), groundwatertesting (if applicable), health risk and ecologicalrisk assessments as needed or required. There are a number of sources ofcontamination associated with onshore oil andgas facilities. Table 1 provides a list ofpotential contaminants associated withdifferent types of oil and gas operations. Existing governmental regulations requireremediation or containment of oil spills as theyoccur; additionally, regulations specify measuresto protect vulnerable areas such as creeks fromspills. However, accidental releases occurirrespective of, or before such regulations wereeffective and enforced. In addition, othersources of contamination are minor spills ofcrude oil from aging infrastructure, and spills ofimported products that may contain hazardoussubstances. The types and causes ofcontamination vary widely, depending onoperating procedures and processes used in aspecific activity and historic period. Forexample, some processing operations activeduring the 1960s used fluids as a heat transfer

medium that contained PCBs before they wereclassified as suspected human carcinogens. Spills of these fluids during handling,processing, and storage left soils contaminated.In most cases, chronic leaks from tanks andpipelines usually result in remedial efforts duringdecommissioning . Regulatory agencies typically base characteriza-tion of crude oil releases and level of remedialaction on concentrations of total petroleumhydrocarbons and, in some instances,concentrations of individual soluble constituentssuch as benzene, toluene, ethylbenzene, andxylenes (collectively referred to as BTEX) andcertain polynuclear aromatic hydrocarbons thatare toxic in certain dosages. If hazardous wastes are discovered ingroundwater, the Regional Water Quality ControlBoard (RWQCB) can require remediation,depending upon type(s) and extent of hazards. If hazardous wastes are discovered in soil,RWQCB will investigate type and potential toleach through to groundwater, and proposeremedial actions based on their findings. REMEDIATION OF CONTAMINATEDSITES

Remediation is defined as the removal andproper disposition of unauthorized or accidentalreleases and/or contamination pertinent to theoil and gas process or related operation. Remediation must include areas affected bythe unauthorized disposition or accidentalrelease when contamination occurs off the site,but where the contamination is generated bythe facilities operations.

The primary goals of remediating contaminatedsoils are to protect public health, to protectgroundwater in rural areas necessary to supportthe state's agricultural industry and to protectsensitive environmental resources. Basic issuesthat take shape around remediation of soils andgroundwater generally focus on type ofcontaminant, extent, cleanuplevel, cleanupmethods, and timing of remediation. The type ofcontamination also weighs heavily in definingpotential issues.

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Table 11

Listing of Potential Contaminants Associated with Oil & Gas OperationsProcess-SpecificEquipment, or Type ofArea

Possible Contaminants

Contaminated Soil aroundOil Field Facilities andEquipment

The soil may contain one or more of the following: asphalt, BTEX (benzene,toluene, ethyl benzene, xylene), chemical residues, paraffin, salt, tar, and/orweathered oil.

BTEX will only be associated with light oil fields (i.e., high gravity oil production).Drilling Muds Elevated concentrations of chromium may be found in drilling mud pits which

contain ferrochromelignosulfonates in the disposed drilling mud.Cut-Labs Cut-labs may have associated solvent waste disposal into a pit/sump, or into a dry

well located near the lab.Electric DistributionCenters

Some distribution centers may have PCB contamination from leaking transformersand other oil-filled equipment.

Filters Some diatomaceous earth filters contained a precoat of asbestos fiber, or cellulosefiber. Old installations will have a disposal pit that probably contains asbestos fibersmixed with diatomaceous earth, and the solids filtered from the water.

Flares Ash from burning crude will contain heavy metals. Area around flare may becontaminated with heavy metal salts.

Storage Yards PCBs, other chemicals. Hydrogen Sulfide GasScrubbers

Iron sponge units would leave a residue of metallic iron, iron sulfide and iron oxide(rust). Spent iron sponge can be pyrophoric.

Scrubbers that use the amine reaction unit may have elemental sulfur as an endproduct, and probably have sulfur storage areas or potential for sulfur spills.

Loading Areas Likely areas where hydrocarbon spills, leaks or drainage can occur.Oil and Gas Wells Must be properly abandoned to prevent flow of oil, gas, or water to surface and to

prevent communication between salt water and fresh water zones.

Early produced water spills from vintage 1950s fields may contain arsenic due touse of sodium arsenite in producing oil wells for corrosion inhibition.

Pipelines Any hazard associated with pipelines will be due to either contained fluids, or toareas where leaks have occurred and contaminated the soil.

Pump Stations Hazards at pump stations would be due to associated sumps or contaminated soil. Besides hydrocarbon spills, spills or leakage of thinners or diluents may be aconcern.

Old pump stations may have used mercury-containing flow meters. Some mercuryleakage or disposal may have occurred on-site.

Steam Lines Some of the early thermal lines may have been wrapped with an asbestos-containing insulation.

Sumps/Pits Materials contained in sumps can include asphalt, chemical wastes, drilling mud,formation solids, salts, tar, trash, waste lubricating oil, waste water, water, andweathered oil.

Tanks Potential problems with tank farms include: contained solids, contained fluids,contaminated soil around or underneath the tanks, and associated pits or sumps.

The following materials may be found inside old oil field tanks: asphalt, chemicals,chemical residues, corrosion products, crude oil, crude oil diluent, diesel oil, drillingmud, filter sand and gravel, foaming agents for fire control, gas oils in gas storagetanks, gasoline, glycol and/or glycol residues, green sand, ion exchange resins, ironsponge, lubricating oil, road oil, salt, sand, solidified oil, tar, water, and waste water.

Water Treating Facilities Chemicals used include emulsion breakers, coagulants, polymers, biocides, scaleinhibitors and corrosion inhibitors.

1Scott, J. 1994. Santa Barbara County Oil and Gas Facilities Inventory.


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When oil and gas sites are discovered to becontaminated with well-known toxins such aspolychlorinated biphenals (PCBs) or withhydrocarbon, levels of remediation aredetermined based on assumptions about thepotential to reach groundwater sources, thepotential for damage to environmentallysensitive areas, and the future use of the land. Uses such as residences, education, andrecreation dictate a higher level of remediationdue to higher potential exposure of humans tohealth risks. Certain jurisdictions requirecleanup levels that are protective ofenvironmental resources in addition to beingprotective of human health.

Table 2 shows the different types ofcontaminants and the potential hazards ofhydrocarbon compounds associated with crudeoil, drilling muds, solvents and metals. Thepotential paths of exposure include inhalation(of fugitive dust or vapors emitted from soilsand waters), ingestion (of groundwater, surfacewater, and soils; or of produce, fruits, poultry,and livestock raised in area; or of seafoodharvested nearshore if contaminants runoff intoocean; or from infant exposure through breastmilk), and dermal contact with soil or water.

Crude oil contains hydrocarbon compoundswhich can be divided into four major structuralforms: (1) alkanes, more commonly calledparaffins, (2) cycloalkanes, more commonlycalled naphthenes or cycloparaffins, (3)alkenes, more commonly called olefins, and (4)arenes, more commonly called aromatics. Soluble and potentially toxic constituents ofcrude oil are usually limited to benzene,toluene, ethylbenzene, and xylenes (BTEX)along with certain types of polynuclear aromatichydrocarbons. Aromatics contain BTEX. Monoaromatics (single 6-member carbon ringwith three double bonds) are very water solublecompared to their alkane and alkenecounterparts, and move easily intogroundwater; in comparison, polynucleararomatics (multiple 6-member carbon rings withthree double bonds) range from moderatelywater soluble to relatively insoluble. Moreover,crude oil found in contaminated soils may havealready degraded through evaporation, dilutionwith surface or groundwater, and chemical andbiological oxidation (although generallyaromatics will take longer to biodegrade).

Remediation Methods

Recently, there have been positive results inremediating sites contaminated with crude oilby methods other than the typical treatmentmethods of excavation and disposal offsite. Asan example, there is much promise in newapplications of specially bred microbes to safelyand effectively bioremediate hydrocarboncontamination. Bioremediation occurs naturallyin soils, whereupon carbon-bearing moleculessuch as hydrocarbons from petroleum providea source of nutrients to microflora. The micro-organisms create a biofilm around thehydrocarbon molecule and digest it, ordecompose it into simpler compounds ofcarbon and oxygen. Bioremediation can beaccomplished in situ, which is the leastexpensive method when conditions are optimal,or ex situ (land farming and biopiles) whichrequires excavation and transport of thecontaminated soils (ex situ can occur onsite oroffsite).

Limiting factors to bioremediation appear to besoil and weather conditions as well as theacreage of contamination that can be effectivelyremediated. On the positive side,bioremediation appears to work, at least insome cases, on contaminated soils under andaround operating equipment and tanks. Consequently, some bioremediation may occurin advance of full decommissioning activities. Basic issues with various potential methodsrevolve around the adequacy for cleanup level,timing, environmental impact, and cost of onemethod versus another. Options should beconsidered and their feasibility should beanalyzed during the planning of decommis-sioning. Table 3 provides with a description ofsome of the most common methods of soil andgroundwater remediation.

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Table 22

Potential Hazards of HydrocarbonsHAZARDS IDENTIFICATION

CATEGORY SUBCATEGORY HAZARD

ALIPHATICSn-hexane Peripheral neuropathy in humans

branched chainedalkanes

Hydrocarbon neuropathy in male rats only

AROMATICSbenzene Group A carcinogen - leukemia in humans

toluene Solvent neurotoxicity; Prop 65 reproductive toxicantxylene Solvent neurotoxicityethylbenzene Solvent neurotoxicity

METALSbarium Relatively non-toxic as sulfate; soluble salts are toxic

lead Impairs neurodevelopment (Prop 65 listed); B2 carcinogencadmiun Group A inhalant carcinogenchromiun Group A carcinogen by inhalation; B2 oralnickel Some exposures (by inhalation) are carcinogenic

POLYCYCLICAROMATIC

HYDROCARB

non-carcinogenic PAHs(naphthalene, etc)

Systemic toxicity

carcinogenic PAHs(benzoapyrine, chryzene,etc.)

Group B2 dermal, inhalant, oral carcinogen

SOLVENTS carbon tetrachloride Group B2 carcinogentetrachloroethane Group B2 carcinogentrichloroethane Group D carcinogentrychloroehylene Group B2 carcinogenmethlylene chloride Group B2 carcinogenMainly liver tumors and hepatotoxicity

EPA Carcinogen Classification:Group A: Human CarcinogenGroup B: Probable Human CarcinogenGroup C: Possible Human CarcinogenGroup D: Not ClassifiableGroup E: Negative Evidence

2USEPA. 1989. United States Environmental Protection Agency. Health Effects Assessments SummaryTables and Users Guide. USEPA Office of Emergency and Remedial Response, USEPA, Washington, D.C.


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Table 33

Remediation TechniquesTECHNIQUE DESCRIPTION

Physical Barrier -Membrane Barriersand Sheetpile

A synthetic membrane barrier such as High Density Polyethilene (HDPE) walls canbe used as a short term measure to contain the lateral movement of separate-phase contaminants that float on the water table. Ground water does not penetratethe membrane barrier, but it does continue to flow under and around the barrier. Aground water extraction system may be installed on the upgradient side of thebarrier to reduce hydraulic pressures and improve hydraulic control. The HDPEmaterial is resistant to penetration by plant roots and burrowing animals, andinspection/maintenance related requirements should not be required.

Due to the strength of the steel piles, sheetpiling can be used to retain soils duringexcavation and minimize the disturbed area. With this process option, interlockingsteel sheets are vibrated or pounded through the soil to the required depth. Thesheetpiling retards the lateral movement of separate-phase hydrocarbon, but lessthan the synthetic membrane option. This is an alternative to installation of HDPEbarriers using excavation and trenching.

Vacuum EnhancedDrop Tube

Vacuum-enhanced drop tube recovery removes separate-phase contaminantsfrom the subsurface, which reduces chemical volume. This technique consists ofa small diameter drop tube placed at or below the liquid level in a verticalextraction well. A high vacuum would be applied to the drop tube which wouldquickly draw soil vapor through the drop tube. The vacuum also aids in oxygena-tion of the soil column above the water table (the vadose zone) which in turn aidsin the biodegradation process. Ground water and separate-phase contaminantwould also be drawn out of the well and mixed in the turbulent flow in the droptube. The vapor would be separated from the mixed liquids and each would bedisposed of using other options.

Dual Pump Recovery Dual-pump recovery provides both containment of the separate-phase contami-nant, which reduces mobility, and contaminant removal, which reduces chemicalvolume. This technique involves installing vertical extraction wells and pumpingground water with a submersible pump set at the bottom of the well and pumpingseparate-phase contaminants with a skimming pump set at the top of the liquid inthe well. The extracted ground water and the separate-phase contaminant wouldbe handled using other techniques. Wells should be installed along the down-stream edge of the separate phase plumes with overlapping “cones of depression”to ensure that separate-phase contaminant would be captured along the entireedge of the plume.

Excavation This technique consists of removing separate-phase contaminant from selectedareas using a track-mounted excavator or other conventional excavationequipment. Once excavated, separate-phase contaminants and contaminated soilneeds to be treated. It can be hauled to a bioremediation site for treatment. Cleanoverburden soil should be stockpiled and redistributed over the excavated areaafter the pit is backfilled with treated soils.

Vertical or HorizontalBiosparging

With this process, air is introduced to the subsurface below the water table topromote the growth of aerobic microorganisms which could degrade dissolved-phase contaminants. Biosparging can be accomplished continuously or in a pulsedfashion through vertical or horizontal wells. As the injected air sweeps upwardthrough the contaminant-affected ground water and soil, it may also transfervolatile compounds from a liquid to a vapor phase.

Ground WaterExtraction

This process consists of pumping dissolved-phase contaminant from ground waterextraction wells. Ground water extraction can provide both hydraulic containment,which can prevent chemical migration, and dissolved-phase contaminant removal,which can reduce chemical volume. The extracted ground water would then betreated and discharged using other technologies.

3Arthur D. Little. 1997. Guadalupe Oil Field Environmental Impact Report, Public Draft.

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Extracted Material TreatmentTECHNIQUE DESCRIPTION

Oil/Water Separation With this process option, extracted ground water with entrained separate-phasecontaminant would be pumped into a large holding tank where gravity wouldseparate the immiscible hydrocarbon from the water. Baffles and separation platesare used to prevent short-circuiting and increase separation efficiency.

Liquid-Phase CarbonAdsorption

This process would treat extracted ground water, removing dissolved-phasecontaminant from extracted ground water by pumping it through two or morevessels containing granular activated carbon (GAC) connected in series. As thewater is passed through the carbon beds, the petroleum hydrocarbons wouldbecome adsorbed onto the GAC. After the GAC becomes saturated withhydrocarbons, it would be replaced with fresh GAC. The used GAC would betransported to an off-site facility for regeneration. This technology is proposed as aprocess to treat extracted dissolved-phase ground water or water taken from aseparate-phase treatment technology.

Recycling With this process option, recovered hydrocarbon would be transported to A nearbyRefinery and reprocessed into other products.

Deep Well Injection Under this disposal option, untreated or partially treated water generated byremediation activities would be pumped down unused oil wells into the oil-bearingformation thousands of feet underground. Liquids generated by pumping in thebeach area and by various pilot tests have been injected under permit as Class Ifluids in this manner.

LandfarmBioremediation

Landfarm bioremediation utilizes naturally occurring micro-organisms for thedegradation of the hydrocarbons. Exposing the affected soils to the air and addingmoisture and other nutrients enhances the activity of the microorganism, resultingin increased rates of hydrocarbon degradation. During operations, soil will beperiodically wetted down with water pumped from existing on-site wells to maintainan optimum moisture content for biodegradation. Nutrients may also be sprayedover the excavated soil, or nutrients could be introduced by tilling the affected soilwith compost and other amendments. On a periodic basis, (e.g., every few weeks)soil should be tilled or disked with conventional earthworking equipment.

Air-Phase CarbonAdsorption

This process would treat extracted air from the vacuum drop tube systems,removing contaminant from the extracted air by routing it through vesselsconnected in series and containing GAC. As the air is passed through the carbonbeds, the petroleum hydrocarbons would become adsorbed onto the GAC. Afterthe GAC becomes saturated with hydrocarbons, it would be replaced with freshGAC. The used GAC would be transported to an off-site facility for regeneration.

Restoration

Restoration and recontouring is defined as theprocess by which the land is returned to its originalstate. General procedures for restoration includeminor recontouring and grading, includingbackfilling and ground leveling; preparing topsoil;drainage control; and installing slope stabilizationmeasures, and other erosion control and soilstabilization measures as needed.Recontouring and regrading may be necessary inareas where large pieces of equipment orfoundations are excavated and removed. Ingeneral, sites should be returned to more naturalcontours depending on the subsequent land use. Backfilling and soil importation may be necessaryin some areas, specially where facilities areexcavated or where remediation measuresrequire transport of soils offsite. Imported topsoil

must be fertile, friable topsoil of character andtexture similar to the project site soil. In addition,the soil should be without a mixture of subsoilmaterials, obtained from a well drained arablesite, reasonably free from clays, lumps, coarsesands, stones, plants, and other foreign materials.Finish grading should include provision of positivesurface drainage of planted areas. Existingdrainage flowlines should be utilized as much aspossible. Erosion control measures include strawbails, silt fences, jute netting, water bars, diversionchannels, etc., and should be used as neededdepending on the site topography and finalcontours.

Revegetation

Revegetation is the replanting and re-establishment, where appropriate, of native


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species previously removed during theconstruction of the facility or known to exist in thesurrounding area of the facility to bedecommissioned. Revegetation of adecommissioned site requires a number of stepsthat include site and seedbed preparation,seeding, mulching, fencing and irrigating.Site preparation includes breaking up compactedsoils by disking or other methods, and mixingimported soils with the existing material. Chiselingalso restores soil permeability. Mulching withfinely chipped vegetation or straw may be needed to improve the seedbed.Only species and species varieties adaptable tolocal soil and climatic conditions should be usedfor seeding. Seeding techniques may includebroadcasting, drilling, hydromulching or otherappropriate techniques or combinations thereof. Fertilizers and soil amendments should be usedas needed, to optimize revegetation success. Seeding should occur at a time of the year whenseeds are most likely to receive moisture andgerminate, generally in late fall. Mulches are applied to seedbeds to retard soilerosion, moderate surface temperatures, retainmoisture and provide shade for seedlings. Mulches are recommended for steep slopes andon rocky, shallow soils or exposed windy slopes. One of the most effective and universally availablemulches is grain straw.Trees and other planted vegetation may requireirrigation after planting and then periodicallythereafter to ensure revegetative success. Insome areas fencing may be necessary to keeplivestock from trampling new seedlings orpredators from eating the seeds.Inspection and monitoring of the revegetationeffort should be conducted by a landscapecontractor or revegetation expert to ensure thatthe prescribed maintenance procedures are beingcarried out and to determine that the revegetationis effective. Additional maintenance activities mayinclude herbicide treatments and reseeding wherenecessary.

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ENVIRONMENTAL SESSION

Environmental and Socio-Economic Effects Occurring During theDecommissioning and Removal Process and Measures forMitigating Impacts

Air Quality, Peter Cantle ....................................................................... 93

Platform Decommissioning: Commercial and RecreationalFisheries Effects, Dr. Craig Fusaro................................................ 95

The Commercial Fishing Industry in South/CentralCalifornia, Dr. Craig Fusaro and John Richards ............................ 97

Fisheries Impacts of Explosives Used in Platform Salvage,Dr. Ann Scarborough Bull .............................................................. 104

Effects of Decommissioning Activities on Marine Benthos,Ray deWit....................................................................................... 105

Environmental Session

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AIR QUALITY

PETER CANTLESanta Barbara County Air Pollution Control District

AIR QUALITY AND FACILITYABANDONMENT

Air Quality Impacts and Issues• Decommissioning and abandonmentPossible abandonment scenarios• Full removal, onshore disposal• Complete (or nearly so) abandonment in

placeAbandonment process overview• Apply past experience to future projects• Scope of project – size and equipment array• Timing and scheduling of project• Regulatory setting• Minimize air quality impacts considering

other issuesConclusions and Summary

AIR QUALITY ISSUES AND IMPACTS

These are Interesting Times!

Santa Barbara, Ventura Counties –100+ years of oil development• 1980’s – massive OCS development,

planning, environmental assessment,mitigation

Challenge of past: develop andextractChallenge of future: remove andminimize impacts, cost

POSSIBLE ABANDONMENTSCENARIOS

Many combinations, including …• Full Onshore / Full Offshore• Full Onshore / Partial Offshore• Full Onshore / Non-Removal OffshoreEach has different air quality (andother) impacts

ABANDONMENT PROCESS ANDEQUIPMENT

Surveying (occurs throughoutproject)Vessels: Side-scan sonar, marinemammalsTopsides preparation, removal• Cutting, welding, derrick and cargo barges• Workboats, tugs, support vesselsJacket preparation, cutting andremoval• Cleaning equipment, cutting, welding, diving

support• Derricks, hoisting equipment, cargo barges,

workboats, tugsTransport• Tugs, workboats• Derrick barge, cargo barges

ABANDONMENT EQUIPMENT

Onshore…Processes vary according to facility

• Battles Gas Plant

Equipment required includes:• Cranes, hoisting equipment, welding,

cutting• Haul trucks, dozers, scrapers, graders,

backhoes• Contaminated site clean-up equipment

WILD CARD – SCOPE of Project


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AIR QUALITY AND RELATED ISSUES

Scope• Deep water, massive structures• Major equipment, major emissions

anticipated• Time required to complete abandonment

(whatever project is approved)Project Timing• Size and weather may dictate longer

schedule• Ozone season in Santa Barbara (May –

October)• Gray Whale migration (November – June)• Potentially two or more years neededStaging of Project• Scope may require “shuttling” of materials• Staging areas (e.g., Coho Bay)• Repetitious, high-emissions work• Additional loading, unloadingInteragency Coordination• Many agencies, entities involved• Jurisdictional concerns and questions likely

SafetyMarine mammalsAir quality

• Minimize air quality impacts in concert withother issue areas

AIR QUALITY REGULATORYSETTING

Permits required for abandonment,removalNew Source Review triggeredBest Available Control Technologyrequired• Reduce project emissions• Typical engine controls

Timing retard

TurbochargingIntercooling

• SafetyOffsets – state law prohibits offsetsfor abandonmentState Portable EquipmentRegistration Program• Applies to onshore portable equipment• May apply offshore eventuallyChevron / APCD agreement• Shutdown credits to offset abandonment

emissions only• Go to “Clean Air Benefit” afterward• Credits not banked for future use

CONCLUSIONS

“Continuum” of available optionsAir quality impacts are greater with…• Longer projects• Projects that occur in “ozone season”• Larger equipment array• More, and more frequent heavy lifts• Positioning, shuttling, cycling of equipmentAir quality impacts are lessenedwith…• Shorter duration projects• Projects that effectively avoid ozone season• Less equipment and fewer operating hours• Fewer heavy lifts• Less positioning, shuttling, cycling of

equipment

CONCLUSION

Best air quality option• Topsides removal• Partial removal of jacket• Abandon the rest in place


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PLATFORM DECOMMISSIONING:COMMERCIAL AND RECREATIONAL FISHERIES EFFECTS

DR. CRAIG FUSARODirector, Joint Oil Fisheries Liaison Office

COMMERCIAL FISHERIES

• Trap for crab, lobster, shrimp• Trawl for halibut, shrimp, cucumbers, sole,

rockcod• Drift gillnet for swordfish, shark, seabass• Purse seine for squid, sardines• Hook and line for rockcod• Troll for salmon

RECREATIONAL FISHERIES

• Commercial Sportfishing Charters for kelpbass, rockcod, seabass, halibut, bonito,barracuda, salmon, shark, warmwaterexotics, etc.

• Private sport fishing boat fleet, similar targetspecies

• Commercial Diveboat Charters for lobster,spearfishing or nonconsumptive uses

• Private sport dive boat fleet, similarpurposes

OPTION 1: FULL PLATFORMREMOVAL

• Areal preclusion –1

• Gear damage –• Debris – or +• Vessel traffic –• Potential fish dispersal (noise) – or +

1- and + refer to the negative or positive impactsof the activity on fishers.

OPTION 2: NON-REMOVAL,ALTERNATE USE

• No removal operations = no effects

OPTION 3: PARTIAL JACKETREMOVAL, ARTIFICIAL REEF

• Areal preclusion –• Gear damage –• Debris – or +• Vessel traffic –• Potential fish dispersal (noise) – or +

OPTION 4: MOVE JACKET TOARTIFICIAL REEF SITE

• Areal preclusion, two sites –• Gear damage –• Debris – or +• Vessel traffic –• Potential fish dispersal (noise) – or +

OPTION 5: DEEPWATER DISPOSALOF JACKET

• Areal preclusion,possible two sites –



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OPTION 6: FULL PIPELINEREMOVAL

• Areal preclusion alongpipeline route –


OPTION 7: PARTIAL PIPELINEREMOVAL

• Areal preclusion, part ofpipeline route –


OPTION 8: ONSHORE FACILITYREMOVAL & RESTORATION

• Not directly relevant to commercial orrecreational fisheries

SUMMARY OF POTENTIAL EFFECTS

• Areal preclusion –• Gear damage –• Debris – or +• Vessel traffic –• Potential fish dispersal (noise) – or +

OIL INDUSTRY / COMMERCIALFISHERIES PROGRAMS FORPOTENTIAL IMPACTS

• Debris: Site clearance work following allremoval operations

• Gear Damage: Agreements to reimburse fordamaged/lost gear

• Vessel Traffic: Oil Industry Service VesselTraffic Corridor Program

OUTSTANDING ISSUES

• Areal preclusion during decommissioningoperations

• Debris missed by site clearance procedures• Vessel traffic to and from areas not covered

by agreed-upon traffic corridors


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THE COMMERCIAL FISHING INDUSTRY INSOUTH/CENTRAL CALIFORNIA

DR. CRAIG FUSARODirector, Joint Oil Fisheries Liaison Office

andJOHN RICHARDS

Sea Grant Extension Program

INTRODUCTION

This section describes various commercialfishing activities currently operating along thesouth/central coast of California. This regionroughly corresponds to Region II of the federaland California state geophysical permitprograms. This region also corresponds with anarea of high interest to the oil and geophysicalindustries.

Information presented here covers fishingseasons and areas for a number of activefishery types in the area, as well as descriptionsof commercial fishing techniques, gear, andvessels to be found here. In addition, keyfishing industry, government, and local contactinformation is provided to facilitate thedissemination of the information regardinggeophysical programs. These contacts canoften provide further and/or more recentinformation on commercial fishing activities.

Commercial fishing in the south/central region ofCalifornia, ranging from the port of Morro Bay inSan Luis Obispo County to Port Hueneme inVentura County, is unique in at least two ways.First, the number and types of fishing gear usedand species caught is quite varied, and over 20species are harvested commercially. Second,much of the fish caught in the Santa BarbaraChannel and Santa Maria Basin fishing groundsis marketed primarily as fresh fish to marketsand restaurants, rather than reduced or frozenfor sales to large distribution networks. Somefisheries are dependent on highly migratory orunpredictable stocks, and therefore may changeradically in size from one year to the next.

Other sources for information on current fishingactivity in any given area are (in no particularorder) the Unit Managers of the California

Department of Fish and Game (Morro Bay andSanta Barbara Regional Units), the SantaBarbara Sea Grant Marine Advisory Office, andthe Joint Oil/Fisheries Liaison Office. Theseoffices will usually be aware of the most recenttrends in fisheries activities for their respectiveareas.

This paper presents information on fishingseasons, and then provides aid to geophysicalsurvey vessel operators on how to recognizefishing gear types from visible signs of fishinggear on the surface of the water. Each fishery isthen discussed in turn, providing a briefdescription of fishing techniques, gear, andvessels. All information on a particular fishery isgrouped together in this way for convenientreference.

THE CRAB FISHERY

The commercial crab fishery in south/centralCalifornia seeks two different groups of crabsThe largest crab fishery is for what is commonlycalled ‘rock crab,’ a composite of three speciesred rock crab. yellow crab, and brown crab. Thered rock crab is caught primarily around or onsubmerged rocky outcrop areas. The othertypes are caught in areas of low relief sand orsandy mud bottom. This fishery is active allyear, and many of the fishermen who fish crabgear also fish lobster gear in lobster season(October-March).

Traps are basically wire, plastic coated wire. orplastic mesh boxes 2, 3, or 4 feet square whichare weighted to stay in place on the seafloor(Figure 1 ). Braided polypropylene rope (usually3/8 inch diameter) is used to deploy and retrievetraps, which are set in nearshore waters fromshore to 40 or 50 fathoms deep.


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Figure 1. Crab and Lobster Traps, as deployed.

Crab traps (pots) are baited and deployed infishing grounds The pots are commonly left tofish ('soaking') for about 3 days, and are thenretrieved. The crab fishing vessel pullsalongside the pot buoy(s), grapples the buoy ondeck, feeds the line through a 'pinch-puller'winch of some kind, and raises the pot from theseafloor. The crabs are taken from the pot, it isrebaited, and redeployed. Normal fishingpractice dictates the movements of traplocations: if the traps are fishing well, they areleft where they are. If the traps are not catchingmuch, they will usually be moved to try a newlocation. In practice this means that groups, or'strings' of gear will be moving from one locationto another on an unpredictable time scheduledictated by crab population movements. It istherefore difficult to predict the location of anyparticular string of gear at a given time. Mostfull-time crab fishermen have at least 50-70pots, and many crab fishermen have upwards ofseveral hundred pots arranged in 'strings' offrom 5-25 individual traps set along particulardepth contours.

The vessels used in the commercial rock crabfishery are most often smaller than their Alaskancounterparts, ranging from about 20 to 40 feet inlength (Figure 2 ). Most often these smaller,faster boats are equipped with a small davit andwinch, or crab pot-puller of some kind to haul inthe gear from depth. Since these vessels aresmaller, and since many crab fishermen have

upwards of several hundred pots, this meansthat pots are deployed over several trips to getfull operational capacity (one such vessel mayonly safely carry 10 to 30 pots at a time), andrelocating gear must also be done in incrementsallowed by deck space.

Figure 2. Crab or Lobster Vessel, Fore Deck.

The second crab fishery is a southern extensionof a larger, northern California to Alaska fisheryfor Dungeness crab. Both the trap and buoysystems are somewhat different for this fishery,and the Dungeness crab fishery is highlyvariable in this area, depending on signs ofstock early in the season. This fishery extendsfrom northern California south through the SantaMaria Basin to Point Arguello in some years.Dungeness crab vessels tend to be larger (25-75 feet) than those fishing rock crab south ofPoint Conception.

From a practical standpoint in locating andassessing the deployment pattern of a string ofpots, it is important to consider the effects of tideand current strength on the line and buoy, andwindage on the buoy, in determining the actuallocation of the gear. During conditions of hightide, strong currents or high winds, buoys maybe below sea surface and therefore not visibleuntil conditions slacken. Rough seas may alsomake spotting buoys more difficult.

Most of the crab, rock or Dungeness, aremarketed locally (within a 300 mile radius of theRegion) to fresh fish wholesalers. markets, orrestaurants, and marketing crab is highlycompetitive. If a particular crab fishermancannot assure his market of a steady supply,he/she is not likely to continue to be able to sellto that market, since the market can seekproduct from other more steady producers ofcrab. Minimizing interactions with crab


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fishermen and their gear therefore minimizes thepotential for altering an individual's position inthis highly competitive market.

THE LOBSTER FISHERY

The lobster fishery is quite similar to the crabfishery. The pots used are of a similar size, withsimilar buoys marking their location, and arefished by similar size vessels. In fact, most crabfishermen also fish lobster, changing over someof their crab gear to lobster gear, or addingstrings of lobster gear to their deployed crabgear in nearshore waters. Some fishermentarget only on lobster and do not fish crab, thusadding to the total number of vessels, and potgear, in nearshore waters during the season.One of the main differences between crab andlobster fishing is that lobster fishing is confinedto a specific season; fall through winter.Opening day of lobster is the first Wednesday inOctober, and the season closes on the firstWednesday after the 15th of March. Anotherdifference in lobster gear deployment patterns isthat in addition to arranging pots along depthcontours in ‘strings,’ lobster pots are alsogrouped in clusters which fringe rocky outcropson the seafloor, since the lobster maysometimes be found in association with theseoutcrops.

Typically at the beginning of the season there isa certain amount of 'jockeying' for desirablepositions along the coastline among lobsterfishermen, as they establish their positionsrelative to one another along the coast and atthe Channel Islands early in the season. TheDepartment of Fish & Game allows fishermen toset out their gear a few days before the seasonactually starts, provided they are unbaited, withthe doors open. It is therefore most usual to seea rapid buildup of large numbers of lobster potsin nearshore areas quickly in early October.

At the beginning of the season, most pots areset in shallow water, hugging the shoreline. Asthe season progresses, the gear is likely to befound further and further from shore, asfishermen follow the movements of the lobsterpopulation offshore into deeper water throughoutthe season. Toward the end of the season(March), it would not be unusual to find most ofthe gear in the 20-40 fathom range.

The gear is fished in exactly the same manneras crab pots: the fishing vessel pulls alongsidethe surface buoy, grapples it aboard, runs theline through a pinch-pulley of some kind, andhydraulically lifts the pot from the seafloor.Lobster are removed, the pot is rebaited, andredeployed. The pot is put in the same place itwas taken from if it fished well, or moved toanother location if it did not fish well.

The lobster catch is also marketed on a localbasis, most of it going to wholesale or retailfresh markets or restaurants within a 300 mileradius of this region.

THE GILLNET FISHERY

Two types of gillnets are in common use in theSanta Barbara Channel and Santa Maria Basinand they are very distinct in the way they arefished. The first type is the set gillnet, which isset in place with anchors on the seafloor and leftunattended to fish ("soaking") for a period of 24hours or so. The second is the drift gillnet,which is a floating net with a lighted buoy at oneend, attached to the fishing vessel at the otherend (Figure 4 ). Each of these types of gillnetswill be considered separately.

Set Gillnets

Since 1994, set gill nets have been banned foruse within State waters, except in certain areaswhere deepwater rockfish nets are now beingset. The species sought by these set nets arehalibut, seabass, angel shark, other sharks,rockfish, queenfish and kingfish.

A set gillnet is attached to an anchor-and-buoyline at both ends (Figure 3 ). Commonly, gillnetbuoys have flags marking the ends, for ease ofvisibility. Set gillnets range in length from ahundred yards to a half mile or so in length,depending on how may 'gangs' or pieces of netwebbing are hung together between anchorlines. The net is set at some time of day, ornight, and usually retrieved within 24 hours.Fish are taken from the net as it is pulledaboard, or worked over the deck and redeployedin place, depending on whether the net is to berelocated or not. As in the crab and lobsterfishery, the decision to relocate gear is based onthe catch rate of the net in the current location.Nets may be arranged so the net material itself


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is close to the surface, at midwater, or near thebottom.

Figure 3. Set gillnet, deployed.

Drift Gillnets

This type of gillnet is not left unattended, andmost often, one end of the drift net is attached tothe fishing vessel. The drift net fishery operatesin a much different area of the Santa BarbaraChannel and Santa Maria Basin regions than theset net fishery does. Fish species sought in thisfishery are swordfish and thresher shark, butsome incidental catch of other pelagic specieslike opah is also now common since a strongmarket is developing for such species.

Figure 4. Drift Gillnet – Structure of Gear.

Drift nets are often much longer than set gillnets,and may be as long as a mile or mile and a half(Figure 4 ). This is significant from a gearinteraction viewpoint because drift gillnet vessels

may have restricted ability to maneuver similarto geophysical survey vessels with a 1-2 milelong cable out. The end of the net not attachedto the fishing vessel usually has a radarreflector/lighted buoy attached to it, but may notbe immediately obvious because it is so far fromthe vessel. Since drift gillnetting is usually doneat night, and often during the darker phases ofthe moon, this compounds the necessity to beaware of the configuration of drift gillnetoperations. Normally the vessel will be at theleeward end of the drifting net equipment. A driftgillnet can be fished anywhere from right at thesurface to 30 or 40 feet below the surface.

The vessels used in both the set and drift gillnetfisheries vary in size and shape, but might beclassified into two categories: 1) smaller (28-40feet), faster craft similar to the crab and lobstervessels commonly in use in the region, and 2)larger (40-60 feet), more traditional fishing hulls.In either of these cases, the gillnet boat isreadily distinguishable from other vessels ofsimilar design and size by the presence of alarge (4 to 10 feet) reel on which the gillnet isspooled when not in use (Figure 5 ). This reelmay be mounted on a fore deck, or aft deck.

Figure 5. Vessel- Gillnet.

THE HOOK AND LINE FISHERY

This fishery primarily targets several species ofrockfish, such as the red (vermilion), bocaccio,chili, and several others; incidental catchincludes rocky reef associated fish such aslingcod and cabezon. The fishery has noseasonal restrictions, but is most active duringthe fall and winter months. This fishery as itexists in the Santa Barbara Channel and SantaMaria Basin is a "fallback" fishery for some of


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the fishermen who enter it, since many of thesefishermen also fish in other fisheries during othertimes of the year. Some boats however, operatehook & line gear as their primary and onlyfishery. As such, a variety of vessel types andsizes are involved in the fishery, ranging in sizefrom weekend skiffs with rod and reel to largercommercial vessels from other fleet types, usingbuoyed, vertical longline techniques.

Most often, hook and line fishermen use theirfathometers to seek out relatively deep waterrocky outcrops having "stacks" of fish showingover them. A buoyed vertical longline withgroups, or "gangions" of baited hooks on them isplaced in the water where they find these“stacks” of fish (Figure 6 ). The lines are thenretrieved, any fish hooked are removed, thehooks rebaited, and the process is repeated.Since it is not always possible to tell exactlywhere the gear is deployed near the boat, a 1/4mile clearance around working hook and linevessels is advisable.

Figure 6. Hook and Line Gear, Deployed.

THE TRAWL FISHERY

The trawl fishery, in distinct contrast to the crab,lobster, and set gillnet fisheries, is a mobilefishery in which a trawl net or double net rig istowed behind the fishing vessel at slow speed,either in midwater, or, more commonly in thisregion, along the bottom, giving the name"dragboat" to the trawl fishing vessels here(Figure 7 ). Most of the vessels are large forcommercial fishing vessels of this area, ranging

from 40 to 80 feet in length. These vessels arereadily identifiable when the net is not deployedbecause of the net 'otter boards' or 'doors' whichare usually hung near the stern of the vessel,and the single boom and winch for net retrievalusually mounted forward on the open sterndeck. Some draggers use a Gulf-style doublenet rig (twin trawlers) which is towed from theends of two heavy outrigger poles readily visibleextending laterally 20-30 feet from the beam ofthe boat. The species sought by trawlers or'draggers' are ridgeback shrimp, spot prawns,pink shrimp, rockfish, various species of sole,and sea cucumbers. Seasonally, the trawlersare allowed to drag in shallower state waters forhalibut, and incidental catch of shark and someother fish is also allowed.

Figure 7. Trawl.

The trawler deploys the net in areas in whichfish are noted on the fathometer, or wheretrawling has been successful before. Dependingon the species sought, and season, this can beanywhere from the 50 to 150 fathom depthcontour along the coastline, along the ChannelIslands, and along topographic features of theseafloor in midchannel at appropriate depths. Inthe Santa Maria Basin, draggers may work outin waters as deep as 400 fathoms in their searchfor various species of sole. The net is slowlylowered to the bottom (or midwater), held openby two large 'otter boards' or doors attached tothe leading edge of the net funnel. The vesselthen navigates along a depth contour at a slowpace (a few knots) through the dragging groundsfor several hours. The net is then picked up offthe bottom and retrieved on deck with ahydraulic winch and boom. The fish are emptiedfrom the cod (trailing) end of the net, sorted, andthe process is repeated.

Trawlers are not readily maneuverable when thenet is deployed for several reasons. First, thenet is on the bottom in relatively deep water, and


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can be up to a mile behind the vessel. Second,the trawlers often work on the top edges ofsteep drop-off slopes; to turn into deeper waterwould force the net to drop off these slopes.This causes loss of fishing time since the nethas to be picked up and reset. Similarly, rockyoutcrops, wrecks, and abandoned wellheads orother debris are located randomly with respectto the trawl grounds. These features arehazards to the dragger because of their potentialto snag and hang up the net. Most of thetrawlers are aware of most of the snags to avoidin their favored grounds, by trial and error.Knowledge of these snags also limits thepotential maneuverability of the dragger whentowing a net, because to turn in to such a snagmay mean loss or damage to the net, andpotential hazard to the vessel itself if the hang issignificant and/or weather sea conditions areunfavorable- Since turning into suchobstructions would be hazardous, most draggerswould have to stop towing and pull gear in ratherthan turn.

THE PURSE SEINE FISHERY

This fleet is based primarily in ports to the southof Santa Barbara; mainly in Ventura Harbor andSan Pedro (Los Angeles Harbor). The speciesfished are primarily pelagic, such as anchovy,mackerel, and bonito. A major squid fishery hasalso developed in the past few years. Becausepurse seiners follow schools of these pelagicfish, it is difficult to predict where the fleet will beat a given time. Though the season is open allyear, the Department of Fish & Game sets catchquotas. When these are filled, the fishery isover for that year unless an extended quota issubsequently issued.

The vessels, in the 35 to 70 foot size range, aredistinguishable by the extra pursing skiff usuallycarried astern, and the tall boom and winch forpursing and hauling in the purse seine itself(Figure 8 ). A much larger "power block" willnormally be at the top of a purse seiner boomthan the block seen atop a trawler boom. Whena school of anchovy, bonito, or mackerel isspotted, the vessel maneuvers into position nearthe school and launches the skiff, which dragsthe net around the school of fish and back to themother vessel. The purse line of the net israpidly winched in to close the bottom of the net(forming a "purse") to prevent the school of fish

from escaping downward (Figure 9 ). The entirenet is then brought in with a power block andwinch. A successful set and haul usually takesfrom 30 to 90 minutes, depending on the size ofthe fish school, weather, and other factors.During the pursing process, the purse seinevessel is not maneuverable and can beconsidered effectively dead in the water. Itshould therefore be given the appropriateclearance due a vessel in such circumstances.

Figure 8. Vessel – Purse Seine.

THE DIVE FISHERIES

Commercial divers in the Santa BarbaraChannel primarily seek sea urchins, although asmall dive fishery has recently developed for seacucumbers. Divers usually work rocky reefareas in waters no deeper than 20 fathoms,since the two primary species sought aredistributed in that depth range. Historically thecoast was dived extensively for abalone andurchins, but the primary grounds for sea urchinsis now around all of the Channel Islands. Someurchin divers still do work the coastline, but themajority of the dive fishery grounds are currentlyat the islands.

Figure 9. Purse Seine.

Commercial dive boats are usually small, fastvessels from 22 to 32 feet in length. Normaloperations can be either anchored or "live-boat".One to several divers may be in the water. A'tender' or deck hand on deck operates thevessel and diver air compressor, and tends thedivers air hose and game bags. These dive


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vessels are clearly marked with Department ofFish & Game identification numbers. The prefix"SU" indicates a sea urchin permit.

Typically the diver will work a "bed" of urchinsuntil his bottom time is exhausted or the bed isfished of all legal size urchins. Then the diverwill decompress if necessary, surface and spenda period of time on deck, or move to anotherlocation. Clearance of at least l/4 mile of a divevessel in operation is advisable, because a divercan be in any direction relative to the divevessel.

MARICULTURE AND RESEARCHOPERATIONS

Along the coast of the Santa Barbara Channelnear Santa Barbara, at least nine differentmariculture leases are scattered within the threemile limit (state waters). Each of theseoperations has a slightly different purpose, suchas the commercial growing of kelps, harvestingedible mussels, growing oysters, or abalone,and/or a number of other species. The onething all of these leases have in common is afixed marker buoy, or several fixed, permanentbuoys or rafts which locate the lease for theoperator and the permitting authority (theDepartment of Fish & Game). Likewise, thereare fixed buoys in place for various researchinstitutions throughout the west coast, gatheringinformation on the oceanography or ecology ofthe Santa Barbara Channel.

THE TROLL FISHERY

Trolling for salmon, albacore, and occasionallybonito is done primarily in the Santa MariaBasin, and to a lesser event in the SantaBarbara Channel, depending on where thesefish are from year to year. A troller is most oftena relatively small vessel (from 20 to 40 feet long)equipped with at least two laterally deployedbooms or arms of some kind to which areattached several trolling lines (Figure 10 ). Abaited hook and flasher (or several hooks) isattached to the end of the trolling line, and aweight is attached ahead of the hook andflasher. Multiple sets of this gear trail 100 to 300feet behind the active troll vessel. The troll linesare tended regularly to remove hooked fish fromlines and the lines are reset. Trollers work inhighly variable areas, since this fleet targetshighly migratory and widely ranging fish. As in

the hook and line fishery, trollers often are inanother fishery, and enter the troll fishery in theoff-season of their principal fishery.

Figure 10. Troll.


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FISHERIES IMPACTS OF EXPLOSIVES USED IN PLATFORMSALVAGE

DR. ANN SCARBOROUGH BULLMarine Biologist, Minerals Management Service, Gulf of Mexico OCS Region

VILLERE REGGIO, PresenterBiologist, Minerals Management Service, Gulf of Mexico OCS Region

There are upwards of 5000 oil and gasstructures in the Federal and State waters of theGulf of Mexico. A recent average showed morethan 100 removals occur each year. Sixty-sixpercent of these structures are removed withexplosives. Typically, the deck of the offshoreplatform is cut manually with torches and liftedonto a materials barge. Explosives are lowereddown the hollow pilings and conductors to aminimum depth of 5 m (15 feet) below themudline as required by Minerals ManagementService. Explosives are detonated, therebysevering the pilings and conductors which, alongwith the jacket, are removed from the seabed.

One consequence of using underwaterexplosives is a negative impact on marine life atthe platform, particularly fish. This reportpresented preliminary results from Dr. Bull’sresearch assessing the fish mortality at sixplatform removals between August 1993 andSeptember 1995. Computed results for redsnapper reveal that less than 1% of the annualGulfwide harvest of this species is due toexplosive platform removals. Study sitesspanned the Louisiana coast from the westernborder to the Mississippi Delta. Water depthsranged from 14 to 28 m (45-92 feet).

Mr. Reggio commented on the relationship ofpetroleum platforms with the evolution ofoffshore fishing over the past 50 years.Independent research, and over 20 years ofpersonal investigations and observation, hasindicated offshore petroleum structures havehad a profound, pervasive and long-term impacton fish and fishing in the north-central andwestern Gulf of Mexico. Platform removals arenow routinely considered for reuse as artificialreef developments in water depths from 15 to106 m (50-350 feet). Through toppling,relocation, and partial removals 35 oilcompanies have cooperated with the Gulf Statesto create over 100 planned and permanentartificial reefs (Rigs to Reefs). Ongoingresearch supported by the MMS EnvironmentalStudies Program, in cooperation with publicuniversities and private contractors, is helping todefine the ecological, social, and economicconsequences of petroleum platforms on fishand fishing with special emphasis on their futureuse as dedicated artificial reefs.


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EFFECTS OF DECOMMISSIONING ACTIVITIES ON MARINE BENTHOS

LERAY A. DE WITConsultant in the Marine Environmental Sciences

Since the 1960s, when the first platforms wentinto the Santa Barbara Channel, marinescientists have been interested in thesuccession of biota on and around thosestructures. While the newer platforms are inwater depths exceeding 400 feet, the older onesare in shallower water, so the entire structurewas within the photic zone, generally defined asthe upper 200 feet of water. These structures,comprising a series of steel legs and cross-members, provide attachment substrate; a studyin the Gulf of Mexico estimated that 3-4 acres ofhard surface was added for an oil and gasplatform placed in 150 feet of water. Additional"hard substrate" is also realized on the seafloorbelow the platform where cuttings aredischarged and where the shells from attachedmollusks settle after they are dislodged from thestructure.

Before the effects of decommissioning andremoval of oil and gas structures can bediscussed, it is important to remember that theplatforms and pipelines are "artificial substrates"and the communities that develop on them are adirect result of the habitat being there.Therefore, consideration should be given to thequestion, "Is it better to leave a structure and theassociated biota in-place or return the area tothe way it was before placement?" It is not theintent or objective of this paper to answer thatquestion but to provide an overview of theorganisms associated with these structures andthe potential effects of various decommissioningand removal options on them.

Studies on the Santa Barbara Channel platformshave shown that fairly distinct "zones" ofepibiota (attached organisms) develop relativelyquickly. An upper zone (to approximately – 20feet ) normally supports substantial mussel andbarnacle growth. That fouling community hasbeen documented to be from 1 to 4 feet thick.An interesting sidelight is that mussels up to 1foot long have been observed on Santa BarbaraChannel platforms. Below that to at least the–120 foot depth, the jewel or strawberryanemone (Corynactis californica) generallydominates the attached community. Intermixed

with that anemone are soft corals, hydroids, andvarious mollusks. Few seastars are usually onplatforms above the area where anemones areabundant. The consensus is that the stingingcells in the anemone's tentacles precludeseastars from moving over them. This may alsopartially explain the abundance and relativelylarge size of the mussels above the anemoneband since seastars are the principal predator ofmussels. Detailed studies have recorded over200 species of epibiota on Santa Barbaraplatforms.

On the seafloor surrounding the platforms anequally dramatic biotic change occurs as a resultof the presence of the platforms. As statedearlier, the drill cuttings that are discharged fromthe platform and the mussel shells that areremoved during storms or due to their ownweight are deposited on the seafloor below theplatform. These "mounds" have been estimatedto be almost 40 feet deep in some areas of theChannel with shell talus comprising almost halfof that height. Studies by scientists in the 1970'sestimate that 15,000 to 30,000 feet 2 of seafloorhad been "enriched" around platforms Hilda andHazel.

Irrespective of the actual area, it is clear that anew substrate, which supports a vastly differentepibiota community than the surroundingsedimentary bottom, is created as a result of thisdeposition. Depending upon the depth ofplatform, that community consists of crabs,shrimp, seastars, sea cucumbers, anemones,and other organisms not usually found in thenatural habitat. One study of platform Eva offHuntington Beach in the 1970's found that36,850 pounds of seastars, comprising 19,000individuals of at least four species, were within a7,000 feet2 area under the platform. Anadditional 5,000 sea cucumbers (2,400 pounds)were also documented within the same talusbed. Needless to say, the shell substrate andabundant organic material provides a goodhabitat for certain benthic organisms, some ofwhich are of commercial interest.


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The exposed portions of pipelines also providesolid substrate, albeit not the area provided byplatforms, within the generally sedimentaryseafloor of the Channel. While much of thedeeper water pipelines bury themselves into thesoft sediments, nearshore sediments are morecompact and thus support the pipelines, allowingepibiota to attach to the exposed surfaces. Inaddition to the pipelines themselves, armor rock,usually placed over the pipelines from –25 feetto shore, also provide substrate for epibiotaattachment. Within the nearshore areas,generally to about –60 feet ., kelp andinvertebrates similar to those found on naturalrock reefs in these water depths, attach to thepipelines and rock cover. Scallops, mussels,and species of non-commercial interest arecommonly found on the rocks.

The spaces between the armor rock alsoprovide habitat for crabs, lobster, and severalspecies of fish, some of which are also ofinterest to commercial and sport fishermen. Mypersonal observations within the Channel haverevealed aggregations of angel sharks along thepipeline oil from platform Helen to shore and Iand several other observers have documentedabundant growth on the pipelines and rock coverof other pipelines within the Channel. It isimportant to note that most pipelines are buriedthrough the intertidal zone and therefore provideno longterm attachment substrate there.However, in subtidal areas where the pipelinesand/or armor rock is exposed, biomass on thepipeline far exceeds that of the surroundingsedimentary bottom. In a study in which I wasinvolved, it was found that the epibiota biomassof the submerged portions of the rocks onRincon Island was 50 times that of the infauna inthe sedimentary habitats around the island.

Before the effects of removal can be discussed,a brief description of the effects of the marineactivities that occur prior to the actual removal isrequired. These include effects of vesselanchoring, divers, and the cutting of thestructures. While each activity is likely to befairly local in its effect on the benthos, that effectshould be including when comparing disposaloptions.

Multiple anchors are usually used by vesselsengaged in platform or pipeline removal.Anchoring does indeed result in the burial oforganisms directly below the anchors as well asthe resuspension of sediments when the anchor

contacts the seafloor and when it is removed. Inaddition, the lines or cables connecting theanchors to the vessels have been shown tosweep across the seafloor and damage thesubstrate and/or attached biota. The area ofeffect is usually limited to a triangular zone withthe apex at the anchor, widening toward thevessel. Due to wave action in the shallowerwaters, nearshore anchoring normally requiresthat anchors be set at a distance 10 times thewater depth of the vessel. Therefore, a boatworking in 25 feet of water could be expected toplace its anchors as much as 250 feet away.Deeper water areas usually require less "scope"and therefore the area of impact could beexpected to be smaller.

Diver operations, including jetting of sedimentfrom around pipelines, cutting pipelines and thesmaller cross members of the platforms, andplacing charges, can also result in impacts to thebenthic community. In my experience, I haveobserved apparent diver-related impacts toinclude some damage to kelp plants near thepipeline cut points, removal of attached epibiotaaround cut points of platform cross members toaccess the jacket, and scraping of solidsubstrate habitats with equipment. Myobservations indicate that diver-related effectsare very local and relatively insignificant.

Cutting of structures via mechanical or explosivemethods also appears to have a relatively localeffect on the benthos. The effects of cutting areusually limited to a relatively narrow bandaround the structure and if the piece is to beremoved anyway, the loss of those organismswithin the cut area is irrelevant.

No matter how much of the subsea portions ofthe structures is removed, the attached benthoswill, of course, be removed also. Even if thestructure is used to create an artificial reef, theattached community will change relative to waterdepth, available light, and suspended sedimentat the new location. The orientation of thestructure is also likely to change from upright tohorizontal, thus organisms attached to the upperportions of the platform are likely to exposed togreater water depths and decreased light.Again, depending upon the water depth, aplatform laid on its side could be expected todevelop a fouling community similar to thatfound at that water depth when it was upright,resulting in a net decrease in the number ofhabitats the structure supports but increasing


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the arial cover of the habitat(s) at those depths.Also to be considered in partial removal is thefact that the near surface areas normally supportthe largest attached biomass per unit area and itis the mussel community that provides much ofthe organic material and substrate input to thetalus bed beneath the platform. Removal of theupper portions of the structure would eliminatethis important community.

I have found that pipelines laid across hardsubstrate, tend to wear a "groove" into the rock.It is this abrasive action that likely precludesepibiota from developing within the groove. Onthe other hand, the pipelines themselves providea viable substrate and therefore it is likely thatthe removal of the pipeline should not result in anet loss of epibiota within rocky habitats. Insedimentary habitats the pipeline may providethe only solid substrate within the area andtherefore the complete removal here would beexpected to result in a net loss of organisms andbiomass, even when the recolonization of thesediment under the pipeline occurs. In thesandy intertidal zone, assuming that the pipelineis exposed only during extreme erosion events,there is no substantial habitat value associatedwith the pipeline and therefore removal shouldresult in no substantial long-term change in thebiota.

In conclusion, the following summarizes theeffects of each decommissioning / removaloption identified in the agenda of thisconference. Generally, removal of the upperportions of a platform results in the loss of themost productive area and could be expected toeliminate the source of talus formation aroundthe platform. Pipeline removal effects are mostdetrimental in areas where the exposed portionrepresents the only solid substrate and has theleast effect within the intertidal areas.

Full Removal Including Recontouringthe Seafloor

Loss of all biota and habitats that haveestablished as a result of the structure'spresence. This of course assumes onshoredisposal and scrapping of the entire structure.

Non-Removal (Alternative Use)

Assuming no changes in discharges from whathad existed, the structure-associated biota andthe epifauna on the talus mounds, could be

expected to continue to develop into acommunity that differs from the surroundingsedimentary bottom and open-water biota.

Partial Jacket Removal with ArtificialReef

Since is has been shown that the greatest perunit biomass of epibiota is that in the upperportions of the platform, the loss of that portionwould be expected to result in the reduction oftalus-supplying organisms and the loss of theorganisms associated with the portion removed.Placement of the removed structure into similarwater depths would be expected to result incontinuation of epibiota development and thepossible increase in benthos around the areawhere the structure is placed. The probability isthat no net gain or loss from current conditionswould be realized.

Remove Jacket to Artificial Reef Site

As in the partial removal option, the water depthand other conditions will dictate the developmentof the benthic community on and around thestructure once it is placed at the artificial reefsite. Highest epibiotic productivity could beexpected when the artificial reef site is within thephotic zone with some portions at or near thesurface.

Deepwater Disposal of Jacket

Deepwater has yet to be defined in the contextof platform disposal, therefore, as previouslydiscussed, the benefits or negative effects of thisoption will be driven by the depth of water andthe amount of natural solid substrate within theregion. Assuming that deeper water equates tosofter sediments, less of the structure would beexposed than in shallower areas. Enhancementof benthic productivity of the area could berealized from the presence of the platform withlosses of existing biota limited to that buriedbeneath the structure.

Full Pipeline Removal

Removal of the entire pipeline will not onlyreduce available solid substrate, but will alsoresult in impacts to the benthic community fromremoval-associated activities. Unless there is asafety issue, rock-covered pipelines should notbe removed, however, removal of thosepipelines that traverse natural rocky habitats is


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likely to result in reestablishment of biota withinthe area immediately around the pipelines.Generally, it is expected that the impacts tobenthic communities would be greater fromcomplete removal of pipelines that thoseassociated with allowing them to remain in-place.

Partial Pipeline Removal

As previously stated, consideration should begiven to the habitat through which the pipelinetraverses and the potential long-term effects ofremoval vs. remaining in-place. Exposedpipelines in offshore sedimentary habitatsshould be allowed to remain in-place.

Some general conclusions that focus on thepotential effects of various decommissioningoptions on the marine benthos of southernCalifornia are:

1) the habitats and associated biota present onand under the platforms and on pipelinesare usually unique since the surroundingarea is sedimentary;

2) removal of even part of the structures couldbe expected to alter the benthic and epibiotacommunity in the area;

3) the effects of removal-associated activities

must be considered in assessment ofimpacts of removal but are expected to berelatively local and short-term; and

4) creation of artificial reefs from the removed

structures could be expected to enhance thebenthic and epibiota communities of the reefsite but removes those communities fromthere present, offshore locations.

Removal of oil and gas structures and identifyingthe best use of the material remains acontroversial topic. The organisms that attach tothe structure or benefit from its presence willsuffer some impact with removal of any portion.Weighing the benefits and losses to the benthicand epibiota communities is only part of theoverall consideration and, I might so boldly add,a relatively minor one when compared to theother technical and cost issues that must beincluded in the equation.

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DISPOSITION SESSION

Long-term Environmental and Socio-Economic Effects Related to theDisposition of Oil and Gas Facilities

Commercial Fisheries: Long-term Effects of Offshore Oil and GasFacilities Decommissioning, John Richards................................... 111

Ecological Consequences of Alternative DecommissioningStrategies for POCS Offshore Facilities, Dr. Mark Carr,Dr. Graham Forrester and Dr. Michael McGinnis .......................... 116

Effect of Offshore Oil Platform Structures on the Distribution Patternof Commercially Important Benthic Crustaceans, with Emphasison the Rock Crab, Dr. Mark Page and Dr. Jenny Dugan............... 119

Enhancement of Platforms as Artificial Reefs, Dave Parker ................ 122

Long-term Socioeconomic Effects of Onshore FacilityDecommissioning, Dr. James Lima................................................ 124

Disposition Session

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COMMERCIAL FISHERIESLONG-TERM EFFECTS OF OFFSHORE OIL AND GAS FACILITIES

DECOMMISSIONING

JOHN RICHARDSSea Grant Extension Program, Marine Science Institute

UC Santa Barbara

INTRODUCTION

Decommissioning of offshore oil and gasfacilities and the long-term effects of variousdisposition options have both direct andindirect impacts on nearly every commercialfishing fleet operating along the south-centraland southern California coast. To gain anunderstanding of the disposition issues andconcerns of the commercial fishing industry,interviews were conducted in seven ports withforty-three vessel owner/operators, eachrepresenting an individual fishing business.The fishing fleets represented included troll,hook and line, drift and set net, purse-seine,trawl, trap, and dive. The interviews wereconducted either in person or by telephoneduring the summer of 1997 with captains fromMorro Bay, Port San Luis, Santa Barbara,Ventura Harbor, Channel Islands Harbor, PortHueneme, and San Pedro Harbor. Backgroundinformation on current fishing operations andfleet characteristics was acquired throughinterviews with six fisheries resourcemanagers and representatives of eightcommercial fishing organizations (listed inAppendix A).

THE OCEAN SETTING

The shift in the California coastline in the areaof Point Conception, Santa Barbara County,from a north-south to an east-west orientation,has a significant influence on the weather,oceanography, and diversity of marine life inthe Santa Maria Basin north of the Point andthe Santa Barbara Channel to the south-east.Fish and shellfish species favoring both coldand temperate seas inhabit this productivemarine transition zone. Further south, from theLos Angeles Bight to the Mexican border, thewaters are typically warmer and, in years of ElNiño events, there is often (depending on thestrength of the event) a rise in oceantemperatures and movement of warmer-watermarine species to the north. The changeable

nature of the ocean in this area, and thediversity of marine species have led to thedevelopment of a very dynamic and adaptablecommercial fishing fleet.

CHARACTERISTICS OF THEFISHING FLEETS AND FISHERMEN

The demand imposed on southern Californiafishermen to adapt to changing conditionsalong with the unique variety of fish in the area(over 20 commercially harvested species)have prompted many captains to utilize acombination of gear types and methods tomaintain productive fishing enterprises. Anexcellent review of the region’s fishing vessels,gear types, methods, and seasons is given inthe Joint Oil/Fisheries Committee and LiaisonOffice (1986) publication, “A manual forgeophysical operations in fishing areas ofsouth/central California”. As this publication iscurrently out of print, an abridged and updatedsegment of the publication describing thesouth coast fishing operations is reproduced inthis volume (See p. 97 Fusaro & Richards).

Southern California commercial fishing vesselowners and operators are typically smallindependent businessmen with vesselsranging from 18 foot skiffs to 100 foot purseseiners and investments from $10,000 to over1 million dollars. In 1997, registeredcommercial fishing vessels from SantaBarbara to Orange County numberedapproximately 1375. Over 1900 commercialfishing licenses (including both captains andcrewmen) were issued in the same area(David Ono, CDF&G, pers. comm.).

Professional fishermen, those who derive themajority of their income from fishing, and dualcareer fishermen (who work at other jobs andfish seasonally) are estimated to number over300 in the tri-county area (San Luis Obispo,Santa Barbara, and Ventura Counties). Thisnumber does not include “sport-commercialfishermen” (hobby fishermen or retired persons


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fishing part-time) or commercial sea urchindivers, a large fleet generally working out ofthe area of decommissioning activities. (Dr.Craig Fusaro, pers. comm.).

DECOMMISSIONING OPTIONS

Of the 43 commercial fishing vesselowner/operators interviewed, the vast majority(95%) expressed the following opinion:

“The oil and gas industry should honoragreements made with state andfederal government agencies and othermarine resource users to remove alloffshore structures and equipmentfrom the abandoned leases and returnthe seafloor to it’s original state.”

This opinion was expressed in many differentforms and paraphrased by the author. Itreflects the perception of many in the fishingindustry that during the leasing process,agreements were made that would assure theremoval of offshore structures and that theseafloor would be returned to the state it wasfound prior to offshore oil and gasdevelopment. This perception, is apparentlyincorrect in regard to the MineralsManagement Service’s OCS Oil and GasRegulations on decommissioning offshorefacilities as they give the MMS RegionalDirector certain discretionary authority to“depart from the operating requirements of theregulations” and allow alternate uses of theoffshore structures with the concurrence ofother regulatory agencies (See Appendix I:Regulatory Framework…, page 197, thisvolume).

If the decision is made to allow all or portionsof the offshore structures to remain in place orto be moved to another at-sea location, thefishermen interviewed provided the followingcomments and opinions on the variousdecommissioning options, starting with theleast desirable and ending with the mosttolerable:

Option #3: Partial Jacket Removal(Topping to 85 feet below thesurface)

This was considered the least desirable andmost dangerous option by the majority offishing captains interviewed in each of thedifferent fleets. The following is a summary of

the comments and information provided on theimpacts of this option on each type of fishingoperation:

Troll Fishery - Salmon trollers tow severalsets of lines with numerous lures or baitedhooks weighted by large lead sinkers (“cannonballs”). These lines are often fished to depthsof over 300 feet and fishermen try to avoid anysubmerged obstructions that would snag theirgear. If existing platforms are cut to 85 feetbelow the surface, trollers would have to stayclear of the remaining structures. Trollfishermen expressed concern over loss offishing area and potential gear loss if rigs weretopped and the remaining structure left at 85feet below the surface.

Hook & Line - Hook and line fishermen havesimilar concerns as a common technique is todeploy buoyed vertical longlines with groupsor “gangions “ of baited hooks near anidentified “stack” of fish. The lines are thenretrieved and the fish removed. These linesare also weighted with 20 to 30 lb. weights andfished at depths of several hundred feet. Theprimary objections of hook and line fishermento this option are the potential for gear loss andloss of fishing area.

Set & Drift Gill Net - Set gill nets are not usedfrequently in the area of offshore oilproduction, but drift gill nets are deployedduring the thresher shark, swordfish, andwhite sea bass seasons. The drift net, which isattached to the fishing vessel at one end, maybe up to a mile long and 200 feet deep, thoughthe depth will vary according to the oceanconditions and areas fished. Captains of driftnet vessels are particularly concerned aboutsubmerged obstructions, as they generallywork at night and have restricted mobility whenthe net is out. The direction and speed of thedrift is determined by the ocean currents and aboat may cover 10 or 15 miles in a night offishing. The potential for major loss of gear andfishing time, the safety risk of being snaggedand immobile at night, as well as loss of fishingareas are the primary reasons drift netfishermen feel this is an unacceptable anddangerous option.

Trawl Fishery - Trawl nets are fished either inmid-water or on the bottom with bottomtrawling being the most commonly used insouth-central and southern California. Thisfishery is particularly vulnerable to any type ofbottom obstruction and fishermen may spend

Disposition Session

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years charting these obstructions or “hangs” toavoid damage or loss of gear. By cutting therig down to 85 feet below the surface, trawlerslose the ability to see the exact location of theremaining structure. If the structure is markedwith a surface buoy, they will still have to givethe area a wide berth, thus losing considerablymore fishing area than if the rig were left withat least part of the topside intact. Potentialgear loss, becoming snagged and immobile (amajor safety risk), and losing additional fishingareas are the main objections trawlers havewith this option. Some trawlers have alsonoted that oil-field marker buoys themselveshave become navigation hazards whenmaintenance is poor and they lose lights, radarreflectors, or become partially or fullysubmerged.

Purse Seine - Purse seiners, a highly mobilefleet traditionally seeking pelagic species(anchovies, sardines, mackerel, bonito, andtuna) have recently increased in number onthe south coast due to several good seasonsof squid availability and sound markets.Vessels from the central California andWashington have joined the San Pedro, PortHueneme, and Ventura fleets to fish in theSanta Barbara Channel. Squid fishing is cyclicand the warmer waters anticipated this season(1997-98) may diminish squid production andprompt fishermen to put more effort in pursuingthe pelagic species throughout the southernregion. With nets that can be fished to depthsof 360 feet and “pursed” (the bottom of the netclosed) at a depth of 180 feet, seine captainshave the same concerns about snaggingbottom obstructions as the drift net and trawlfishermen: primarily damage and loss of gear,the safety risk of being immobilized, and theloss of fishing area.

Trap Fisheries - Lobster and crab trapfishermen often work near some of theshallower rigs and would probably be able toavoid problems if the underwater structureswere carefully marked with buoys. Since trapsmay move or “walk” during storms or roughocean conditions, more problems (such assnagging or loss of gear) might occur with theother options such as toppling or moving thejackets to inshore areas as artificial reefs.Increasing boat traffic to and from an artificialreef site could also adversely affect trap fishingoperations.

Option #4: Partial Jacket Removal(Toppling in place - artificial reef)

A majority (over 90%) of the fishermeninterviewed felt this was also an undesirableand risky option. They expressed the sameconcerns (gear loss/damage, safety risk ofbecoming snagged and immobilized, and lossof fishing area) as with topping to 85 feet.Toppling certain deeper water rigs may not beas much of a problem to the fleets that fish offthe bottom, but many of the shallowerplatforms are in prime commercial fishingareas, particularly for trawling and purseseining. Several fishing industryrepresentatives questioned the reasoning (andscientific basis) for toppling the platforms inplace to be used as artificial reefs, rather thancarefully selecting areas and reef materialsthat would provide beneficial habitat forenhancing fish production.

Option #6: Deep Water Disposal ofJacket

This option was unacceptable to all but a few(7%) of the fishermen interviewed. Mostcaptains hold a strong bias against using theocean as a dumping ground.

Option #5: Move Jacket to ArtificialReef Site

This was considered a possible option by mostfishermen (though about 10% favored totalremoval). They would consider this option on acase-by-case basis with well defined goals forthe project, careful study of potential reef sites,and development of site criteria consideringboth ecological and fisheries aspects. Areacommercial fishermen would like to be fullyinvolved in the planning process along with theother stakeholders. Again, many fishermenquestioned whether the oil platform jackets areconstructed with the proper materials to buildviable, long-lasting reefs.

Option #2: Non-Removal: MultipleUse

This was considered the most tolerable option,especially if a portion of the platform topsideremained above the water so it was easilyseen by day and picked up by radar in the fogor at night. The platform lights at night alsohelp fishermen and other mariners innavigating.


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The following benefits to this option wereexpressed by 90% of the captains:

Shell mounds which remain on the seafloorafter the removal of the “4H” platforms in statewaters off Santa Barbara County havecontinued to be a problem to the commercialtrawl fleet. By leaving the platform intact, withthe topside visible, fishermen would have abetter chance of navigating and fishing aroundthe structures and would not have to beconcerned about “hanging-up” on the shellmounds or losing additional fishing grounds.

Most of the other (non-trawl) fleets would alsobe able see and navigate around the rigsbetter if they were left intact and exposedabove the surface rather than cut off ortoppled. They would be significantly easier tosee at night if the topsides remained lit.

Many of safety risks and potential geardamage mentioned above would be reduced ifthe platforms remained visible to fishermen.

Several commercial fishermen suggested thatthe fish populations now associated with therigs might have better protection if the rigsremained standing rather than being cut offbelow the surface or toppled.

Non-removal, in fact, was preferred by nearlyall of the fishermen interviewed if one or twoplatforms were carefully selected to serve asweather stations, especially at the west end ofthe Santa Barbara Channel or in the SantaMaria Basin. Other suggestions for multiple-use of the oil and gas rigs included: a CoastGuard rescue station; a fisheries andaquaculture experiment station, long-termecological monitoring site, oceanographicresearch station, and a site for alternativeenergy production (utilizing wind, wave, andcurrents). A majority of those intervieweddesired to be included in discussions of thecosts and benefits of these potential uses. Thequestion of liability continues to be a primaryconcern of the fishing industry members.

Pipelines

Leaving pipelines in place afterdecommissioning the platforms would poseproblems for certain commercial fishingoperations depending on the areas and thecondition of pipes. Those pipelines with snags(rough or exposed flange connections), areasof pipeline cross-overs, pipelines rising off thebottom, or disconnected ends sticking up can

cause gear damage and loss to most of netfishing and trapping operations in the areas ofoffshore oil and gas production. Properlymaintained, smooth pipes usually cause noproblem for trawlers, seiners, or trappers,though fishermen expressed concern aboutpotential long-term deterioration of thepipelines and which agency would assumeliability for those remaining afterdecommissioning.

SUMMARY OF COMMERCIALFISHING REPRESENTATIVES’PREFERENCES:

The majority of the 43 fishermen interviewedfavored Option #1: Full removal of platformsand associated debris.

Alternatively, if regulatory agencies decide toallow the offshore structures to remain in placeor to be moved to another at-sea location, thenthe majority favored Option #2: Leaving thestructure in place with careful consideration ofmultiple uses, safety risks, ownership, andresponsibility for liability.

In regard to pipelines, most fishermen wouldaccept leaving them in place with assurancesthat they remain snag-free and compatible tothe various fishing operations, though long-term maintenance responsibility and liabilityshould be determined prior to abandonment.

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Appendix A.

Commercial Fishing OrganizationsContacted:Southern California Lobster AssociationPacific Coast Federation of Fishermen’sAssociationsSouthern California Trawlers AssociationMorro Bay Commercial Fishermen’sAssociationCommercial Fishermen of Santa Barbara, Inc.Ventura County Commercial Fishermen’sAssociationFederation of Independent Seafood HarvestersSea Urchin Harvesters Association ofCalifornia

Resource Managers and BiologistsContacted:Robert Hardy - California Department of Fish &Game, Morro BayChristine Pattison - California Department ofFish & Game, Morro BayDan Dugan - California Department of Fish &Game, Morro BayMaria Voikovich - California Department ofFish & Game, Santa BarbaraKristine Barsky - California Department of Fish& Game, Santa BarbaraDavid Ono - California Department of Fish &Game, Santa BarbaraMarylin Beeson - California Department of Fish& Game, San Diego

AcknowledgementsThe author gratefully acknowledges the timeand wealth of information provided by all of thecaptains, crew, vessel owners, and fishingorganization representative who participated inthe interviews. Also many thanks to theresource managers and biologists of theCalifornia Department of Fish and Game whoprovided current background information anddata on the south-central and southernCalifornia fishing operations.

Special thanks to Vanessa Deluca, of StateFish Company, San Pedro, John Lane, HerbLeedy, and Dave Panzer of the MineralsManagement Service, Camarillo who took timeto answer questions and provide backgroundmaterials.

Review of the manuscript by Dr. ChristopherDewees, Sea Grant Extension Program andDr. Craig Fusaro, Oil/Fisheries Liaison Office isgreatly appreciated.

Dr. Mark Carr, University of California SantaCruz, served as the catalyst in initiating theproject and Bonnie Williamson, University ofCalifornia, Santa Barbara, has assistedtremendously with technical support.

Funding and travel support was provided bythe U.S. Department of the Interior, MineralsManagement Service; University of CaliforniaSanta Barbara, Marine Science Institute; andthe U.C. Sea Grant Extension Program.


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ECOLOGICAL CONSEQUENCES OF ALTERNATIVEDECOMMISSIONING STRATEGIES FOR

POCS OFFSHORE FACILITIES

DR. MARK H. CARRDepartment of Biology, University of California, Santa Cruz

DR. GRAHAM E. FORRESTERDepartment of Biology, University of California, Los Angeles

DR. MICHAEL V. MCGINNISOcean and Coastal Policy Center, Marine Science Institute, University of

California, Santa Barbara

SIGNIFICANCE OF STUDY

Critical to formulation of appropriatedecommissioning policy is an understanding ofthe ecological, economic and socialconsequences of different decommissioningoptions and identification of the mechanismsby which such information is incorporated, ornot, into legislation and public policy. Perhapsthe most important ecological consequence ofabandoning POCS facilities is a potentialchange in regional fish production (thebiomass of fish accrued per year), which mayin turn influence yields to fisheries. Hardsubstratum reefs represent a small fraction ofthe available offshore habitat in California, butare sites of high fish production. However,prior to this study, only one study providedquantitative estimates of species compositionand abundance of fishes at a single platformoff southern California.

STUDY OBJECTIVES

1. Quantitative description and comparison offish assemblages on natural reefs and offshorestructures.

One objective of this study has been toquantify the species and sizes of fishesassociated with platforms and natural reefs.Such information is required to determine whatspecies and life stages might be influenced bythe various decommissioning options. Do fishrecruit to each habitat type from the plankton(as larvae) or migrate on to one habitat typefrom the other as older stages (benthicjuveniles and adults)? Comparison of fishesbetween platforms and natural reefs providesinformation on what stages use the two habitat

types. Patterns of fish sizes over time can alsoprovide information on how long fishesassociate with each habitat type and how wellthey grow and survive. Such information iscritical to understanding the relative value ofnatural reefs and platforms as fish habitat.

2. Quantitative description of the verticaldistribution of fishes on platforms.

Several of the various options for platformdecommissioning alter the vertical height of theremaining structure (e.g., “topping”, “toppling”,moving to different water depths). To estimatethe potential consequences of these options, itis necessary to determine how species aredistributed from the surface to the bottom ofthe platforms. Also, information on the sizes offish at each depth can indicate patterns ofrecruitment and how the vertical distribution offishes changes as they grow.

3. Quantify the net rate and direction of fishmovement between platforms and naturalreefs.

Fundamental to understanding the netcontribution of local populations to regionalproduction is information on the size-specificrate of migration of fishes among local, reef-associated populations. In the context ofplatform decommissioning, knowledge of thenet direction and rate of transfer of biomassbetween platforms and natural reefs is crucial.For example if fish recruit to natural reefs andeventually migrate to platforms, accumulationof fish biomass on platforms would beincorrectly attributed to production at theplatform habitat. Conversely, if platformsprovide recruitment habitat for fish thateventually migrate to natural reefs, the

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contribution of platforms to regional productionmay be grossly underestimated by simplymeasuring production in the two habitats.Movement information is also important todetermine whether the loss of fish at a site isdue to emigration rather than mortality.Therefore, we have conducted a tagging studydetermine how much and what direction (fromplatforms to reefs or vice versa) fish move, therate of that movement, and net direction ofexchange.

Study Area and Methods

1. Quantitative description and comparison offish assemblages on natural reefs and offshorestructures,

and


Over the past three summers (1995-1997), fishassemblages associated with shallow (< 33m)portions of six production platforms (Hogan,Houchin, Henry, A, B, and C) have beensampled monthly from May through October(peak periods of recruitment of most reeffishes) using diver surveys. Deeper (> 33m)portions of these platforms have beensurveyed three times each year (June, August,October) with a remotely operated vehicle(ROV) outfitted with a video camera incooperation with the Marine TechnologyProgram at the Santa Barbara City College.Surveys conducted by divers on productionplatforms involve estimates of the density andsize of individuals of each species along 2 mwide x 2 m tall belt transects at predeterminedlocations and depths. A second diver samplesthe same transects using an underwater videosystem. The video system (equipped withparallel lasers for estimating fish length) isused to increase the sample size of fishlengths and provide a standard for comparingsamples with ROV video at greater depths.Belt transects of similar dimensions aresampled with the ROV while an observer logsthe depth and location of transects, andidentifies fish species.

Divers also locate and sample fishassemblages on the 3 shallow natural reefsclosest to these production platforms duringthe same sampling period each month. Datacollected on natural reefs are the same as thaton production platforms, but surveys of naturalreefs also include quantification of habitat

variables (e.g., substratum type and relief,epibenthic cover, density and size ofmacroalgae, temperature and visibility) thatmight explain patterns of species abundance.The ROV is used to sample one or twoadditional natural reefs in deeper waterbetween the shallow natural reefs and theproduction platforms.


Over the past two years we have begun atagging study to estimate rates of fishmovement between production platforms andnatural reefs. This work is being done inconjunction with the Channel Islands NationalMarine Sanctuary and volunteers from theUniversity and the local sport fishingcommunity. We have tagged fish at fournatural reefs in the vicinity of the 6 studyplatforms off Summerland. Fish are caught byhook and line, identified, measured, taggedwith standard Floy tags, and immediatelyreleased. When necessary, their swimbladders are vented to enable fish to return tothe bottom. Floy tags are similar in design togarment tags, with a number, name and phonenumber. This allows fishers to call and informus of where and when they caught each fish.Tags are color coded by the reef/platform onwhich they were tagged and released.

Results and Implications

1. Quantitative description and comparison offish assemblages on natural reefs and offshorestructures

The species composition of fishes encounteredon platforms and natural reefs differed bothwith respect to the presence/absence andrelative abundances of some species in eachhabitat. Some species were only encounteredon the natural reefs (listed in red color on theadjacent Table). Others were only observedon the platforms (listed in blue on the adjacentTable). However, most species occurred atboth habitats types (listed in black).Particularly notable were the several speciesof surf perch and kelp-associated species onlyseen at the natural reefs, and the youngrecruits of many rockfish species that wereonly seen at platforms. Many of the speciesobserved at both habitat types differed in theirrelative abundance on platforms and naturalreefs (see Table below). Some of these


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economically or recreationally importantspecies were more abundant on natural reefs(e.g., barred sand bass, kelp rockfish),whereas others were more abundant onplatforms. These results suggest that theremoval of platforms will likely affect somespecies much more than others, and somespecies will likely be influenced little.


The abundance of many speciesvaried markedly with depth along platforms.Often these depth-related differences werealso related to the age/size of individuals. Forexample, the young of many shallow dwellingrockfish occurred only at the shallower depthssampled, whereas older stages (juveniles andadults) occurred more frequently at greaterdepths. These results suggest that removingthe upper portion of platforms may reducerecruitment of some species to the platforms.In contrast, both the young and older stages ofother species (many rockfishes includingolives, widows, boccacios) occurred at depth,suggesting that recruitment and adultabundance of these species may not be

reduced by the removal of the upper portionsof platforms.


To date, we have tagged 500 fish andrecaptured 50. This high return rate (10%) isattributable to the excellent cooperation bysport fishers that have called us withinformation on the fish they caught. Of the fishrecaught, 75% were caught where they weretagged, suggesting that many of the speciestagged (mostly rockfishes) remain on the reefsthey were tagged. Of course, it is not clearhow much movement occurs by the many fishthat were not recaptured, but we hope tocontinue to collect information on thoseindividuals in the future. Some speciescontributed highly to the individuals that domove; particularly barred sand bass andkelp/calico bass. That calico bass move morehelps to explain why we see many adults onreefs, but no young recruits. These datastrongly suggest that a species like this isattracted to platforms, having recruited asyoung elsewhere, rather than recruiting to andremaining on the platforms.

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EFFECT OF OFFSHORE OIL PLATFORM STRUCTURES ON THEDISTRIBUTION PATTERN OF COMMERCIALLY IMPORTANT

BENTHIC CRUSTACEANS, WITH EMPHASIS ON THE ROCK CRAB

DR. HENRY M. PAGE AND DR. JENIFER E. DUGANMarine Science Institute, University of California, Santa Barbara

Offshore oil platforms act as artificial reefs byproviding habitat for mussels, encrustingbivalves, sea anemones and otherinvertebrates. Studies of artificial reefs, ingeneral, have centered on whether they simplyattract or produce sport and commerciallyimportant fishes. We tested elements of aconceptual model describing possibleinteractions between offshore platforms andCancer crab stocks based on ideas developedfor fish populations and fishery refugia.

Using offshore platform "Holly" (Mobil) as amodel system, we: 1) estimated foulingcommunity thickness on platform conductorpipes and the rates and composition of faunallitterfall to the benthos that may provide foodand/or habitat for rock crabs, 2) evaluatedwhether the platform is a site of rock crabproduction, and 3) determined if crabsaggregate beneath the structure relative toadjacent soft bottom.

The fouling community attached to Hollyprovides shelter and food for juvenile Cancerantennarius. This community of organisms,which varies in thickness with depth (P<0.001,One-way ANOVA), reached a maximum meanthickness of ~18 cm at a depth of 12 m anddecreased to a mean thickness of ~5 cm at adepth of 24 m. Mussels predominated atdepths of 6 m and 12 m while barnacles (e.g.,Megabalanus californicus, Balanus aquila),encrusting bivalves (e.g., Chama spp.Crassadoma gigantea), and anemones(Metridium senile), predominated deeper. Thebay mussel, Mytilus galloprovincialis,comprised nearly 100% of the mussels atdepths shallower than ~9 m while largeclumps of the sea mussel, M. californianus,were present between 9 m and 15 m.

The fouling community is also a source oforganic enrichment to the benthos through"faunal litterfall". Using 38 cm internaldiameter plastic circular hoops with attached

fine mesh bags as faunal litterfall traps, wecollected an average of from 0.08 to 2.6 kg wet

weight of mussels•trap-1•week-1 at a depth of18 m. Dislodged clumps of M. galloprovincialisformed nearly 100% of this material. Thetopography of the bottom beneath Holly isaltered by this litterfall and consists of a moundof mussel shells at least 1.5 m thick at theplatform periphery. Rock crabs could beattracted to the area beneath or around Hollyby increased food availability and/or habitatheterogeneity.

To identify rock crab species present andtemporal patterns in crab abundance beneathHolly, standard crab traps (Fathoms Plus)were deployed monthly from the platform andevery two to three months ~200 m east, south,and west of the platform. Three species of rockcrab (brown rock crab-Cancer antennarius,yellow rock crab-C. anthonyi, red rock crab-C.productus) and the sheep crab, Loxorhynchusgrandis, were found beneath Holly. C.antennarius (x=1.0 to 7.5 crabs•trap-1) and C.anthonyi (0 to 16.7 crabs•trap-1) were mostabundant followed by C. productus andLoxorhynchus grandis (usually <1.5

crabs•trap-1).

Cancer antennarius and C. anthonyi weresignificantly more abundant beneath Holly thanon surrounding soft bottom. There was nodifference in abundance among locations forC. productus and Loxorhynchus grandis. Ofinterest, 87% (n=254) of the C. anthonyiindividuals trapped at the platform werefemales, compared with only 26% females(n=99) at the soft bottom stations, suggestingthat females may prefer more heterogenoushabitats than males.

To quantify spatial and temporal patterns in therecruitment of rock crabs and in crabpopulation structure on the platform, crabswere censused and fouling community


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sampled on at least four vertical conductorpipes at three depths (12, 18, 24 m) usingSCUBA every other month.

Only Cancer antennarius recruited to theplatform. Smallest crabs (<40 mm carapacewidth, CW) were found within clumps ofMytilus californianus and were rarely seen invisual surveys or trapped. The smallest crabsremain hidden in mussel clumps and becomemore active at a size of >40 mm CW. Crabs of40 to 80 mm CW were found in the open andenter traps. Larger crabs >80 mm CW werepresent, but were less abundant. The largestC. antennarius were trapped on the bottombeneath the platform . Larger crabs beneaththe platform may have recruited into musselclumps in shallow water and fallen or moved tothe bottom.

Preliminary analysis of our data suggests thatCancer antennarius, C. anthonyi, C. productus,and Loxorhynchus grandis, respond differentlyto the presence of the platform (Figure 1).Recruitment of C. antennarius occurs onto theplatform, but dispersal appears limited, leadingto a resident population restricted to the vicinityof the structure. Recruitment of C. anthonyidoes not occur at the platform, but members ofthis species (primarily females) aggregatebeneath the structure. C. productus does notrecruit at the platform and there were no

patterns in the distribution of adults relative tothe platform. Finally, L. grandis was foundseasonally at the platform and at soft bottomsites, indicating that this species movesbetween the platform and surrounding areas.

The implications of the availabledecommissioning options on crab populationswill vary among crab species. C. antennariusand C. anthonyi are likely to be affected mostby the various removal options Completeremoval (structure and mound) of the platformwill result in a loss of litterfall and habitat thatwould directly reduce the production of C.antennarius. This option would also affect thedistribution of female C. anthonyi. Therewould be relatively little effect on C. productusand L. grandis. Partial removal (cropping at adepth of 60 feet or toppling) would result in aloss of litterfall because much of the productionof the fouling community occurs above 60 feet.Recruitment of C. antennarius may be reducedunder this option. The aggregation of C.antennarius and C. anthonyi on the musselmound may still occur, however, reduced foodavailability could affect growth rate of thesespecies. Decommissioning of the platform inplace or elsewhere, as an artificial reef, couldresult in a continuation of the patterns found atPlatform Holly. However, these patterns mayvary among platforms and reefs depending ondepth and location.

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Figure 1. Summary of distribution and movement scenarios for the rock crab, Cancer spp., and the sheep crab, Loxorhynchus grandis in relation to offshore oil platform Holly +=data consistent with scenario, =data inconsistent with scenario, *hypothesized, insufficient data.

④

Water Line

Mussel mound

Soft Bottom

②

④

①③

①② ③

Recruitment

Attraction/Aggregation of individuals produced elsewhere

①Recruitment to platform followed by movement away from platform

②Resident population; produced by recruitment onto platform supports

③

Movement of individuals between a platform and surrounding areas

④

C. antennarius C. anthonyi C. productus L. grandisDistribution scenario

Crab species

*

+

+

+ ++*

Figure 1. Summary of distribution and movement scenarios for the rock crab, Cancer spp., and thesheep crab, Loxorhynchus grandis in relation to offshore oil platform Holly. + = data consistent withscenario, - = data inconsistent with scenario, *hypothesized, insufficient data.


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ENHANCEMENT OF PLATFORMS AS ARTIFICIAL REEFS

DAVID O. PARKERSenior Biologist

California Department of Fish and Game

Enhancement refers to the addition ofmaterials which can provide increased and/orimproved substrate for development of reef-based communities. The resulting reef couldhave high and low relief components, crevices,ledges, edges, holes and other features whichincrease substrate complexity. Addition ofsuch materials would also serve to providesome "replacement or compensation" for theupper water column platform structure which iswould be removed to meet navigational, safetyor other requirements. The size or footprint ofthe reef habitat area would also be increasedthrough materials enhancement. A larger reefarea could contribute to development of self-sustaining reef populations and serve to limitthe "habitat island" effect of a small isolatedreef.

Materials should have inherent stability once inplace. Those with high specific gravitiesprovide the greatest likelihood that the reefconfiguration will be stable and remain in placeover time. Materials should have a very longor indefinite life in the marine environment.The physical and chemical composition, andshape should not degrade or change such thatthe substrate/habitat function is substantiallyimpaired. Rock and concrete rubble have beenused extensively and perform well for artificialreefs in California. Manufactured substrateshave not been used extensively here, butcould be appropriate to meet specific reefdesign criteria. Quarried rock is locallyavailable in any quantity, size and in severaldensities. Shoreline quarries simplify transportand delivery by barge.

Concrete rubble, or scrap is a material ofopportunity with uncertain availability, whichmay have to be stored while sufficientquantities are accumulated. Shapes and sizesare variable and depend on the source and itmay be mixed with other undesirablematerials. Transportation involves severalstages, overland, loading facility, barge.Manufactured substrates can be developed for

a specific reef design and purpose with massproduction and replication increasing costeffectiveness. These materials could bemanufactured at or near barge loading sites tosimplify transport.

In southern California, artificial reefs have onlybeen constructed in nearshore areas atrelatively shallow depths, there has not beenany experience with reefs placed in depthssimilar to those of platforms planned fordecommissioning. Reef materials interactquickly with the surrounding substrate afterplacement including localized scouring whichstabilizes around some annual or seasonalvariation. Other than the localized effects onthe surrounding substrates, no large scaleeffects have been seen on natural sand orsediment movement patterns. These reefsalso undergo a process of biologicalsuccession or development beginning withsimple communities of opportunistic attachedorganisms and mobile species which areinitially attracted to new relief formingsubstrate. Communities tend to become morecomplex with time, and reef-dependent mobilespecies form resident communities. Giant kelpand other algae may develop on reefs inappropriate depths and locations. Manymobile species may also use the reefs for aportion of their life history - spawning, juvenilehabitat, feeding - or include the new reef aspart of their larger range which mightencompass existing nearby reef habitat.Specific patterns of the biological developmentprocess may vary with location, depth,surrounding substrate type and frequency ofdisturbances.

While enhancing platforms is meant to havebeneficial effects on reef based biologicalcommunities and resource users, severaluncertainties are present. Reefs in Californiahave not been constructed in depths likely forplatform-based reef sites. Design criteria forenhancement materials may have to bedeveloped for deeper applications. Substrates

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in those sites may have differentcharacteristics (softer, more easily disturbed?)and responses to added materials than thoseat inshore reef sites. The amount and extentof material to be added to platform structuresas reef enhancement has not beenestablished. How large should such new reefsbe? Is there an optimum mix of high and lowrelief components? What are the bestsubstrate types and configurations for thespecies and communities which are likely todevelop at specific locations? The rates of

biological development on the new reefs maybe different than in nearshore applications.

Many of the components of deeper reefcommunities are very long lived and a"mature" reef may develop very slowly. Willharvesting pressure at these new sites affectthe development process? Before seriousconsideration is given to constructing rig-basedreef systems, general design and siting criteriashould be developed and applied to eachproposed site on a case-by-case basis.

WHAT IS ENHANCEMENT?

• Addition of other reef forming materials

• Increased diversity and complexity ofsubstrate

• Replace “lost” upper water columnsubstrate

• Increase foot print of the reef

TYPES OF ENHANCEMENT MATERIALS

• Quarried rock

• Concrete rubble and scrap

• Manufactured substrates

CRITERIA FOR ENHANCEMENTMATERIALS

• High density and stability

• Longevity and durability

• Substrate value

PERFORMANCE OF REEFS AS POTENTIALENHANCEMENT MATERIALS

• Experience in California limited tonearshore waters

• Physical interactions

• Biological development

UNCERTAINTIES OF REEF ENHANCEMENTIN DEEPER WATER APPLICATIONS

• Interactions with local substrate

• Magnitude of enhancement componentneeded

• Biological development process

CHARACTERISTICS OF SOME MATERIALS

• Quarried rock

• Locally available on order in desiredamounts and sizes

• Concrete rubble and scrap

• Uncertain availability, variable size andshape

• Manufactured substrates

• Designed for specific application

EFFECTS OF ENHANCEMENT ASARTIFICIAL REEFS

• Resources and habitate

• New or expanded reef communities

• Displacement of existing bottomcommunities

• Uses and activities

• Additional opportunities for reef-relateduses

• Local limitations to uses of soft bottomhabitats


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LONG-TERM SOCIOECONOMIC EFFECTS OFONSHORE FACILITY DECOMMISSIONING

JAMES T. LIMA, PH.D.Sociologist, Minerals Management Service, Pacific OCS Region

ABSTRACT

The potential long-term social and economiceffects attributable to the decommissioning ofonshore oil and gas processing facilities andsites that support offshore energy developmentvary with the type of facility. Limitedexperience with decommissioning in Californiaposes new challenges to federal, state, andlocal decision makers. The process ofdecommissioning facilities that support a singleoffshore field at the cessation of production isfairly straightforward. The long-termconsequences of this action are generallynegligible or beneficial. The process ofdecommissioning co-located and co-operated(consolidated) facilities is more complex. Thelong-term consequences of this action to landuse, economic diversity, and governmentrevenues may be quite sizeable. Furthermore,the potential cumulative impact of onshoredisposal on landfill capacity needs to beexamined as part of the decommissioningprocess.

INTRODUCTION

The decommissioning of onshore facilities andsites that support offshore energy developmentin California State submerged lands and thePacific Outer Continental Shelf is a relativelynew phenomena. Depending on the type ofonshore facility, decommissioning may havepotentially sizeable, long-term cumulativeconsequences. This paper examines (1) thenature of decommissioning and the potentialsocial and economic impacts, (2) the threetypes of onshore facilities--private system,location consolidation, and operationconsolidation, (3) the likely long- termconsequences from the decommissioning ofeach type, and (4) the components that makeup decommissioning policy.

SOCIAL AND ECONOMICCONSEQUENCES OFDECOMMISSIONING

Most organized human activity generates anynumber of social and economic consequences.These impacts, which may be adverse orbeneficial, encompass a number of areasincluding aesthetics, noise, infrastructure, landuse policies, public finance and economics,and recreation. Furthermore, the magnitudeof the impact varies within the context of wherethe activity takes place and where the effectsare realized. Table 1 lists some of the generalcriteria for assessing social and economicimpacts. While each area has unique criteria,for most social impacts when demand exceedsthe supply of a service or capacity of thecommunity to provide the service, a adverse or“negative” impact occurs. Furthermore,impacts may be incremental and project-specific, that is, attributable to a specific actionor cumulative, the combined effect when theincrement is added to past, present, and futureactions. As such, the incremental impacts of asingle action may seem inconsequential whilethe cumulative impacts are quite sizeable.

The life cycle of offshore energy projectsprogress through four phases — exploration,development, production anddecommissioning. Social and economicimpacts are usually most pronounced duringthe development phase when offshore andonshore facilities are sited and constructed.The increased level of activity with itsattendant increase in employment andexpenditures causes both short-term and long-term in-migration of people to the area creatingdemands for public services. After theproduction system (e.g., platforms,completions, pipelines, and the onshoreprocessing and transportation facilities) iscompleted and operating, the breadth andmagnitude of in-migration impacts dramaticallydecline. The social and economic impacts

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caused by the onset of decommissioning,during which wells are plugged andproduction-related facilities close and aredismantled, will vary depending on the extent

to which the area is dependent on the oil andgas industry (Scheweithelm and McPhee,1983, 175).

Table 1. Criteria for the Assessment of Social and Economic Impacts in Onshore FacilityDecommissioning. (Area and Criteria for assessment adapted from California ComprehensiveOffshore Resource Study, Volume 1. California State Lands Commission, 1994).

Area Criteria for Assessment Likely Long-Term Effect

Cultural Resources 1. Effect on prehistoric or historicarcheology site.

2. Adversely affect a site orproperty of cultural significanceto a community or ethnic group.

3. Restrict existing uses which arereligious or sacred to arecognized group.

None. Most of the impactsresult for on-site construction.Dismantling of facilities shouldavoid areas known orsuspected to be culturallysignificant.

Aesthetic (Visual) Changes in view of1. primary travel routes and use

areas.2. a component for which there is a

public interest and concern.3. sensitive or unique natural

community4. on the horizon.

Beneficial from the removal ofindustrial facilities in primarilynon-industrial area. Re-industrialization afterdecommissioning ofconsolidated facility couldinduce new impacts.

Infrastructure 1. Increase level of traffic to degreethat it reaches an unacceptablelevel of service.

2. Substantially reduce availablecapacity of public water supply,sewage treatment, energysystems, schools, solid waste,toxic waste or public safetypersonnel and facilities.

Few long-term impacts due tostable low level employment inpost-development phases. Re-industrialization afterdecommissioning ofconsolidated could induce newimpacts. Impact on solid wastedisposal capacity is possible.

Land Use 1. Inconsistency with local or stateland use policies.

2. Commitment of land, eliminationof future land use options.

Beneficial for private systemfacility. Potentially sizeable forlocation and processingconsolidation.

Public Finance/Economics Does the action result in:1. Significant changes in public

revenues.2. Significant changes in public

agency expenditures.3. Changes in local property

values.4. Nonconformance with local land

use and coastal programs.

Likely negligible effects forprivate system facilities.Potentially sizeable for locationand processing consolidationdepending on value of offshoreindustry to local economy andtax base and ability ofgovernment to replace lostrevenue.


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The prevalence of social and economicimpacts during the development andproduction phases does not mean that areduced level of activity duringdecommissioning is inconsequential. ANational Research Council study (1992, 100)recognized that termination requires more anddifferent labor than production. Beyond theshort-term impacts, the study recognizescertain long term and cumulative impacts mayresult from termination, determined largely by“the extent that the economic and socialcharacteristics of regions have been shapedby the petroleum industry.” The cause ofthese impacts will not only be from thecessation of a primary economic activity, butthat its disappearance has “also left in its wakeconditions that may hinder alternative usesand repel those who might invest in theirdevelopment.” Investment in development ofother activity is likely to be hindered, the reportposited, because uncertainty will remain aboutthe future of oil and gas resources of an area,which may be resumed under differenteconomic conditions.

Rapid production declines and facilitydecommissioning in an area highly dependenton the offshore energy industry can have verypronounced social, financial, andorganizational impacts and regionallyimportant economic consequences, as seen inthe “bust” in the Gulf offshore industry in the1980s (See Gramling, 1996, 97-118; Seydlitz,et al., 1995; Thayer and Hadley, 1990). Forthe most part, California communities affectedby offshore energy development, which is amuch smaller segment of the area’s economythan in the Gulf of Mexico, have notexperienced the severe economic dislocationsinduced by the decline of the oil prices in the1980s. However, the economic impact ofoffshore energy development on Ventura andSanta Barbara County, as one recent studynoted, does provide significant benefits to thearea. The study surmises that the cumulativeimpacts of a gradual decline and cessation ofthe activity could be sizeable (UCSB EconomicForecast Project, 1997). Moreover, within thisarea, energy development activities have haddifferent cumulative effects on the two countiesand within the counties (Paulsen, et al., 1996;Molotch and Freudenburg, 1996). Socialscientists recognize that the limited experiencewith decommissioning of facilities in the Pacificmeans that the socioeconomic impacts

attributable to this final phase may be the leastwell understood of all the impacts (SCEI, 1991,B37).

Finally, understanding the impacts ofdecommissioning are important to the policieswhich govern the development of offshoreenergy resources in the future.Decommissioning may be seen as policytermination (SCEI, 1991). The policies thatshape offshore energy activity at any giventime are a combination of location, technology,economic, and political factors (Lima, 1994),and the effect of these factors will shapedecommissioning policy. Offshore energyprojects have very long life cycles.Decommissioning occurs within the context ofthe time and place. The policy that governsactivity at the end of one era of developmentbecomes the foundation for policy that willgovern the next era of development. Yet,there is not a single “decommissioning policy.”Rather, it is an amalgam of the policies of thegovernment agencies at all three levels ofgovernment involved in the process.

CLASSIFICATION OF ONSHOREFACILITIES

Different types of onshore facilities may requireunique policies for decommissioning offacilities. Using the typology of onshorefacilities developed by Willard Price (1987),onshore processing facilities in Ventura andSanta Barbara counties fall into two classes--the private (market) system and the privateindustrial development. Private systemdevelopment is characterized by the“maximum private freedom to own land anddevelop facilities, within traditional localgovernment land use, site development, andbuilding controls.” Private industrialdevelopment, of which consolidation is avariant, is characterized by “private ownershipand development of facilities, involving publicindustrial development sites, within publicplans and environmental regulations.”

PRIVATE (MARKET) SYSTEM

The private system onshore facility affords thedeveloper maximum discretion and flexibility inthe siting and the sizing of its onshoreprocessing facility and describes the systemthat was prevalent in Ventura and SantaBarbara counties until the early 1970s.

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Facilities were designed and sized for theparticular characteristics of the product and thefield. Facilities were usually sited as close aspossible to the landfall of the offshore-to-onshore pipelines, in order to minimizetransportation costs. If several operatorsdeveloped the same field, each usually had itsown processing facility. Shared facilities or thecommingling of production from several fieldsat a single plant was not usually practiced andin some cases was prohibited. Theseseparate onshore sites were relatively closetogether, reflecting the pattern of offshoreleasing, land ownership and the previous oilfield development. In combination with existingonshore production, private systemdevelopment resulted in the industrialization ofthe coastline as each operator constructed aseparate onshore plant. (For a detaileddescription of energy facility siting in generalsee New England River Basins Commission,1976, and in the Santa Barbara Channel inparticular see Centaur Associates, 1985 andLima, 1994). Planning for these facilities wassequential and reactive, with each facility beingconsidered individually when the operatorrequested initial or subsequent permits (Price,1987).

PRIVATE SYSTEMDECOMMISSIONING

Under the private system, onshore processingfacilities, the processing site, and offshoreproduction components (platforms, subseacompletions, slant drilling from an onshoresite) are physically and conceptually linked.When the decision is made by the company toterminate operations, decommissioning of theentire seaward and landward components mayproceed simultaneously. In essence, theprivate decision renders the entireproduction/processing system redundant.(Government policies influence the economicattractiveness of continued production underprevalent market conditions. See, forexample, California Oil Survival Team, 1993.)Each level of government is concerned withfacilities within its jurisdiction. Private systemdecommissioning exhibits the least regulatoryoverlap. All onshore equipment can beremoved and the site restored with littleconcern of the cumulative effect of theseactions. Decommissioning is and was verymuch a case-by-case, facility-by-facilitydecision. As such, onshore decommissioning

activities are primarily concerned with issuesproximate to the physical environment--facilityremoval, clean-up of on-site contaminatedareas, site restoration, and revegetation.

Local governments have had limitedexperience with decommissioning privatesystem onshore facilities. Facilities and sitesthat supported offshore production have onlyrecently begun to be decommissioned. Formaldecommissioning policy for the private systemhas been very ad-hoc, contained in acollection of land use plans and ordinancesand in individual facility permits. Policy is verygeneral, mandating removal and restoration.Details of decommissioning were very sitespecific and concentrated on the best way toachieve the removal and restoration objectivesfor each specific site. These detailedprocedures are often contained in a regulation-mandated abandonment plan or by some otheraction by public authorities (SBC, 1990).

This “policy” has generally functionedadequately. However, one Santa BarbaraCounty (1996) publication noted that while theregulatory framework appeared to befunctional overall, some potential issueswarrant attention. Particularly, variation wasfound to exist in “due diligence towards timelyabandonment of an oil and gas operation,including the removal and restoration of thesite”(SBC, 1996). In some cases, the “lag”between cessation of operations tocommencement of removal has beenunacceptably lengthy to local decision makersand other stakeholders.

Another concern regarding timeliness of actioninvolves how to ensure industry bears thecosts of decommissioning rather than thepublic, which could be exposed to potentiallylarge risk if decommissioning is notaccomplished as intended. This latter concernis the reason that permits require performancebonds or some other type of surety.

IMPACTS OF PRIVATE SYSTEMDECOMMISSIONING

Decommissioning occurs in the context of thecurrent time and place. This facet is seen inland use issues which are the primary socialand economic impacts of private systemdecommissioning. Potential impacts include


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the compatibility of the decommissioned sitewith adjacent land uses and ensuring the newland use designation is consistent with stateland use policy, such as California Coastal Actpolicies. Given the long life cycles of energyprojects and the changing pattern of land use,the current policies are likely to be much lesstolerant of renewed use of the individual sitesfor processing. For example, the CaliforniaCoastal Act requires consolidation of onshoreenergy facilities. In turn, this requirement ispart of each county’s local coastal land useplan.

The processing facilities that supported the“Mobil pier” state tideland leases were in partauthorized by Ventura County via a conditionaluse permit (CUP) in 1948. When thesefacilities were recently decommissioned, theCUP required minor modification to addressthe dismantling of facilities. However, the CUPremained in effect because some facilitiescovered by the CUP were still in operation(Fugro West Inc., 1996). Undergroundpipelines were abandoned in place to minimizeground disturbance. Above ground pipelineswere either removed or were to remain inplace until the entire pipeline corridor whichserved more than the processing plant wasabandoned. Zoning of the parcel remainedCoastal Manufacturing, which limited uses ofthe parcel to petroleum related activity until thezoning designation is changed. Thesurrounding land use is zoned as coastal openspace or industrial, uses that are compatiblewith petroleum related activities (Francis,1997). However, since the site is within thearea intended for onshore processing, theaction is consistent with current policy.

Santa Barbara County chose to change landuse designation of private system facilities inadvance of decommissioning in part to ensurecompliance with Coastal Act-mandatedconsolidation policies. The decision in 1990 torezone seven existing onshore sites in thearea adjacent to the Santa Barbara Channelwas done at a time when many of the sites stillsupported offshore production. The rezoningaction had the effect of rendering offshoreenergy processing at these sites a “legal non-conforming land use” which allowed thecontinued existing use that would otherwisenot be permitted under the new designation.While non-conforming land uses may be

continued, the designation prevents theexpansion or enlargement of that use (SBC,1990). This action will cause future processingto occur at consolidated facilities inaccordance with current policy.

The long-term social and economic effects ofproperly decommissioned onshore privatesystem sites are few. Cultural resourceimpacts occur during the development phasefrom construction. Aesthetically, removal ofindustrial facilities in primarily non-industrialareas is viewed as a benefit, as is therestoration of the site to a land use and zoningdesignation that is compatible with thesurrounding area. The economicconsequences of decommissioning areameliorated by the fact that for many years thefacility most likely supported decliningproduction from the associated field andoperated with a relatively small and stableworkforce. The public finance and serviceimpacts are minimized because whenproduction ceases the property tax value of thephysical plant (i.e., improvements to the land)is minimized. In some cases, whatever usereplaces the facility, such as conversion of theprocessing site to a recreational or residentialdevelopment, may lead to greater assessedvaluations in the long term.

PRIVATE INDUSTRIALDEVELOPMENT (PID)

Under the private industrial developmentconcept, land and facilities are privately ownedand developed within the framework of publicplans and environmental regulation. Anexample of the PID is the establishment ofconsolidated processing sites and facilities inSanta Barbara County in the mid-1980s. Price(1987) notes that consolidation creates anonshore “oil industrial park” and represents astep toward comprehensive, proactiveplanning away from the sequential andreactionary planning that characterizes privatesystem development. There are two types ofconsolidation--location consolidation andoperational consolidation.

LOCATION CONSOLIDATION

Location consolidation is structured so thatseparate processing facilities must be co-located in a designated geographic area orwithin a specific site. That is, land use plans

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and ordinances designate the areas wherethese facilities are to be co-located. Thispolicy attempts to reduce the cumulativeimpacts of individual facility construction byaggregating the impacts from many sites to acentralized location. However, locationconsolidation retains many of thecharacteristics of the private system describedabove wherein each operator is free toconstruct and operate facilities within thiszone. Often, the extent of the area wherefacilities will be allowed is determined by thealready existing concentration of facilities in anarea from previous and current development.The strategy presently used by VenturaCounty approximates location consolidation.

In Santa Barbara County, locationconsolidation was a strategy first annunciatedin 1967 in order to reduce industrialization ofthe coastline brought on by the projectednumber of onshore processing plants thatwould be needed to support expandedoffshore leasing. The policy favoredexpansion of existing facilities onto landsadjacent to existing sites and consolidation offacilities on existing processing sites or theland adjacent to them as an alternative to new,separate sites (Lima, 1994). This policymarked the transition from the private systemto the private industrial system since itcontrolled within public plans and policieswhere and under what circumstances thatonshore facilities could be sited.

LOCATION DECOMMISSIONING

Location consolidation decommissioningallows removal of facilities but retains theunderlying land use designation which allowsthe continued use of the site for processing. Ifa single operator chooses to decommissionfacilities, the action might require removal ofequipment and restoration of a portion of thesite, but it does not require that the entire siteand all facilities be decommissioned. An areamay experience a “rolling decommissioning” offacilities over the life of the site. Indeed, thesite could experience cycles of industrializationand decommissioning over time. However, thesite would always be available to supportonshore activities for offshore development. Infact, regulations could make provisions forredundant facilities to be mothballed for aspecified period of time to avoid impacts fromrebuilding on the site. However, in requiring all

onshore facilities to be sited within the zone,location consolidation prevents expandedindustrialization into other coastal areas. Thechallenge to policymakers is to determine howlarge an area location consolidation needs inorder to be successful and translating that areainto reality, through land use plans andordinances.

OPERATION CONSOLIDATION

Operation consolidation is structured so thatmultiple operators commingle processing at asingle facility or prescribed number of facilitiesat a designated site. In this respect, facilitiesare not only co-located (locationconsolidation), they are co-used. The processof siting and designating these sites is morecomplicated than for a single-operator facility(New England River Basin Commission, 1976).

In Santa Barbara County, when the policyregarding consolidated facilities and sitesbecame fully developed by the mid-1980s, theobjectives for this siting strategy went beyondthe desire to reduce the number of facilitiesand locations and the future demand for thesame. The objectives of operationconsolidation are fairly straightforward. Thesepolicies seek to:

• reduce the number of facilities and thenumber of locations both in the presentand in the future (Anthony, et al., 1991);

• reduce or concentrate environmentalimpacts and reduce cumulative impacts(Callahan, et al., 1987);

• help reduce residual risks to the coastalenvironment (Douros, et al., 1991);

• provide all potential operators with anopportunity to develop resources byavoiding denial of “future development thathas been precluded by projects that haveoccurred at a pace and manner thatprematurely exhausts limited resources”(Callahan, et al., 1987). (Broadly defined,resources includes land for processingsites.)

Consolidation strategies are not necessarilydesigned to limit offshore development activityby restricting onshore processing, althoughthey could theoretically have that effect.Consolidated sites can be sized to allow roomfor additional facilities or expansion of existingfacilities assuring land resources for future


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processing if needed. Encroachment ofconsolidated sites by incompatible land usescan be minimized if a comprehensive planningprocess designates land uses for areasadjacent to the consolidated site.

Santa Barbara County policy regardingconsolidation requires “new” production, to theextent technically and environmentallyfeasible, to be (1) processed at consolidatedfacilities to the maximum extent possible and(2) commingled, that is, production fromseveral operators processed at a single facility,even if throughput has to be reducedproportionately to accommodate newoperators. The policies further restrict theconstruction of additional facilities atconsolidated sites in order to eliminate“redundant facilities.” The authorizedconsolidated facility capacity was determined,in part, by considerations of a future potentiallevel of development.

OPERATION CONSOLIDATIONDECOMMISSIONING

The process of decommissioning either type ofconsolidation will be comparatively morecomplicated than the private system. Similarly,the social and economic impacts from thedecommissioning are likely to be morecomplex. The difference in potential impactsstems from the basic structure of the three.With consolidation, there is a conceptual if notreal separation of “onshore” and “offshore”facility decommissioning and a separation of“facility” decommissioning from “site”decommissioning. Furthermore, a number ofother considerations arise when comparinglocation consolidation to operationconsolidation decommissioning.

For example, operation consolidation mustconsider the impact of multiple users. A singleoperator may decommission offshorestructures, ceasing input into the onshorefacility. This cessation of an operator’s inputmay increase the marginal costs of theremaining users if they do not increaseproduction to maintain a level of throughput.However, in a multiple-user facility it is unlikelythat the loss of any single operator will raisemarginal costs of processing to the point thatcontinued production for remaining usersbecomes economically irrational, especially ifthe throughput was pro-rationed among the

users. As such, decommissioning of offshorestructures need not be causally linked todecommissioning of onshore structures.However, if the facility depends on thethroughput of one dominant operator,decisions regarding decommissioning mayindeed affect the future viability of continueduse by the remaining operators.

The number of stakeholders potentiallyinvolved in consolidation complicatesdecommissioning decisions. The expectationsof facility and site owners, the facility operatorand the facility users (all of whom may bedifferent) as well as the desires of differentlevels of government and the public must betaken into account when making decisionsabout the decommissioning of facilities andonshore sites. One of the long-term publicpolicy questions for operation consolidation is“what is sufficient onshore processing capacityfor current and future production?” Withlocation consolidation the question becomesone of “what is the sufficient onshore area forcurrent and future production?” Given theuncertainties involved in energy developmentthe answer to the questions may be somewhatproblematic.

LONG-TERM SOCIAL ANDECONOMIC CONSEQUENCES OFCONSOLIDATEDDECOMMISSIONING

The answer to the questions considered indecommissioning will be very important since ithas the potential to affect the future economicdiversity of an area. Onshore infrastructureimparts a economic and regulatory bias to thearea in favor of additional development. Theavailability of infrastructure is a factor in afirm’s decision to undertake new or expandexisting operations in an area (Lima, 1994).Decommissioning expenditures have very littleimpact on future economy, that is, employmentcreated by facility removal and restoration is ashort-term benefit. Once the tasks arecompleted the economic benefits of increasedemployment cease. However, expendituresfor maintaining capital infrastructure, such asconsolidated facilities, provide a means ofcontinued tax revenue, employment, and otherpotential economic gains. The attractivenessof maintaining this infrastructure is a decisionthat is made in the light of several factors,

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including compatibility of offshore activity withother values and competing and possiblyincompatible uses.

In an area where operation consolidation is ineffect, careful thought must be given to theconsequences of closure and dismantling of aconsolidated facility prematurely--prior to theexhaustion of possible production in the area.This action may make follow-on productionuneconomic if the remaining producers areunwilling to assume operation of an existingfacility or undertake construction of areplacement facility. If construction of areplacement facility is undertaken, the area willexperience some measure of social andeconomic impacts with the attendant increaseddemand for public services and infrastructurethat characterize the development phase ofoffshore energy projects. In addition, thedecision to decommission facilities and sitesmust be consistent with state coastal policieswhich seek to minimizing industrialization ofthe coastline.

If the purpose of operation consolidation wasto achieve the objectives listed above, thesuccess or failure policy must be evaluated inlight of the extent that impacts from the re-industrialization of the area are prevented,avoided, or minimized. As such, facilitydecommissioning and retention of theconsolidated site must be considered as analternative. Conversely, prematuredecommissioning may hasten the end ofextractive industry in the area in favor of othernon-extractive uses. To the extent that theseother uses can replace the contribution ofenergy activity and not cause greatercumulative development impacts, these mayprove more valuable than continuedencouragement of the offshore industry.

Premature cessation of production could havesizeable impacts on government revenues asvaluable infrastructure is suddenly removedfrom the property tax base of a community.However, the local government revenue fromoffshore energy is more than just the sum ofproperty and sales tax revenues and feescharged the operating companies. In SantaBarbara County, for example, approximately9.7 million dollars has been provided to theCoastal Resources Enhancement Fund(CREF) since 1987 by various offshore energy

projects. These contributions represent anoffset of residual coastal recreation, aesthetic,tourism and other impacts caused by offshoreenergy development that could not bemitigated using other strategies (McNeal-Pfeifer, 1997). In the decade since itsinception, the fund has provided monies tolocal public and not-for-profit organizations fora variety of activities including coastal landacquisition, infrastructure capital and operatingimprovements and recreation programs. Insome cases, The CREF fund provided thematching funds needed to “leverage” greateramounts. Whether or not these programswould have been or could have been funded inthe absence of energy development isspeculative. But, even a cursory examinationof the projects funded through CREF revealsan improvement in the local quality of life thatarguably may not have occurred in theabsence of these offset funds. Furthermore,the synergistic effects of the “seed money” thatCREF expenditures provided has not beenthoroughly examined. When analyzing thelong-term consequences of facilitydecommissioning, the value of the offshoreindustry must be made in light of thecontributions and consequences of that activityand the impact it has on public finance andinfrastructure.The long-term effect of decommissioning mayalso be realized in government operations.The fundamental structure and practices oflocal government has had to change toaccommodate offshore energy development(Lima and Woolley, 1990, 1991; Lima, 1994,1995). Since location and operationconsolidation are mandated by public policies,it stands to reason that decommissioning ofthese facilities will create new administrativechallenges and there will be greatergovernment involvement in thedecommissioning. Also, since consolidation isessentially a government industrialdevelopment policy it is likely that morestakeholders will seek to have their concernsaddressed through public administrative andpolitical forums.

THE DISPOSAL ISSUE

Experience with the deconstruction of facilitiesand disposal of the non-salvageable materialin landfills has not indicated an impact to publicservices and infrastructure. However, there


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may be cumulative effects from the onshoredisposal of materials in light of existing landfillcapacity. Whether or not onshore disposalconstituted a substantial long-term effect woulddepend on the amount of material requiringdisposal in a landfill and the impact that thedisposal has on the remaining capacity oflandfills. California has mandated that localgovernments reduce the amount of materialdeposited in landfills, but the potentialcontribution of decommissioning to the wastestream remains to be estimated.

Dismantling of the Mobil pier onshoreprocessing facilities in Ventura County wasprojected to result in up to 60 truck trips, half toremove debris and scrap from the site and halfto remove used and surplus material (Fugro-West, Inc., 1996). Local landfills capacity wasadequate to handle the debris. Similarly, whenthe so-called “4-H” platforms (Hazel, Hope,Hilda, and Heidi) were recentlydecommissioned approximately 11,000 tons ofsteel were brought to shore at San Pedro,California, and sold as scrap for approximately330,000 dollars. However, ultimate onshoredisposal costs exceeded salvage revenue byapproximately one million dollars. Thecontractor had to handle and dispose of 3,000tons of marine growth, 1,000 tons of cement,and 300 tons of mud at an approximate cost of850 thousand dollars, 275 thousand dollars,275 thousand dollars, respectively (Bafalon,1997). The California State LandsCommission (SLC, 1993) noted that disposalcould constitute the “critical environmentalissue.” Disposal impacts are a factor of howmuch material has to be processed, length oftime needed to break up and dispose of thefacilities, the location of the disposal activity,and whether the disposed elements containedtoxic materials.

The subsequent environmental assessment forthe removal projected noted no short- or long-term effects from disposal (SLC, 1994).

CONCLUSION: FRAMEWORK FORONSHORE FACILITYDECOMMISSIONING POLICY

Limited experience with decommissioningpresents new challenges to decision makers.Presently, clear policy direction does not existregarding the decommissioning of onshoresites. While it is beyond the scope of thispaper to suggest a model policy, a frameworkfor addressing decommissioning should, at aminimum, address the following items:

1. The point at which facilitydecommissioning is triggered (i.e.,cessation of current production, cessationof anticipated production, decline ofthroughput below a specified threshold).

2. The process to be followed to initiatedecommissioning, including provisions forstakeholder input.

3. The mandatory and alternative actions fordecommissioned facilities and sites (e.g.,complete removal and restoration,remediation of contamination, partialremoval of unused equipment, temporarysuspension in anticipation of future need,rezoning of land, abandoning pipelines inplace, etc.).

4. The time frame in which on-sitedecommissioning actions must becompleted.

5. Provisions to ensure financial resourcesare available to completedecommissioning.

6. The requirement for site-specific approvalof actions (e.g., a decommission plan foreach facility and site).

7. A process for considering of the long-termcumulative effects of decommissioning andstrategies to reduce these effects.

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REFERENCES

Anthony, Douglas, William Douros and JohnZorovich. 1991. Land Use Issues Raisedby Offshore Oil and Gas Development.Coastal Zone 91. Proceedings of theSeventh Symposium on Coastal and OceanManagement. American Society of CivilEngineers. New York.

Bafalon, Lee. 1997. Personal Communicationwith James Lima, On file, MineralsManagement Service, Pacific OCS Region,Camarillo, CA.

California Oil Survival Team. 1993.Environmental and Other IssuesConfronting the California PetroleumIndustry. Workshop Proceedings. ICFResources, Incorporated.

Callahan, Catherine, Amy Margerum andSharon Maves. 1987. InnovativeApproaches to Mitigating CumulativeImpacts. Coastal Zone 87. Proceedings ofthe Fifth Symposium on Coastal and OceanManagement. American Society of CivilEngineers. New York, NY.

Douros, William, Bruce Carter, and DouglasAnthony, 1991. Risk of TransportingPetroleum and Other Materials fromOffshore Oil and Gas Development.Coastal Zone 91. Proceedings of theSeventh Symposium on Coastal and OceanManagement. American Society of CivilEngineers. New York, NY.

Francis, Nancy. 1997. PersonalCommunication. Ventura County ResourceManagement Agency.

Fugro-West, Inc. 1996. Dismantling of MobilOnshore Facilities. Production andGathering Lines, Ferguson/Tomson TankBattery, Produced Water Filtering System,West Coast Tank Farm. Conditional UsePermit No. 48. Minor Modification,Execution Plan. On file. Ventura CountyResource Management Department.

Gramling, Robert. 1996. Oil on the Edge:Offshore Development, Conflict, Gridlock.State University of New York Press.Albany, NY.

Lima, James and John Woolley. 1990. SantaBarbara County Response to Offshore OilDevelopment. Proceedings of the AnnualMeeting of the American Political ScienceAssociation. The Association.Washington, D.C.

Lima, James and John Woolley. 1991. SantaBarbara County and Offshore OilDevelopment -- Applicability of the Lessonsto Other Communities. The CaliforniaCoastal Zone Experience. AmericanSociety of Civil Engineers. New York, NY.

Lima, James. 1994. The Politics of OffshoreEnergy Development. DoctoralDissertation. Special Collections.Davidson Library. University of California,Santa Barbara, CA.

Lima, James T. 1995. Life Cycle of a LandUse Planning Agency in California: SantaBarbara County and Offshore EnergyDevelopment. Annual Meeting of theSouthern Political Science Association.

McNeal-Pfiefer, Kathy. 1997. PersonalCommunication on Coastal ResourceEnhancement Fund Expenditures. On file,Minerals Management Service, PacificOCS Region, Camarillo, CA.

Molotch, Harvey and William Freudenburg.1996. Santa Barbara County: Two Paths.OCS Study MMS 96-0036. U.S.Department of the Interior, MineralsManagement Service, Pacific OCS Region.Camarillo, CA.

National Research Council. 1992.Assessment of the U.S. Outer ContinentalShelf Environmental Studies Program.Volume 3. Social and Economics Studies.National Academy Press. Washington,D.C.

New England River Basins Commission.1976. Onshore Facilities Related toOffshore Oil and Gas Facilities: Factbook.The Commission. Boston, MA.


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Paulsen, Krista, Harvey Molotch, and WilliamFreudenburg. 1996. Ventura County: Oil,Fruit, Commune and Commute. OCSStudy MMS 96-0035. U.S. Department ofthe Interior, Minerals Management Service,Pacific OCS Region. Camarillo, CA.

Price, Willard. 1987. Offshore Oil in theCoastal Zone: A role for Seaports. CoastalManagement. 15 3:229-246.

Santa Ynez Unit OS&T Abandonment. U.S.Department of the Interior, MineralsManagement Service, Pacific OCS Region.Camarillo, CA.

SBC. 1987. Exxon Santa Ynez Unit FinalDevelopment Plan, No. 87-DP-32cz,Conditions of Approval. Santa BarbaraCounty, California, Resource ManagementDepartment, Energy Division. SantaBarbara, CA.

SBC. 1996. Santa Barbara County,California. Oil and Gas Abandonment.Offshore Oil and Gas Status Report forSeptember 1996. Planning andDevelopment Department, Energy Division.Santa Barbara, CA.

SBC. 1990. Santa Barbara County,California. Proposed Rezone of Oil andGas Facility Sites, South CoastConsolidation Planning Area. ResourceManagement Department, Energy Division.Santa Barbara, CA.

SCEI. 1991. Southern California EducationalInitiative. Socioeconomics Workshop.Workshop Report. OCS Study MMS 91-0012. U.S. Department of the Interior,Minerals Management Service. PacificOCS Region. Camarillo, CA.

Schweithelm, James and Michael McPhee.1983. Onshore Effects of Oil and GasDevelopment. Technical EnvironmentalGuidelines for Offshore Oil and GasDevelopment. Edited by John Gilbert.Pennwell Publishing Co. Oklahoma City,OK.

Seydlitz, Ruth, John Sutherlin, and SamanthaSmith. 1995. Characteristics and PossibleImpacts of a Restructured OCS Oil andGas Industry in the Gulf of Mexico. OCSStudy MMS 95-0055. U.S. Department ofthe Interior, Minerals Management Service,Gulf of Mexico OCS Region, New Orleans,LA.

SLC. 1993. California State LandsCommission. File Memo. File No. 40654.Chevron Carpinteria PlatformAbandonment. Meeting to Discuss CEQAApplication. August 13, 1993. TheCommission. Sacramento, CA.

SLC. 1994. California State LandsCommission. 1994. CaliforniaComprehensive Offshore Resource Study.Volume 1. The Commission. Sacramento,CA.

SLC. 1994. California Sate LandsCommission. Notice of Public Review of aProposed negative Declaration. FileW40654 ND652. Removal of Offshore OilPlatforms Heidi, Hilda, Hope and Hazel.May 9, 1994. The Commission.Sacramento, CA.

Thayer, Ralph and Charles Hadley. 1990.The Impacts of the Recession in OuterContinental Shelf Activity on the Provisionof Public Services by State and LocalGovernment in Coastal Louisiana.Proceedings of the Eleventh Annual Gulf ofMexico Information Transfer Meeting. OCSStudy MMS 90-0040. U.S. Department ofthe Interior, Minerals Management Service,Gulf of Mexico OCS Region, New Orleans,LA.

UCSB Economic Forecast Project. 1997. TheEconomic Contribution of the Oil and GasIndustry in the Tri-Counties. WesternStates Petroleum Association. SantaBarbara, CA.

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SUMMARY AND RECOMMENDATIONS

Technical Session ................................................................................. 137

Environmental Session ......................................................................... 140

Disposition Session............................................................................... 145

Summary and Recommendations

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TECHNICAL SESSION:SUMMARY AND RECOMMENDATIONS

MARINA VOSKANIAN and DR. ROBERT BYRDSession Co-Chairs

Russ Schmitt: Now we will hear from MarinaVoskanian. Marina will give an overview of thetechnical sessions work group report.

Marina Voskanian: Thank you Russ. GoodMorning ladies and gentleman. I am sopleased to see such an overwhelming interestfor this workshop over the last two days. Wehad a technical program with several peoplecontributing to that session. I would like tothank every one of them. Thank you to theLeague of Women Voters, they had a greatinput in our session. We heard fromSurfriders, the County of Santa Barbara. Ofcourse the members from SLC and MMS,Department of Conservation, Division of Oiland Gas, American Pacific Marine,Twachtman, Snyder and Byrd who had a greatrole in organizing this session, Frugal andothers.

During our technical session that wasconducted Tuesday afternoon we receiveddifferent options available and type oftechnology generally used to accomplish thedecommissioning and removal of offshorefacilities in environmentally safe and efficientmanner. This session as you saw wasoriented toward informing the public and non-technical personal on plugging the wells, thecommissioning of topside, productionequipment and debris jackets, pipelines andcables. The site clearings and verification, andonshore facilities clean up and removal werealso discussed. There were two to threeissues that arose during that technical sessionand I would like to invite my co-chairman BobByrd to address those issues. Thank you.

Bob Byrd: There were at least two issues andprobably others, but there were two thatjumped out at us, that we felt deserved somecomment. The issue of structural longevity, orrather the prospect of leaving decommissionedstructures in place was discussed on severaloccasions during the last day or so. We feltwe needed to comment about therequirements for leaving a structure in place.

In particular the maintenance requirements ofthese structures. Offshore platforms arerelatively high maintenance issues in terms ofmaintaining their structural integrity. Many ofthe platforms offshore California haveimpressed current cathodic protection systemswhich prevent corrosion and deterioration ofthe structural steel. Something to replace thiswould likely be required if the topside wereremoved and electrical power generation orattached power cables from other facilitieswere removed. There are possibilities of otherpassive forms of cathodic protection, butwithout some cathodic protection theseplatforms would deteriorate very rapidly. Thisissue needs to be considered in leaving theseplatforms in place.

The other comment that we want to make isthat there is a fair amount of anecdotalevidence that structures which are submergedwell below the splash zone or free surfacewould have a very long life. There are anumber of places in the world where you cansee ships that have existed for fifty to onehundred years and are still in relatively goodcondition. The offshore platforms which youare looking at out here have much heaviersteel than a ship’s so I think you can make apretty strong argument that they would bearound for a long time provided there was nocontact with the air-water interface.

The other issue we want to comment about isthat of the possibility of refloating jackets. Wehad made some comments responding toquestions from the audience that it would bevery difficult using conventional means to pickup one of the large structures here, move itinto either a shallow water site or a deep waterdisposal site. Technically that is a very difficultthing to accomplish. Afterwards Bill Griffinreminded me of a presentation we both sawthis last spring at Aberdeen at adecommissioning conference related todevelopment of external buoyancy packageswhich can be attached to platforms. While thisis something that is in an early state of


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development, it turns out after putting a fewnumbers on paper that in fact it does appearthat it is something that may be feasible withmore development. This type of removaltechnique would have a very significant impacton the options available for the disposition ofjackets. It would affect the feasibility of deepwater disposal. It would affect the feasibility ofshallow water reefing of an entire jacket. Itwould affect the feasibility of removing a jacketas a single unit to a distant disposal site ofwhatever type you choose.

Finally we were approached this morning withthe comment that we really do not give a greatdeal of consideration in the technical sessionto the reuse of facilities offshore California. Ithink that is a fair comment. In looking at theprospect of reusing of the California facilities, itis a little problematic for us to generate a lot ofenthusiasm for the possibility of reusing thefacilities in a context of an environment wherethere is not a lot of ongoing development. Ifyou look at the Gulf of Mexico market platform,jacket and facility reuse has gotten to be verypopular. Probably 25% of the jackets orfacilities historically have been reused.Today’s market with increased activity thatpercentage is probably increasing. In thecontext of California decommissioning what islikely to happen would be that individualcomponents from facilities would be reused.For example generators, production modules,or perhaps quarters packages. Today it wouldbe likely that these would be reused in distantmarkets, perhaps in Southeast Asia, SouthAmerica, or other areas. It seems unlikely thattoday there would be a great deal ofopportunity to reuse these facilities inCalifornia. Although that situation maychange. Thank you.

TECHNOLOGICAL SESSIONSUMMARY & ISSUES

1. Session Summary:

The technical sessions reviewed optionsavailable and the type of technology generallyused to accomplish the decommissioning andremoval of offshore facilities in anenvironmentally safe and efficient manner.This session was oriented toward informing thepublic and non-technical personnel in generalon the decommissioning process. Emphasiswas on explaining the various steps and the

options available. Specific areas covered inthe session were: plugging of wells and thecleanup and disposal of production equipment,related structures, pipelines and cables.Offshore site clearance and verification andonshore facility cleanup and removal were alsodiscussed.

2. From this session’s questions and thegeneral discussion during theworkshop, the following issues deservecomment from a technical perspective:

• Structure Longevity

Structures left above the water line willrequire significant and continuousmaintenance to insure their long termsurvival. The air/water interface creates agalvanic cell which accelerates corrosionunless cathodic protection is provided.Many California platforms have impressedcurrent cathodic protection systems whichrequire electrical power to operate. Thiswould not be easy to provide ondecommissioned platforms. Passivecathodic protection systems, which arefound on some structures, generally havea life of approximately twenty years.These systems would require anodereplacement on a continuing basis tosurvive, along with maintenance paintingof exposed surfaces.

There is significant evidence that steelstructures submerged well below thesplash zone (water surface) would havevery long life. Steel ship hulls have beenfound in relatively good condition afternearly one hundred years submergence.Offshore platforms have much thicker steelplate in their structures than do ships.

• Jacket Removal

There is ongoing development related toexternal buoyancy systems which maymake it feasible to re-float jackets in asingle piece. This will have significantimpact on the options available for jacketdisposal, such as deep water disposal,shallow water reefing and towing to distantdisposal sites. It is reasonable to assumethat this technology will be developed inthe near future as the demand for itsapplication dictates.


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• Facility Reuse

Questions concerning the feasibility ofreusing all or part of offshore facilities inother oil and gas industry applicationsarose in discussions. This issue was notaddressed in any significant detail duringthe session, primarily due to timelimitations. In closing we wish to makethe following observations concerning thissubject:

1. While reuse of oil and gas processingfacilities is becoming very popular in someareas such as the Gulf of Mexico, it seemsunlikely that there will be an opportunity todo much of this offshore Californiabecause of the limited amount of newdevelopment that is anticipated.Processing equipment that is brought toshore will be screened and the mostvaluable items will be transported to otherareas for reuse. The remainder will bescrapped.

2. Complete process modules may be used

in some cases where it is practical toremove them intact and transport them to

the new application area for refurbishmentand reinstallation.

3. In general it will not be feasible to reuse

jacket structures because of the difficulty inpicking them up and transporting them to anew site for reinstallation. However, newtechnology may make it possible to do thisin specific cases if new developmentsoccur offshore California where thetransport distance is not great and thewater depth is similar.

4. New technology may make it feasible in

the future to remove an entire topsides(processing equipment and supportingstructure) and transport it in a single pieceto a new site. This has recently beendemonstrated with a 1200 ton offshorefacility topsides in the Gulf of Mexico.Most of the topsides offshore California areconsiderably larger than that, but the newtechnology is promising.


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ENVIRONMENTAL SESSION:SUMMARY AND RECOMMENDATIONS

SIMON POULTER and BILL DOUROSSession Co-Chairs

Russ Schmitt: Now it is time for the Dourosand Simon show. They will be talking aboutthe environmental workgroup session andreport.

Simon Poulter: Thank you. I would also liketo just briefly thank everybody who participatedin planning and participated in our session.There were a number of meetings that wereheld over almost a year period of time to pulltogether the panel as well as the user groupsthat expressed their insight on varioustechnical issues. We have sat down and spenta lot of time and I really want to appreciateeveryone that has participated in that process.I also found the experience that Bill and I hadyesterday I think has been repeatedthroughout the conference. We were actuallya little disappointed after our session that thequestions seemed to jump to the afternoonsession. A great deal of the comments weremade in regard to that. We felt that we werenot getting a lot of feedback. Bill and I steppedoff to the side after the last session and werehoping to spend fifteen minutes summarizingthe result of our session. We promptly got intoa huge argument with each other about whatthe conclusions were really going to be. Werealized that the session had touched on manyof the issues that had been raised in previousenvironmental documents and reviews ofworks. I don’t want to say that we got into aknock down drag out, but I think it was a veryvaluable experience. I know that I have had anumber of conversations with other individualsduring this conference about particulars onother individual’s projects. I think that is thevalue of the session. It is that we have beenable to touch on those issues.

The second kind of observation that has beenmade is that the communication has been verypositive. We have seen in most of thesessions groups that don’t talk to each other sitside by side after making some commentsabout each other. I think that is a veryvaluable experience. We really saw that as apositive exchange of open ideas and will

hopefully continue that dialogue after thesession.

Going into it briefly, the overview of thediscussions made by our speakers wesummarized here in bullet format. I will touchbriefly on some of the comments becausesome of you cannot see the overhead from theback. Peter Cantle discussed air quality. Ithink his major message was that air quality isa major changing issue for anydecommissioning project, and that we arecontinuing to see a lot of dialogue going onamong the state and federal agenciesregarding what will be required fordecommissioning projects and that the factthat the seasonal issues of ozone are going tohave an impact on some of the larger projectsthat we see in the future. He concluded thatfewer activities proposing to leave parts of thejacket in place will result in less emissions, butthat was kind of a given in many of ourdiscussions. I think less physical activity, lesspotential impacts. That does not address thepotential disposition issues obviously and thatwas touched on. Commercial and recreationalfishing preclusion is obviously the biggestissue in that regard and recognizing there aregoing to be seasonal constraints onceoperations occur, particularly if there are largerderrick barges that were going to go into that.Fisheries research indicates that there areeffective methods to reduce potential impactsto fisheries resources during abandonment.We do recognize that there is some impactfrom especially explosive uses, but those useshave been identified as being less significantwhen you consider the overall commercialfisheries catches in both the Gulf and I thinkcan be extrapolated out to the California coast.

Peter Howorth in discussing marine mammalsidentified that there are very effectivemitigation measures in place that have beenimplemented on a number of projects thathave resulted in effective reduction of impactsto marine mammals.


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Bill Douros: As Simon mentioned, while itseemed that we were not in agreement onsome aspects of all of the presentations whenwe met last night to talk about what we weregoing to summarize, that is the firstdisagreement we have had in our eight monthrelationship. What is often an air qualitymitigation measure to prevent ozone is toschedule the project during seasons when youare less likely to, through the naturalprocesses of the sun and temperaturegenerate ozone by the emissions that occur.That means you do as much of the work youcan in the winter time. The winter time is whengray whales migrate and so you can obviouslysee that there is immediately a conflict with twovery important issues to abandonment. This issomething that has come up on theconstruction end of the projects, and this issomething that is going to come up on themajor abandonment projects too. We aretalking about a lot of emissions, a lot offacilities in an area that is very important tomarine mammal migration routes, especially inthe winter time. This is an issue that needs tobe resolved as time goes on.

Simon Poulter: Ray deWit presented anoverview of marine benthic organisms. Inreference to Ray’s talk, our conclusion wasthere was a short term loss of habitat whenyou remove a structure. Then the questionwas raised, is that significant? Is that going toresult in a long-term loss of habitat for theseorganisms? I think there were still somequestions in our minds at the end of hispresentation that we could not resolve and Iwould be interested to hear how othersinterpreted some of the statements he made.The issue was that you will initially lose thathabitat, the hard substrate that manyindividuals have indicated is a limited resourcein the Santa Barbara Channel in particular, butthat natural recovery will occur. Well how fastwill it occur? Is that going to be a naturalsuccession? Will it be the same species? Allof those issues still are out there. We haveseen in some of the flow line abandonments inparticular that issues have been raised and arestill being debated among the agencies.

Water quality, Pete Raimondi gave a veryinteresting presentation and I guess I was alittle lulled by the second slide. This slide saidless than significant and I wrote it off. Thatwas one of our bigger discussions because the

rest of his presentation presented an overviewof the potential issues that we need toconsider. That we, well, don’t see anythingunder certain parameters, but if we look atother parameters that we are maybe notlooking at, such as biological communitiesthere may be an impact, but we do not know.So....The warning went up. I admit I missed it.

Frank DeMarco got into clean up standards ofonshore facilities. A new issue that has beenraised is that an applicant does have the abilityto identify a lead agency. In my briefpresentation I showed you in a slide that thereare potentially a lot of lead agencies issuesregarding a project that has OCS state watersand onshore components that can result insignificant problems. Future land use issuesare going to drive risk-based assessment onwhether we are going to remediate a siteimmediately and result in some excessiveexcavating of a site or bioremediation project.That may result in secondary impacts for futureuse.

Our last speaker I think brought up some verykey issues tied back to that cleanup issue.Kim Schizas talked about future uses of thesites. In Santa Barbara County and southcounty you have two consolidated sites thathave the potential of having multiple operators.We are seeing proposals for potentiallyshutting down one of those facilities. That mayresult in a need to look at whether it isappropriate to “moth ball” that facility and waitfor the next operator to come in , or removeportions of it. Those issues do need to look atfuture land uses of do we restore a site to anatural condition, revegetate it? We also haveto recognize that a lot of these facilities arelocated in areas which are very attractive forfuture development. The Arco Dos Pueblosgolf course is such a situation where we aretaking an oil field and moving it directly into arecreational facility instead of maybe back to anatural condition. Now I will turn it over to Billto go into our recommendations.

Bill Douros: One thing I would like to pointout before we move on is from thecomments made by the ocean users groups.The folks who gave five minutepresentations at the end. We would like tosummarize that there are obviouslycompeting uses and perspectives onwhether or not there are environmental


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impacts and the magnitude of theenvironmental impacts from the act of doingdecommissioning. There was an interestingpoint brought up on air quality. On a recentproject they finally had resolved throughlitigation the mitigation that was necessary.Rules changed after that through newlegislation and it added a perspective for methat I had not quite seized prior to thispresentation. The one common theme fromall of them was communicate! I think all ofthe speakers mentioned that as somethingthat is absolutely essential. One other pointtoo was that, as I mentioned in the openingremarks on the first day, we try to present toyou issue areas for environmental impactsthat will result when you do adecommissioning project. That does notmean though that there are not otherenvironmental impacts that typically result.Most of the environmental impact reportswhen these projects were built includedperhaps no more than a page in the 300 to400 pages of the environmental analysis thatsaid the impacts for abandonments anddecommissioning will be roughly the sameas the impacts for construction. One of theissue areas that comes up often duringconstruction is the change in the visual andaesthetic characteristics of typically a ruralcoastline, impacts to recreation andenjoyment of recreation, tourismopportunities, because of that perceivedindustrialization. While that will occur duringabandonment and decommissioning, part ofour view as to why we did not want topresent that necessarily, it is often toodifficult to quantify. An oil rig to some lookslike many positive things and to others lookslike many negative things. Decommissioningprojects may look bad to those that likeplatforms and good to those who do not likeplatforms and it is very difficult to try andquantify. That is why we stayed away from itin this presentation/workshop. We wanted tomake sure that people did not loose sight ofthe fact that those are still issues.

Okay, the recommendations then. There areat least five things that jumped out at us aseither research tasks or think pieces. Thefirst is regarding air quality. What are theoffsets and other mitigation measures thatmight be viable as mitigation to air emissionparticularly if the legislation has changed thatmakes a certain class unacceptable.

Secondly, and this is what Simon touchedon, what is the effectiveness and rate ofnatural recovery for marine benthic impacts?You certainly lose habitat. You have animpact to those organisms that grow on aplatform when you take it out, but what doesthat matter? Is it 1/10th of 1% or 10% of anavailable habitat in an area? Also is it goingto recover naturally? Anthropogenicrestoration in 600 feet of water is, I am sure,more difficult then even getting the structureout in the first place. So a lot of themitigation, the recovery of those impacts, isprobably going to have to be natural. Weneed to know if that is really something thatis effective and how fast can that comeabout.

This concept in water quality impacts thatPete Raimondi talked about, informedintuition. I think most people that studythese sorts of things might agree, geez....yaknow... a barrel of oil spilled during a cleanup is kind of hard to consider that asignificant impact to marine water quality.An interesting aspect of Pete Raimondi’s talkwas that for another project where theythought they were measuring the rightphysical characteristics they concluded thatno significant impact would have occurred atten meters when really there might havebeen an effect 1000 meters away. So theremay be some additional assessmentwhether it is research or thinking that needsto be done there.

The fourth one did not necessarily come upin our presentation but became obviouswhen the fish folks talked in the afternoon.What happens to the fish when you take theplatform away? Do they go back andpopulate existing reefs? Do they all getcaught by fisherman? Do they all get eatenby sea lions? What happens to them?

Lastly the planning for the future land use foronshore facilities ought to start right away.That is based on what Kim Schizas had totalk about. Jim Lima, I think, emphasizedthat a bit in the afternoon, too.

The second recommendation is that existingmitigation measures that we know workought to be required. There are a number ofthose for marine mammal impacts forinstance. Yet we should continue to work to


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improve those that we know work and thosethat we know do not work as well as we liketoo. There is always room for continuousimprovement.

Lastly we recommend that whenenvironmental impact reports for newdevelopment are prepared, should that evercome about in the future. Thoseenvironmental impact reports need to do abetter job of evaluating the impacts ofabandonment and decommissioning.Another question is how long are thesefacilities going to be out there? No oneenvisioned the Point Arguello project wouldbe taken out within ten to eleven years, butthat may be an important aspect of thedecision-making in the future.

I think what we are also getting athere, is that when you write an EIR that is 400pages long about the impacts of constructingand operating a project a couple of paragraphsthat just sort of summarize that the impacts willbe roughly the same probably is not doingjustice to it, particularly when there are sometechnical limitations to even how you takesome of these facilities out. We are seeingthat now and that is twenty-twenty hindsight.Anything else to add?

Simon Poulter: I just want to point out that Iam sorry we drifted into the disposition, butyou all did so we had too. I think thequestion of what happens to the fish and theimpacts associated with the construction ofthe facility does have to recognize that if weare talking about a structure becoming a reefnow, not only do the engineers need toconsider that structure in their design, butalso we have to recognize that it may have apotential long-term beneficial impact if it isproperly designed and sited for that purpose.That concludes for us. Thank you.

SESSION REPORT

Major Observations

1. Comments and questions from audiencefocused on disposition issues and it is hardto make conclusions with so little feedback. Observations and conclusionsbased on the speakers are provided

below.

2. Open communications were emphasizedby the speakers, user groups and public.

Speakers

Air Quality - Peter Cantle• Air Regulations are continuing to

change. Such changes will affectfuture projects.

• Fewer physical activities means feweremissions and therefore less impacts.

• How to mitigate air emissions impactsis unclear.

• Seasonally scheduling (avoid Ozoneperiod) may push project scheduleswhen you factor in biological seasons(i.e., gray whale migration).

Commercial and Recreational Fisheries - CraigFusaro

• Removal activities result in preclusionfor both commercial and recreationalfishing operations.

• Less removal activity means lessimpact.

Fisheries Research - Villere Reggio• Explosives use does result in fish kills.

In the Gulf of Mexico this representsless than 1% of the total commercialfish catch annually.

Marine Mammals - Peter Howorth• Existing mitigation measures have

been tested during actual projects andhave been shown to effectivelyminimize impacts to marine mammals.

Marine Benthic Organism - Ray de Wit• Removal of structures will result in

short-term loss of habitat andassociated organisms.

• Less removal will result in less impacts.• Upper 200 feet are most productive.• Natural recovery timeframe is not clear.

Water Quality - Peter Raimondi• Impacts are less than significant if they

follow established procedures.• Results are based on literature and

observations but not on fieldverification.

• Caution in his message.


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Cleanup Standards - Frank DeMarco• Applicant can pick lead agency for

cleanup levels (not CEQA).• Risk based clean up levels - tied to

future land uses.• No standard clean up levels have been

established (case by case).• Secondary impacts must be considered

for cleanup activities.

Future Land Use - Kim Schizas• Questions must be asked

⇒ Can the site still be used by otheroperators (Consolidated sites needmore review)?

⇒ Is restoration/recontouringenvironmentally preferred?

⇒ If not, what is the best reuse for thesite?

• We must start planning now.

RECOMMENDATIONS

1. New research or “Think pieces” may beneeded: a. What are offsets or other mitigationfor air emissions? b. What is the effectiveness and rate ofnatural recovery for marine benthicimpacts? c. Is the “Informed Intuition” thatdecommissioning causes no significantmarine water quality impacts accurate? d. What is the fate of fish that lived atthe platform once it is removed? e. Planning for future land use(onshore) needs to begin immediately.

2. Existing mitigation measures that we knowwork must be required; continuousimprovement for all mitigation must besought.

3. Environmental Impact Reports for newdevelopment must do a better job ofevaluating impacts of decommissioning,including assessing what is the “life of theproject.”


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DISPOSITION SESSION:SUMMARY AND RECOMMENDATIONS

DR. MARK CARR and DR. JOHN STEPHENSSession Co-Chairs

Russ Schmitt: The last workgroup sessionwas on disposition and Mark Carr will givethe summary report from that session.

Mark Carr: Thanks Russ. There weremany issues raised during the dispositionsession thanks to the excellent and greatlyappreciated participation by a wide breadthof both stakeholders and agencies. Wehave tried to summarize these issues in theform of recommendations listed here on theoverhead. If we have omitted any issues ofparticular concern please bring them upduring the public response period. Therewere so many issues raised it was very likelywe may have omitted some issues that somestakeholders are particularly concernedabout.

The first one of these which in the pastcontinued to rear its ugly head is the liabilityissue. Given that issue our firstrecommendation is to please try and resolvethis liability issue. Critical to that isunderstanding or determining who is going tobe responsible for these structures once theyare decommissioned at sea. This isparticularly complex off the coast ofCalifornia because decommissioning ishighly likely in either federal or state waters.Depending on where that decommissioningoperation takes place may influence who willbe liable for those structures. Important tothe liability issue is identifying the risks thatone might be liable for, and so a riskassessment would be very useful. That riskassessment needs to take into considerationall the various decommissioning options thathave been identified during the workshop.

The second issue is to determine or at leastclarify the lead agency in the dispositionprocess at both the federal and state level.And to recommend further that this leadagency take a pro-active role in establishinga framework for this disposition process,rather than waiting for a request for a permit

before a framework is established.Particularly important is to define theobjective of the decommissioned structure.For example whether it is going to be afishing reef, a harvest refuge, a mariculturefacility for fisheries enhancement in general.Clarification of these objectives will probablyinvolve further development of the artificialreef programs both at the state and federallevels. That will determine the role of thesestructures in a state or federal wide artificialreef program. All of this is to hopefully avoidthis idea of materials of opportunity waggingthe tail at the disposition process. There isconcern expressed that you do notdecommission a structure simply because itis there, but so that it fulfills a particularpredetermined objective such as fisheriesenhancement. Another issue that keptcoming up and was addressed by someindividuals, but I think there is still somequestion. Is there a window or is there anoption for deep water disposal of thesestructures?

The forth issue, and from a scientific andfisheries prospective....one future and criticalresearch objective is to collect moreinformation on the comparative performanceof organisms of the platforms and on thenatural reefs. This is particularly important tothe fisheries enhancement objective whichwas frequently raised. Milton and Ipresented scientific information, but I hopewe did not give anyone the impression thatwe know all the scientific answers todecommissioning options. Particularlyimportant is understanding how well animalsdo on these artificial structures relative tohow they do elsewhere in natural habitat.

The fifth issue is to investigate the ecologicalrole of these shell mounds. Shell moundscontinue to be a contentious issue in thisprocess. We need to understand thedynamics and persistence of the habitatitself, the physical structure of these


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mounds. How that will change in anabsence of a continued fall of litter from thestructure above? And also again to assessthe performance of the biota on thesemounds with a comparative regionalapproach. How well do these things do inthese habitats relative to other habitats?

If these structures are to be decommissionedat sea certainly it was recommended and thescientific evidence supports the concern thatthey be done by a case by case process.The regional variability in environmentalconditions and biotic communities suggeststhat each of these structures may play a verydifferent role depending on the organismsassociated with them and the surroundingenvironment. That suggests we cannotgeneralize any particular strategy for all thestructures off the California coast, but ratherwe need to take those regional details intoconsideration.

It was also recommended, I think this was anexcellent recommendation by the presidentof Get Oil Out, that we consider anexperimental approach to this dispositionprocess. As a scientist I think I have adifferent definition of “experimental” thanmost people in this room. I think an accurateway to consider this is as an adaptivemanagement strategy. In other words let’snot make the mistake that has been made inthe past with other artificial reef programsand just put these things out. Let’s learnsomething as we do it. As we put thesethings out let’s do so in a manipulativemanner. So we learn about the role of thesestructures as we do it. That needs to bedesigned well ahead of the artificial reefprocess. This would require a comparativeregional approach and evaluation. I cannotstress the role of evaluation anymore! Yousimply do not conduct some kind ofmanagement strategy without assessing orevaluating the success or consequence ofthat strategy. If we are going to get involvedin decommissioning let’s make sure weincorporate a process for evaluating theeffects of that process.

In the process of decommissioning a seriesof steps could be considered. First considerthe likelihood of that structure meeting thepredetermined objective where it currentlystands. Will it meet the predetermined

objective and if not can that objective be metwith some kind of augmentation of thathabitat? Dave Parker spent quite a bit oftime explaining what kind of augmentationmechanisms might be involved. If it cannotin place or with augmentation meet a givenpredetermined objective, can it be metelsewhere? If so then let’s think about whatwe need to know in order to place theseartificial reefs in a different environment or ata different location. Several stakeholderheads suggested that if these things aregoing to be left in place please leave theentire structure including some topsides inplace. I think that needs to be consideredmore, and if not can they be buoyed toprevent commercial trawlers from hangingup on these things.

The seventh issue or recommendation is toidentify those stakeholders that are impairedby each one of these options and for eachcase, and to consider collectively with thestakeholders, with the public, and among theagencies how we can compensate for thosenegative impacts.

The eighth issue is to decommissiononshore facilities simultaneously. If it cannotbe simultaneously at least do it in a timelymanner so we do not have this lag responseof decommissioning or restoring onshorefacilities as we have seen in the past.

The final recommendation is greatercooperation between industry and research.I think all of us were impressed by BillGriffin’s presentation for the globalimportance of the activities that occur on ourcoast. We often heard frequently theimportance of science-based decisions. Ifthe global industry wants to further explorethe concept of disposition at sea they needto impress upon the local industry theimportance of this cooperation betweenresearchers and industry in order to enhancethe likelihood of science-based decisions.Having said that I should mention though inmy own experience particularly with thecompanies we have worked with, PacificOffshore Operators, Torch, and Unocal wehave received outstanding cooperation.However I think that this needs to beimpressed upon the local oil community aswell. Thank you.


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DISPOSITION SESSIONISSUES & RECOMMENDATIONS

• Resolve liability issue- who is responsible for structuresdecommissioned at sea?- State vs. Federal waters.- risk assessment (by option).

• Determine lead agency at both Federaland State level

• Define objective of a decommissionedstructure(s)

- e.g., fishing reef, harvest refuge,mariculture facility.- artificial reef program developmentat state and federal level.- avoid “materials of opportunity”wagging tail.- is deepwater disposal a viableoption?

• Collect more information oncomparative performance of organismson platforms and natural reefs(putative fisheries enhancementobjective)

• Investigate ecological role of shell

mounds- dynamics and persistence of habitatcharacteristics.- assess performance of biota withcomparative regional approach.

• If decommissioned at sea…- Case-by-case.- “Experimental” approach (AdaptiveManagement), i.e., LEARN as you DO.- comparative regional approach andevaluation.- consider likelihood of meetingobjective in place.- can objective be met withaugmentation?- is objective best met elsewhere?Can entire structure (including sometopside) remain?If not, buoy?

• Identify those stakeholders impaired byeach case

Collectively consider how tocompensate for negative impacts.

• Decommission onshore facilitiessimultaneously or timely

• Greater cooperation between industryand research

Industry needs to “think globally, actlocally.”

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AGENCY PANEL DISCUSSION

Agency Panel Discussion

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AGENCY PANEL DISCUSSION TRANSCRIPT

This text was transcribed from audio tapes of the workshop. There are a few gaps in the transcriptcorresponding to times when the tapes ran out and new ones were inserted.

Russ Schmitt: Good Morning. Today we aregoing to begin with a summary of the sessionco-chairs’ discussion yesterday. We will thenturn to a panel discussion with representativesfrom federal, state, and local agencies. Tobegin the discussion agency representativeswill start with a five minute reaction of whatthey have heard, both from the presentation ofsession chairs, as well as the rest of themeeting. This in turn will hopefully frame adiscussion from the audience.

Agency Representatives:Federal Agency Representatives• Richard Schubel , Chief, Regulatory

Functions Branch, U.S. Army Corps ofEngineers, Los Angeles District

• Dr. Lisle Reed , Regional Director,Minerals Management Service, PacificOCS Region

• Maureen Walker , Deputy Director, Officeof Ocean Affairs, U.S. Department of State

State Agency Representatives• Susan Hansch , Deputy Director, Energy &

Ocean Resource Unit, California CoastalCommission

• Bob Hight , Executive Officer, CaliforniaState Lands Commission

• Brian Baird , Ocean Program Manager,California Resources Agency

• Peter Bontadelli , Administrator, Oil SpillPrevention and Response Office,California Dept. of Fish and Game

Local Agency Representatives• John Patton , Director, Santa Barbara

County, Dept. of Planning andDevelopment

• Nancy Settle , Manager, RegionalPrograms Section, Ventura County,Planning Division, ResourcesManagement Agency

Russ Schmitt: At this point I would like to askeach of the agencies to give a short reaction tothe material they have heard, therecommendations, and the summary of theworkgroup sessions. We will start with thefederal agency representatives and in

particular Dr. Lisle Reed, the Regional Directorof the Minerals Management Service of thePacific OCS Region.

Lisle Reed: Thanks Russ. I would first of alllike to say thanks to all the presenters. I wasreally impressed with the amount ofinformation and the issues. I am alwaysastounded by these workshops because thelonger I sit there, and the more I hear, themore I realize how much I do not know. I feelthat even by today we have only had chapterone. We have a lot more work to do, a lotmore things to find out, and a lot moreevaluation work ahead of us. I appreciate alsothat the speakers who have presented issuesover the past couple of days have been verybrief. We had to get a lot of information doneand we had to get it done in a hurry. Peopletherefore had to bottom line things andsummarize. I appreciate the fact that issueslike protecting marine mammals, air quality,water quality, those are doable things. We canprotect those, but I do not want to pass overthe fact. I want to acknowledge fully in front ofeveryone that there are a lot of details herethat will have to be worked through. This willbe very tedious and will take a lot of time, andinvolve most of us at this table and our staffsetc. If we do do something exotic like sometype of attempt at a reef or something like that.The ocean users, I am talking mostly aboutcommercial fisherman. They have the veryright to expect at a minimum that we wouldtake into consideration their concern for safetyand their equipment, and insure fully that thatis taken care of.

The public I think has the right to expect in thebase case that these facilities out there in thewater upon decommissioning could beremoved and the site returned to whateveruses are appropriate. I think that in fact is thelaw and that in fact in the base case is what wewould expect to achieve for the public. I thinkthe public also has the right to expect that ifthere are some other things that could bedone, if there are other good ideas, and it mayresult in significant or worthwhile enhancementof the resource or enhancement of the values


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of the surrounding community and state, thatwe should take a look at it. We should reviewit. We should along with our state, federal,county, and government partners, along withthe public, make decisions that are appropriatefor the situation that arises. So we will do that!I will speak for Minerals Management Service,when we entered into this venture with StateLands to take a look at the decommissioningpolicy and procedures. It was our hope tojointly work up a set of protocols and standardsand procedures that would be amenable toboth the federal and state agency, and wouldgive the people of the communities and thestate the confidence that what goes on out infederal waters will be at least of the quality thatgoes on in state waters. It looks like that giventhe type of platforms we have out in the federalwater that the substantial depth we are talkingabout here, again California is going to be onthe cutting edge. We are going to be the trendsetters and I guess we are dealing with somepretty unique stuff. Nevertheless we willcontinue to work hand in hand with StateLands as we do on many other projects. Wewill work towards a set of criteria and commongoals that will be mutually shared. We willdiligently work with the Coastal Commission,with Cal Fish and Game, which I think has amajor say in this whole issue, and certainly theCounties of Ventura and Santa Barbara, andthe ultimate decommissioning and disposal ofthese platforms. We will try to define aprogram that could involve some moreresearch and evaluations. We will develop aprocess that will bring the public into it and wewill march down that road together. That willeventually allow us to reach a decision that isto the best interest of the general public. Thatis where I am at this point, and I have no ideawhat the ultimate answer will be.

Russ Schmitt: Thank you Lisle. RichardSchubel will give us his reactions now.Richard represents an agency that will beanother major player in this process, the ArmyCorps of Engineers.

Richard Schubel: We are sort of a differentplayer. I apologize, I wanted to attend, butcould not attend, we are facing the so calledcrisis of El Niño in the LA area. So that iswhere our energies have been directed.Basically our role, being a permitting agency,we have to comply with the Clean Waters ActSection 404 and the Rivers and Harbors Act

Section 10. What we attempt to do is take animpartial view. What drives our final decisionor the direction of the permitting process is theproject description. If you have shell moundsinvolved then it goes under Section 10. Thetrue players are really the EPA. The finaldecision is really consensus building. Weneed to look at an array of alternatives.Generally we have to select the leastdamaging alternative. Now our role as far asNEPA. How we come into this document, is todetermine if an EIS is required. We generallygo through an Environmental Assessment.That is our first document and that willdetermine if an EIS is needed. From theproject description we will also determine if wewill be the lead agency, the co-lead, or acooperating agency. If it is on other’s land thatwe are not in charge of, then we would do ourown Environmental Assessment or possiblyadapt the document that is developed by theother agency. What I really want to emphasizeis that the primary objective is to reach aconclusion for the public good. So that we dotake a balanced view and that is what thepermit will state. It will address all of theissues that have been addressed by you here.

Russ Schmitt: Thank you Richard. I am verypleased to introduce Maureen Walker from theU.S. Department of State, who will give herglobal perspective.

Maureen Walker: Thank you. I very muchappreciate the opportunity to be here and toprovide the global perspective. The first paperthat I will comment on will be the environmentsection. I noticed the major observation orcomment was on open communications. Thisis really vital and allows the United States totake a position of leadership overseas,because we draw that from you and from thediscussions that you have. We have moretransparency, more openness, and morepublic discussion in this country than any otherplace in the world. This gives us tremendousadvantage in negotiations because weunderstand the perspective. Everything fromyour anglers, to your divers, to yourenvironmental groups, all the way up till theindustry. I want to really compliment all theorganizers, participants, and all thequestioners, because these are the questionsthey are asking at the international level andwe are able, with your help, to provide thoseanswers.


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One thing that I would like to say in theseopening remarks that as important as you planhow you are going to handle thedecommissioning process out here inCalifornia, to be cognizant of the internationalinstruments that are guiding U.S. decisionmaking at the international level. The first, ofcourse, is the 1982 United Nations conventionon the Law of the Sea. It is very important tounderstand that as well as the convention onthe Dumping of Wastes and Other Matters,which has recently been amended by aprotocol, which the U.S. Department of State ispresently preparing to send to the Senate forratification. Specifically when we look at theenvironment recommendations regarding fishand marine mammals. I am reminded of animportant article of the convention which youshould become very familiar with and that isArticle 60.3. There it says that removal shouldhave due regard to fishing, the protection ofthe marine environment, and the rights andduties of other states. I think by taking adetailed look at the issues we actually areabiding by a very important part of theconvention. Also you should become familiarwith the international guidelines on removal,that were adopted by the InternationalMaritime Organization in the late 1980s. Youmight wonder why would we have to payattention to international issues, this isCalifornia. The reason is because of the factyour dealing in waters that are used fornavigation by all countries. There is a concernby all those countries that there beunobstructed passage wherever possible.

Back to the issue of fish and marine mammalsand some of the other questions that wereraised and comments. I wanted to drawparticular attention to those guidelinesbecause they note that the determination ofany potential effect on the marine environmentshould be based upon scientific evidencetaking into account the effect on water quality,geological and hydrographic characteristics,the presence of endangered or threatenedspecies, existing habitat types, local fisheryresources, and the potential for pollution orcontamination of the site by residual productsfrom or deterioration of offshore installations orstructures. The guidelines that guidegovernments in their decisions for removal saythat the means of removal or partial removalshould not cause a significant adverse effecton living resources of the marine environment,

especially threatened and endangeredspecies. I thought that you should realize that.

With regard to the issue of marine benthicorganisms and the fact that the upper 200 feetis most productive. This is very importantwhen you decide on whether or not you wantto have an artificial reef. There are specificprovisions in the guidelines for when and howoffshore installation should be removed. Thereis one particular point that I wanted to makereference to. That is if it is decided that onewill be partially removed, that an unobstructedwater column sufficient to insure safety ofnavigation, but not less then 55 meters, shouldbe provided above any partially removedinstallation or structure which does not projectabove the surface of the sea. I had not heardthat mentioned and I wanted to make acomment on that. I think I have completed myfive minutes, but I am available for discussionson the disposition question which I understandyou have a lot of concerns about as well assome of the issues raised on the technicalsession. I think I can get to those when wehave the question and answer period. Thankyou.

Russ Schmitt: We will now hear from ourstate agency representatives. Starting withBrian Baird who is the Ocean ProgramManager from the California ResourcesAgency.

Brian Baird: Thank you. I am here todayrepresenting the Secretary for Resources whosits on the Governor’s Cabinet. TheResources Agency has overview responsibilityfor sixteen to seventeen agencies that comeunder the purview of the Secretary. Theauthority under which I operate is theCalifornia Ocean Resources Management Act,which was authored by then assemblyman,now congressman Sam Farr. The bill thatpassed required us to do a comprehensiveanalysis of the needs of ocean managementfor the State of California. In March wereleased the document “California’s OceanResources and Agenda for the Future.” Thislooked at stewardship issues, economicsustainability issues, research education andtechnology development issues, and issues ofjurisdiction. I am happy to say that there are alot of people in this room here today who haveparticipated in the development of thatdocument in assisting us. We had a section in


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that document dealing with decommissioningand requalification of existing structures. Ithink the fundamental finding was at that timeand I think it was reaffirmed here today wascurrently we have no comprehensiveevaluations of these alternatives. We have alot to learn. We have a lot to do, and the workI think has just begun.

In terms of recommendations. In essence westate we need a procedure for evaluating thevarious subjects and various aspects that getinto the issue of looking at artificial reefs.What are we really talking about here? I thinkwhat we are talking about is an enhancement,is a value added kind of equation. I think thatis something we all need to keep in mind whendiscussing the possibility of doing artificialreefs. Looking at the alternatives of totalremoval, leaving all or some portions in place,or other possibilities. Regulatory issues and allof those sorts of things come into thisequation, and some of those things will bediscussed by the individual state agencies thatfollow me. I think again on this valued addedissue, I think you should be assured that thekind of analysis that we are looking at anddoing is going to be aimed at. Are we simplylooking at an opportunity here or are welooking at something that is properly designedand is indeed a value added contribution to themarine environment. That is a key point Iwould like to make.

Secondly, I was vice-chair of California and theWorld Ocean. A conference that was held inSan Diego in March. We also had a sessionon this subject of decommissioning there. Justa few comments, it was interesting. One of thethings we talked about on the ocean agenda isthat we have a great deal of fragmentation.We have many, many agencies who getinvolved in these things. I believe it wasChevron who made the statement that theyhave had to deal with twenty eight agenciesinvestigating this issue. Which underscoresthe need for us to come up with a process toget everybody in the same room and begin tofigure out what our objectives are and wherewe need to go. Not just the agencies, butobviously all the many, many stakeholders.

We have a very different experience here.Yes, we would be on the cutting edge if we arelooking at these structures in deep waters.The Department of Fish and Game has a reef

program that has primarily been in shallowwaters. So we are breaking new ground here.Also there is substantial difference betweenthe Gulf Coast and the West Coast, and thosedifferences are physical, they are cultural, andthey are cost issues. They are all of thosethings.

When we do talk about science, one thing Ihave learned in my four to five year journey oflooking at this comprehensive issue, is that wehave to use science. We have to base this asmuch as possible on science. We also cannothave a naive faith in science solving all theseproblems within this time frame and do thebest job possible. You have to do the best jobyou can to define your objectives and do thebest job you can to determine whether thisthing makes some sense or whether it doesnot make any sense. You will never have thescientific answers to give you the level ofspecificity that you desire. I think the State iscontinuing to do some ground work on thisissue by looking at the liability issues, andlooking at the biological issues, but clearly thiscannot happen in a vacuum and we all need tosit down in a more focused form after this andbegin to look at these issues. The ResourcesAgency in our role is happy to help facilitatethis in any way we can. If there are issues orproblems with bringing the state agenciestogether, we will help fulfill that role. On theother hand if we do not need to fulfill that rolewe will monitor what is going on. The lastthing we want to do is be yet anotherparticipant in the room if we do not need to be.Clearly the key state agencies I think are theState Lands Commission, the Department ofFish and Game, and the Coastal Commissionwho are about to give their presentations. So Iwill let them proceed. Thank you.

Russ Schmitt: Thanks Brian. Bob Hight theexecutive officer of California State LandsCommission will now give his remarks. I alsowant to point out that Bob was here for thetechnical session and we appreciate that.

Bob Hight: I want to start by saying I amreally very encouraged by the thoughtfuldialogue that has occurred over the last twoand a half days. I think the only way that weare going to be able to proceed is if we worktogether as a team. I think ultimately anyresolution that comes out of that process isone that everybody can embrace. I really


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applaud Lisle’s efforts and cooperation inworking with us and working with the otheragencies to create a structure that iscompatible for everybody to deal with.

Touching on a couple of subjects. Yesterday itappeared that there were two conflicts, oneemotion and one science. People have somestrong emotional feelings about are reefs goodor are reefs bad? We need to bring scienceinto the process to figure out really what theeffect of the reef is on the environment andthen make logical decisions from that. AnyEIR or EIS that is done on this project or futureprojects will out of necessity, I think, require amyriad of state and local agencies. I think ifthey work together as a team in a joint EIR orEIS process it enables the public theopportunity to participate and everyone feelsthat they have had their fair share in the say.The Lands Commission’s ultimateresponsibility is to see that the public’s trust isbest preserved, and that can take into a lot ofconsiderations, and I thank you very much forall of your participation. I look forward toanswering any questions. Thank you.

Russ Schmitt: Next step is Susan Hanschwho is Deputy Director of the CaliforniaCoastal Commission.

Susan Hansch: Thank you. I am relievedthat after two and half days the openingcomments I made, I think, still stand. I thinkbringing all these people together reiteratesthe need to still communicate and the value ofthat. I am going to hit a few of those themes inmy comments now.

One of those issues that I know we have notdiscussed in detail, is one of those issues that Ibrought up, is it really time to get rid of thesefacilities? Have we looked at all theopportunities and options? For the CoastalCommission that hits on some very importantcoastal policies, that is the concentration ofdevelopment, minimizing impact while tappingthe petroleum resources. The people ofCalifornia and the resources of the state havealready incurred impacts, and it is time to takethose out? One of the important reasons tomention that issue now, is now is the time tolook at the options. There are a couple ofother themes of major issues that we need toget into immediately rather than waiting till wesee an application in front of us or we start

looking at the environmental impact report.We need to look at the big picture and regionaloptions and the details. I am concerned thatwe might break things up so we are looking atall the details and then not putting the piecesback together and looking at the big picture.You cannot piecemeal it into such small piecesthat then you do not see the overall cumulativeregional impact. You cannot look at theplanning options, and for me it has been veryenlightening looking at the international impactwe could have. I think that is very, veryimportant. So I think that speaks to look at thedetails, but put it all back together as well.

That also strikes the theme of scientific workand the independent analysis, as well as theability to look at some of these questionswithout a preconceived notion of what theanswer is going to be. That also hits thetheme of we need to do it soon. So that wehave enough time to analyze some of thesequestions in detail. Science is not quick andthe communication that we need in order toresolve some of these issues takes time. Thatis why it is so important and I am very pleasedthat Minerals Management Service and theState Lands Commission pushed to do thisnow. All the agencies are in this together andthe public, the environmental groups, thefisherman, all the stakeholders. The CoastalCommission though is likely to be the lastregulatory stop. That is just the way thestructure is. That does not mean our decisionis any more important. We are all going to bein this together, but when it comes to the placethat we have to prepare recommendation forour commission and have the last round ofpublic hearings, we have a lot of the decisionsalready made. In order to do that we have toget into the issues now.

That gets to my fairly specific recommendationand that is before we leave here today is tohave some sort of an action plan, or workinggroups. What are the next steps going to be?Who wants to be involved? That may meantaking the key agencies that are here andcoming up with a working plan, notify peoplethat are on the mailing list, let people knowwhat we are going to be doing, and identifywhat those issues are. Some of those issueswe can probably deal with later, that are easierto resolve. The difficult ones like the issue ofthe artificial reef, some of the liability issues,some of the mitigation issues. We have to


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deal with them soon! I would like to make surewhen we leave here we do have an action totake the next steps. That is all I have to say. Ifthere are any questions at the end I will behappy to discuss things in detail with people.

Russ Schmitt: Peter Bontadelli is here to givethe perspective of the California Department ofFish and Game.

Peter Bontadelli: Thank you very much forallowing me to come down and join you today.I would like to first extend the commitment ofthe Director who was scheduled to be heretoday, Ms. Jacqueline Schafer. A death in thefamily has prevented Jacky from attending thisweek. She did ask me to specifically conveyone very strong message and that is that theDepartment is strongly committed and she hasa direct personal interest in working with all theimpacted stakeholders, as well as all of theother state and federal agencies in helping toaddress the issues that arise with the questionof decommissioning. As Brian alluded to theDepartment of Fish and Game will be deeplyinvolved in several potential aspects ofdecommissioning. I will stress the wordpotential since the final decisions on what willbe done on part of the Decommissioning or notdone in terms of leaving the structure in place,will be made on a case by case basis, which issomething that has been emphasized both bythe working groups in terms of the reports Ihave listened to this morning and also byseveral of the agencies.

The potential and involvement of theDepartment is several fold. I was delighted tohear the State Department mention the IMOissues and the Law of the Sea and some ofthose questions. Since the “hat” I currentlywear is the administrator of OSPR, Oil SpillPrevention and Response, is directly involvedin the issue of maritime safety and trafficcontrol. I will note for example that the CoastGuard is in the process of preparing toimplement an IMO extension of the vesseltraffic separation scheme to an eighteen milenautical distance further to the north. That ispredicated upon the existing Rayconoperations at platform Harvest and therefore isan item that must be addressed as part of thedecommissioning process. Likewise the depthquestions, these would be the IMO regulationsthough their guidelines are something I knowboth we and the Minerals Management

Service along with the Coast Guard will belooking at very closely as we look at anypotential for having a partial removal questionof any of the deeper platforms. I am totallyconfident that those issues can and will beaddressed as part of the process as long aswe plan for them and keep them in mind as wego.

In a different role you heard Brian talk aboutthe fact that the Department is and has beeninvolved in the issue of artificial reefs. In theevent that the artificial reef option is chosen asa solution or a potential disposition option forany or all of the specific platforms that will becoming out, there are several things you needto be aware of. Our Department’s involvementdates back to the 1950s and I am sure DaveParker who made a presentation yesterdaycovered many of the technical aspectsinvolved with that process. Specifically in 1985the Fish and Game Code was amended andSections 4620 - 4625 created the basis for ourinvolvement in platform disposition vis-à-visartificial reefs in state waters. The role andfunction of the Department in the exclusiveeconomic zone of the United States beyondthree nautical miles is not nearly as clear aseither statutorily at the state or federal leveland is directly related to the liabilityimplications that come with that less than clearstatutory authority. Perhaps amendments toone or both would be required if a completeartificial reef program with the Department inthe lead is to be involved in that area. Otheroptions in the event we are not the specificlead would include some form of operating asa permitee or in accordance as an agent, thefederal government vis-à-vis MOU option,working with the Minerals ManagementService, both of which have alternative pointsof view and liability implications and are onesthat the Department is more then willing toexplore, working directly with the MineralsManagement Service and the CoastalCommission, and others, as we work our waythrough that process.

The third and most clear role that theDepartment would absolutely have is going tobe that of a commentator in our public trusteerole for the fish and wildlife resources of theState on any EIR or EIS that may be prepared.In that regard we will provide the bestbiological and scientific information we have,both as a protective agency for the State’s


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endangered species, as well as the othercritters that we manage. We recognize clearlythat we have some differing points of vieweven amongst our own stakeholders in termsof both the commercial industries and thatthere will probably be some form of jointdiscussions on an ongoing basis, bothinternally and externally as we proceed alongthe lines of addressing the issues ofdecommissioning, specifically if we get into theareas of reefs.

The Director specifically requested that Imention the fact that the Department is in theprocess of looking at a reorganization which islikely to create a new marine region with a veryspecific emphasis on the whole issue of whathappens in terms of the overall coastalresources consistent with the directionsoutlined by Brian in the report that wassubmitted earlier this year. Specifically withinthat reorganization the artificial reef programwhich is already authorized by statute for theState will come into existence as a distinctiveprogram and the interactions of that potentialvis-à-vis decommissioning will therefore havea specific home within that Department’sreorganized structure. That will not be our onlypoint of contact as that we still have ourongoing environmental review and other itemsthat will interface, but that will give you a singlestarting point for those discussions within theDepartment.

A couple of other quick issues to mention. Theconcept that engineering and augmentation ofany discussion of reefs is an absolute criticalpoint from the Department’s perspective basedon the research and past experience that wehave had vis-à-vis reefs. Also I was delightedto hear the reference to both research andmonitoring or evaluation, both of which areitems that are currently addressed within theDepartment’s guidelines relative to artificialreef programs that may or may not come intobeing as a result of decommissioning. TheDepartment is fully committed to working jointlyand cooperatively with not only the stateagencies and federal agencies, but also withthe local governments as well as all of ourstakeholders and the other stakeholdersinvolved in the process as we work our waythrough.

Lastly I would like to add the Director’s thanksto both the State Lands Commission, Minerals

Management Service, and UC Santa Barbara,as well as all the stakeholders for their strongparticipation in this conference, and I canassure you that the reports we get from DaveParker and others who have attended theconference will be useful to the Director in thedecision-making that she and the Departmentwill be going through relative to the issues inthe next few years. Thank you very much.

Russ Schmitt: Thanks very much Peter.Thanks for filling in so admirably. Now we aremoving to the local perspective to hear fromour local agency representatives, starting withNancy Settle, Manager of Ventura County’sPlanning Division Resource ManagementAgency.

Nancy Settle : Thank you. Now we are finallydown to the locals. The magnitude of thisissue does definitely impact the locals,especially when we get to the onshore facilitiesand for Ventura County we do have onshoreprocessing facilities and we are also the hostto the Port of Hueneme, which is a major deepwater port that could also be included in somestaging facilities for offshore decommissioningof platforms. My involvement andobservations that I have seen as the yearshave gone by at looking at these workshops,I’ve always come away with greater andgreater understanding, but one of my firstexperiences with offshore oil issues came fromstaff back in 1988, saying we really have to geta handle locally here on the timing and theprocess and phasing for facilities, not only theinstallation at that point but I think it is alsoimportant with decommissioning. As far as myown observations with the three groups thatmet, I know that Dr. Byrd mentioned that theissue of facility reuse is something that wehave not fully looked at and that Susanmentioned that as well. Also Mark Carrmentioned we need to really look at theframework for the whole process. And ifanything else, I think with the local governmentresponse the more that we can continue tolook at all aspects of this and look at the wholerange of the offshore development. One thingin particular is the COOGR Effort, theCalifornia Offshore Oils Gas Resources study,which even though we are talking aboutdecommissioning facilities, this study is lookingat the onshore impacts to local infrastructurefor different levels of continuing to get the oilresources offshore. I think this will have, and


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we will need to come back and take a look atthat, and see how that fits into the picturewhen we are talking about facility reuse, andalso trying to pressure the local jurisdiction forresponding to the impacts on ourinfrastructure. I know one thing our VenturaCounty staff and Lynn Cota mentioned, is whatabout the solid waste issue with respect todecommissioning facilities, bringing themashore. In looking at some of the recyclingpotential, I know here in Ventura County wehave limited landfill capacity and also if one ofthe options is to try to dispose of portions ofthe rigs in local landfills or elsewhere then ofcourse you have the secondary impacts of theair quality issues. I am sure we are going togarner a whole other level of environmentalreview as we look at impacts and the results ofthose impacts. The more that we locally canwork within this process and be kept informedall along the way, although frequently we donot get to jump in, this is a wonderfulopportunity here, until it really reaches ouronshore facilities and infrastructure.

The other point I wanted to make is the publicprocess. It frequently ends up being the localagency that carries out the CaliforniaEnvironmental Quality Act as well as the publicinvolvement and input. We have heard a lothere from the different public representativesfrom various groups, but I know if we really getdown to looking at a specific project that mayimpact Ventura County you are probably goingto see a lot more different representatives fromdifferent public interest groups including theTaxpayers Association or the Sierra Club, andyou may get even a variety of differentresponses as far as what their interests maybe. That is pretty much all I have to offerexcept I do agree with Bill Griffin’s first openingremarks, that we are looking at a wholeprocess here and as much as possible for thelocal government involvement that we can tryto encompass the whole package and not justpieces of it. I also agree with Susan’scomments on follow up workshops and followup groups to see what we can do to furtherwork the rest of these issues out. Thank you.

Russ Schmitt: Thanks Nancy. Last but notleast is Santa Barbara County. John Pattonwill be giving the reaction of Santa BarbaraCounty.

John Patton: Thanks Russ. I tried to take theBill Griffin pledge and listen. What I heardcontinues to reinforce to me the position ofbeing a science skeptic. It is clear that thereare some serious scientific questions that bearon management issues but it is equally clear tome that they are not going to resolve the mostinteresting management questions in biologyand in future land use intrinsically wrapped upwith value questions that are ultimately goingto lead to government’s issues, and thebiggest mess it seems to me we have in thisarea is not our lack of understanding of theprocesses but the lack of any clear pattern forhow to make decisions. This situation is lacedwith value choices. Which fish are we going toprefer? Which fishermen? Are we going totake long term or short term views? On theland use side of things, the thing that bedevilsthose of us that are concerned about thelongshore infrastructure, is the question ofafter this project goes away, does its cousincome back within ten years when there is adifferent price forecast for this sort of oil/gas inthe market that suddenly enables an offshoreproject to clear an investment hurdle and werecreate the damn infrastructure, the ultimatenightmare. So as Nancy mentioned, I thinkthose of us who have onshore interests arevery concerned with how the planning fordecommissioning relates to the implicationsthat should have come out of the COOGRstudy. Which is how much more developmentis there likely to be and over what period oftime, and what sort of infrastructure thatpresently exists can it plausibly use? Withouthaving a pretty good understanding of that it isgoing to be very difficult to make gooddecisions about the fate of the onshore supportfacilities and perhaps as importantly, thepipeline connections between offshoreplatforms, which could, under one scenario beabandon, and in another scenario becomeanother platform for some other developmentor through extended reach drilling actually thebase for developing new places. I don’t seehow we are going to make good decisionswithout having what were intended to be theresults of the COOGR study at the time thatwe make them, and yet we have in the case ofthe Chevron facilities apparently fairlyimminent set of decisions to make ondecommissioning. Brian talked about the lackof specificity as being a characteristic of thescience problem. My theme is that it is not justa lack of specificity but the value of


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governance component has a good deal to dowith how we conduct ourselves in this area.

Those of us who have been in lead agenciescertainly have learned something out of this.As Bill Douros mentioned there was about aparagraph in a large document onabandonment. It was defensible at the timebecause of the assumption that we weretalking about thirty years from now. Who knewwhat the technology would be on heavy lift? Itturns out of course, that it was not thirty yearsbut ten, and it was not three hundred to fivehundred million barrels it was one hundredmillion barrels. It is possible that we shouldtake this lesson rather seriously if we arepresented in the future about the installation ofthe facilities that indeed they have to beremoved in relatively shorter order than peoplethought. That might require some analysis, forexample ten years ago even as now, thequestion of whether it would be physicallypossible to do what the documents assumed,namely complete removal at least as a defaultsolution to the platforms was even possible toaccomplish. This brings to mind some rathersad other examples in resource managementhaving to do with nuclear fuel rods. It isforeseeable you are going to have a problem ifyou do not have any idea how to solve it.What business do you have putting the facilityin in the first place? We thought we had thirtyyears which made it seem reasonable to takethat approach, but we did not. The largerquestion might be if there really is only onehundred million barrels and ten years of life inthe project was it worth putting it in? Was itmaybe not only a bad business decision but abad regulatory decision to allow a project likethat to go forward? All the construction relatedimpacts occur and were presumed to beamortized over a larger amount of productionand a longer period of time. Arguably, itshould become the duty of the priory agencieswho approve exploiting the resource to cometo a conclusion of whether the resource isreally there, before the society is invited toabsorb the impacts that go with exploiting it. Iurge Minerals Management Service and StateLands Commission should take on as part oftheir role evaluation of how reasonable is it tosuppose that the amounts of the resource thecompanies think they are going to extractwhen they go into a project are really there toextract under various price forecasts whichmight be used. I don’t mean they should

second guess the business decisions of thecompanies. Those are reasonable rationaldecisions, but there is a regulatory interestthere that I think ought to be part of futureconsiderations.

Further on the CEQA question, talk about thefeasibility of removal makes me a little itchy. Ifit is true that decommissioning facilities issimply part of the life cycle of facilities and if itwas feasible to put them in, and if the impactsof taking them out are more or less the sameas the impacts of putting them in then surely itis feasible to take them out. It is logic chain,that when people say clearly it is not feasibleto fully remove the facilities. I do not think thatis a prior conclusion that we can accept. Ithink we clearly need to look at what does thatmean? Why is it not feasible? What kind ofcosts are we really talking about? What typeof alternatives are there really? Before any arepushed off the table with a messy dismissivelabel.

On the consolidation site question which Itouched on briefly about COOGR which JimLima raised yesterday, I cannot resist one littledig. Something which seems prettyreasonable now from a land managementstandpoint was the occasion of a litigation bythe oil industry against the County of SantaBarbara when the policy was imposed infederal court. I think we deserve a little creditfor looking down the road a bit. As we talkabout decommissioning I am sure we will behearing a lot about “well you know there mightbe some future use for these onshore facilitiesand pipelines,” coming from the same peoplewho thought we should not have such a policyin the first place. We will not forgive that andmove on.

It is worth noting that neither Gaviota or LosFlores Canyon have in fact functioned asconsolidated facilities because no one else hascome along to share them. There have beenvarious permitting scenarios that have beenplayed out but none of them have led to actualinvestments and projects. So we do not haveactual functioning consolidated sites, but wedo have the capacity for them.

At the local government level we look at thelessons of what happens when we allowremoval to lag behind disinvestment which hasbeen documented quite nicely for Santa


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Barbara County in the past and we compare itagainst the uncertainty, both economically andtechnically, about how and whether additionaloffshore plays may come into production in thefuture, it puts us in a real dilemma. We don’twant to cause needless disinvestment throughdecommissioning followed by reinvestment.We don’t want the impacts of that either. Onthe other hand we do not want to get stuckholding the bag, with the rusty bucket facilitiesthat turn out not to be anything anybody canuse down the road. So it is a significant choicethat requires some uncharacteristically openconsultation with the industry about the futurebecause these are business decisions that aregoing to drive this level of interest, notsomething the industry has been fond oftalking about with local government or witheach other for both legal reasons andcompetitive advantage reasons and yet I don’tsee how we can make much sense out of thiswithout talking about those issues.

My last question is a very small one. On therigs to reef issue, if in the fullness of time, if thepresent site of a jacket is going to be a pile ofrust, and if as Dave Parker said it really doesnot have a whole lot of value unless you pile abunch of augmentation materials around itanyway. Why do the present locations of theplatforms make sense as a place to haveartificial reefs. Does it not matter where theyare? I think based on some things I haveheard we are going to have to seriously look atthe question of if artificial reefs, why at thepresent location of the existing platforms? I dorecognize that this is an already identifiedissue, but it became clearer to me that in thelong run the presence of the jacket does nothave much to do with it. Thank you.

Russ Schmitt: Thank you very much. At thispoint I would like to open up to questions notonly for the panel members but also addressany issues you might have with any of thereports given by the session co-chairs. Andplease this is not a public hearing.

Bill Stolp with Dames & Moore: I have aquestion/comment. The last five years I havebeen in the UK and Norway working onplatform decommissioning facing many of thesimilar issues and problems that you are facingnow. I would like to agree with Lisle in that themore you assess the less you know. We havebeen applying science and analytical

techniques to the questions that come up and Iwould like to say however, that California is noton the cutting edge!! You guys have someunique issues, but you are not ahead of thegame. You are a little behind it, I would sayabout five years. What I would like to do isreiterate that you do need to put amethodology in a process to assess andanalyze the issues. It needs to be amethodological approach to assess thetechnical, environmental, safety risk, and costissues. You have to be able to address whatis a scientific issue and what is a perceivedvalue issue. They do not always see eye toeye and you need to be able to differentiatebetween them and know how to assess andhandle those. So down to the actual questionwhich goes to Minerals Management Service.Is there going to be another workshop similarto this in the future? Could it be possible toinclude more of the technical and scientificmethodological assessment process from thelessons we have learned in the North Sea inthose presentations? If you do include that Iwill be willing to coordinate that effort.

Minerals Management Service: I do notknow if we have talked about what the nextstep is. That is in fact one of the problemsahead of us is, to define a course of action forthe next few months and ultimately the nextyear or two. I do not know if the next timewould be a meeting of this nature or somethingspecifically oriented towards a set of options. Ithink at this point it is wide open. I think weneed to work with the others at the table.

Linda Krop with the Environmental DefenseCenter: I do want to point out one distinctionof what happens in the Gulf of Mexico. Thereare a lot of good lessons to be learned there.Some things that we probably want to followand some things we probably do not want tofollow. The question of liability is one we donot want to follow in that first of all the statesdo assume the liability. They are supposed toreceive half of the savings that the oilcompanies retain by not removing thestructures completely, and apparently there isan issue as to whether they actually receivethe full amount they are entitled to.

Second of all in terms of compensation tocommercial fishers, the Gulf has a blackoutpolicy. If a commercial fisher looses gear orequipment and is compensated, that area


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becomes blacked out for future claims. So ifanother fisher enters that area and has loss aswell, they cannot receive economiccompensation. Well the entire Gulf is blackedout. So fishers are filing claims, but they arenot being compensated. I think that is a lessonwe need to learn and we do not want to havethat kind of liability absolved here.

My comment was going to be that I ampleased to see so much support for pursuingthese issues that were raised at theconference further and with the qualificationsexpressed by John Patton, that a lot of thateffort should be focused on the science. Iwould like to make a suggestion. Many of usin this room and on the panels have beeninvolved in a very indepth process dealing withhigh energy seismic surveys. It has been acooperative effort of the federal, state, andlocal agencies, as well as the public industry,fishers, etc. One of the things we did in thatprocess is we had a sub-component thatlooked at the science of the impacts of highenergy seismic surveys primarily on marinemammals. The committee searched outexperts in the field and developed questionsfor them. We had about twelve experts webrought into a room and we watched themdebate the issues and discuss them for a dayand a half, and it was fascinating. People whoprobably have never been in the same roombefore were. What was especially fascinatingwas the consensus that they achieved onvirtually every question that we asked them.We are still getting some of those answersback in final form. We are finding out, numberone, some very good answers to some ofthose technical questions. Number two, weare finding out where we need moreinformation and what research should beconducted. I feel that we are in a very similarsituation here. We have some information,and everyone seems to agree that we needmore information. I would suggest that as aprocess to try and acquire that information in acollaborative effort.

Lisle Reed: It makes sense. I agree withLinda. It has been working very well with thehigh energy seismic theme effort. I think wemay want to look at pursuing something similarto that. The success has been very good withthe high energy seismic team. They put thescience into a court all of its own and get theright people in to talk about it.

Brian Baird: In the ocean agenda, in ourstrategy we talked about, it is a differentsituation, but I think it is applicable. The jointreview panel process for doing environmentalimpact reports, and quite frankly when I usedto work at the Coastal Commission, I think Iwould characterize it as us sending a missiledown to the Los Angeles office of the MineralsManagement Service and them having tocounterattack. We would go back and forthover these issues until one day somebodysaid," why don't you all get into a room." Wewere in this room at times from 6:00am till lateinto the evening, going over all these issues,line by line. The one I was involved with cameout with a document that we all agreed on.There was no litigation on the document. It issomething that we think makes a great deal ofsense, but it does need a structure in order tomake it work.

Linda Krop: One quick comment on that.Lisle isn't that particular high energy seismicsafety meeting, that is also facilitated? Youjust do not throw people into a room and askthem to solve a problem?

Lisle Reed: Yes it was well organized andwell facilitated.

Sue Benech, Marine Biologist: I have aquestion for Mark Carr. I am posing it as aquestion, although it is a little bit of a commenttoo. We have talked a lot about marinemammals, fishes, and mobile invertebrates. Iwas shocked to hear of the removal of 3000tons of attached invertebrates on theseplatforms. The question I would like to pose toMark is since these platforms are not justreefs, but are actually islands because of theirvertical zonation, has there been anydiscussion of what they may serve as seedcommunities for shallow sub-tidal and inter-tidal coastal area that are heavily impacted byanthropogenic influences? This may be animportant issue to follow up in as far asscience is concerned. I get knocked back andforth, Linda left me positive and Mr. Patton leftme negative. It sounds like science is moot,and it is mostly impression.

Mark Carr: Thanks. That is a really goodquestion. Unfortunately it is one of those thatis very difficult to address, that is the problemwith marine populations that exist on thesestructures. They are characterized by larval


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dispersal that is the mechanism by which theymay potentially replenish other populationsand communities elsewhere. The problem iswe do not know very much at all about thosepatterns of larval dispersal. This is an issuethat raises its head in applied marine ecologyconstantly. I just spent last week at a NationalMarine Fisheries service workshop trying todesign and consider the role of marinereserves as fisheries enhancement strategies.It is the same thing that keeps coming up, howdo you design or locate reserves, or in thiscase artificial reefs, that might contribute toother populations? We just do not know thoseconnections, but certainly that is a very viablepossibility that the organisms that exist onthese platforms act as a source of larvalreplenishment to other populations nearshore.On the other hand, just like marine reserves,we have to be cautious because they may alsohave absolutely no effect. It is all dependenton both the environmental conditions thatinfluence the dispersal of organisms from thatsite and the characteristics of larvae thatdetermine their pattern of larval dispersal. Iwish I could be more positive, but it is one ofthose things that science needs to address.

Tom Raftican from the United Anglers: Iwant to pretty much follow up on what somepeople have already said. For example SusanHansch said," Let's get the next step plannedbefore we leave." I think Mr. Baird wasexcellent in his comments too. Maybe insteadof planning the next step let’s try and gettogether. The only thing I would like to add tothat is we have some outside stakeholders andthe "big" boys. We both would like to beinformed along the way and also as they aredeveloping information in each area. We needsome sort of access to that information acrossthe board. So that instead of coming notknowing what is going on in different areas, ifyou come to a meeting, an association, or agroup, with the information already available toyou when you get there, we can come out withmuch better conclusions from that instead ofdiscovering everybody else's information atthat time. So just something to think aboutbefore we leave. Thank you.

Connie Hannah from Santa Barbara Leagueof Women Voters: I just wanted to thankMaureen Walker for bringing up the vesseltraffic problem. We had spent two days andwe had never talked about the possible

impacts of intact platforms being a problem forvessel traffic. Barry Schuyler of UC SantaBarbara wrote his Ph.D. thesis on tanker trafficin the Santa Barbara Channel. He told theSanta Barbara audience that if you wanted toconsider the ultimate disaster, you consideredan ocean going tanker running into one of theoil platforms. I think that we must keep in mindthe vessel traffic. We are delighted to hearthat they are talking about a separation systemfinally for that traffic. As we talk about deepwater platforms, we have to consider thevessels too.

Maureen Walker: I did want to state that inthe Law of the Sea Convention, which Ireferred to quickly earlier, I did not quote onepart of it which is very important, and that isfrom Article 60.3. That says that anyinstallations or structures which areabandoned or disused shall be removed toinsure safety of navigation. That is a numberone issue. Then taking into regard what Imentioned before, the fishing and the marineenvironment, etc. I think a little history on thismight be of some use to this audience. Backin the late forties when the industry was justgetting off the ground, the United States Navywas quite suspicious of this activity becausethey thought the oceans belonged to the Navy.They did not want to see offshore oil and gasgo in, but as it went forward their provisionsput in an international convention, the 1958Convention, that all structures would beremoved, and the Navy had a lot to say aboutthat particular provision. As the industrydeveloped and went forward it becameapparent, and mostly through some of theNorth Sea governments and also the UnitedStates, that there were going to be cases thatnot all the platforms could be removed. That iswhy the 1982 Convention on the Law of theSea does have some flexibility here, but theguidelines that were drafted in the InternationalMaritime Organization presumed that mostplatforms will be entirely removed. Theexceptions are the exceptions to that rule.There are ways and means, and the guidelinesgo through them, but I just thought it isimportant for you to know some of thatbackground and what was involved indeveloping those guidelines. Thank you.

Lisle Reed: I have one comment relative tothe issue of tanker traffic inside the channel. Iwill observe that the state does definitely share


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the concerns that were expressed in that. Ibelieve today you will find that there isessentially no tanker traffic left inside thechannel, particularly carrying crude. That issomething that you will see even more stronglyreinforced in the process of the CoastalProtection Review Document, which will becoming out shortly from our office. Weanticipate nearterm publication of that. Wealso have a series of discussions underway onvessel routing issues, both in the MontereyBay Sanctuary and also related to air qualityissues coming out of Southern California.Those groups and operations are jointly beingworked on by both the Coast Guard and NOAAas part of the issues in which the State isdeeply involved. I think many of those issuesthat you raised will be resolved. There arehowever significant amounts of ongoingcontainer traffic, which does have significantamounts of bunker, which does not completelyeliminate the concerns that we have for anytraffic that does remain in the channel.

Maureen Walker: Just one last thing. I haveto put my hat on as the chair of the NationalSecurity Council Interagency Working Group,where we have to take into account the wideranging views of our blue water interests; theNavy, the Coast Guard, as well as the coastaland marine interests of NOAA, EPA, etc. Tosay this issue of navigation is not one that isspeculative, in the 1980s a German submarinedid run into an offshore platform, and it is ofsafety concern. I just wanted to make thatpoint. Thank you.

Arvind Shah: I am associated with the Gulf ofMexico office with Minerals ManagementService in New Orleans. In the last ten years Ihave been involved with maybe more then1000 applications, 70% of them withexplosives, 30% of them with non-explosives.I have some experiences in these removals. Iwould like to make a few comments over here,about this rigs to reefs fund which wasestablished by Louisiana and Texas. Thatfund is strictly dedicated to those rigs to reefsissues. For example they maintain the buoysout of that fund and they have not received anylawsuits yet so far. With 123 structures in thisrigs to reefs area I am sure there is more than$13 million in that fund. If you try to follow thesame thing over here I would advise you adopta similar fund that is dedicated to the rigs toreefs issues rather then that money going to

the state treasury and waiting for that money tocome back to the agency. I think that it is veryimportant because the states of Louisiana andTexas passed tough legislation and dedicatedit to the rigs to reefs issues. In the Gulf ofMexico office all the removals we have doneso far, we have not allowed this partial removalor totaling of the structure in place. The onlytime we have allowed this partial removal ortotaling in place was in association with therigs to reef structures. Minerals ManagementService on their own in the Gulf of Mexico hasnot allowed any partial removal or totaling inplace. Our regulations as they exist nowrequire that all the platforms and all thestructures, at the end of the expired lease,within one year be removed, regardless ofwater depth. Those are our regulations andthat is what we try to follow. Regarding thisrigs to reefs partial removal we do not havedirect input, but most of these partial removalsare done 85 feet below the waterline. In somecases they are removed less than 85 feetbelow water line. Minerals ManagementService does not have an input in those partialremovals from the waterline to the top of theremoval. That issue is decided by the statethrough the Corps of Engineers and theyconsult the Coast Guard regarding the waterlevel between top of the platform and sealevel. They decide what type of buoys or aidsto navigation should be placed on the structureif it is lower then 85 feet.

One last thing I would like to tell the audiencehere. We have a very good web page forthose of you who like to "surf" the net. Ouraddress is www.mms.gov. We have a lot ofinformation available. All our NTLs, all ourLTLs, all the removal data on the platforms.We have about 1300 applications available onthe internet. It is all on the internet. You candownload it and it is free. Also we have publicinformation available on the Gulf. We alsohave a toll free number that offers a lot ofinformation and free hard copies from ouroffices. I am also willing to answer anyquestions while I am here. Thank you.

James Wiseman, graduate student at UCBerkeley: I was glad to hear about the website. I have been talking to people aboutsharing information and we have talked aboutthe need for sharing information. I would liketo suggest, and people have agreed with me,that we host a public web site on a government


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agency machine for information sharing. Herewe could put together the proceedings of theconference, some conclusions, and pictures,etc. Thank you.

Win Thorton, member of the Artificial ReefAdvisory Board for the State of Texas: Ihave a comment. I would like to say a coupleof things about our program in Texas. It is avery comprehensive program. We started itback in 1980, and it is not just rigs to reefs.We have a lot of other materials and reef sitesdeveloped. We have liberty ships. We havepurpose built reefs in nearshore areas. We dohave rigs to reefs. We have concrete, rock,and fly ash blocks. We have a program thatlooks at a variety of materials and a variety ofsiting criteria. We also have an advisory boardthat is made up of the various stakeholdersgroups, be it oil and gas, be it recreationalfisherman, commercial fisherman, divers, etc.So their input is developed and included in anyof the siting or criteria that we do.

The fund that we have for the State of Texas issolely devoted to development of artificialreefs. The donations that are put there areused to maintain marker buoys as required toenhance those reef sites to cover any futureliability should it occur. We have actuallyaccepted donations from the oil and gascompanies that have saved money. We havealso paid money out to develop nearshorereefs that cost money. This was forrecreational divers and recreational fishermen.We are actually funding the development ofnearshore reef sites. We do deep water to acouple of hundred of feet, to shallow waterreefs, to meet the needs of the multiple usersin the state of Texas. Thank you.

John Smith of Minerals ManagementService: Maureen is dying to get to thisquestion, so I have to give her the opportunityto get into this issue. The issue of deep oceandisposal came up in several of the sessions. Iwould like to ask Maureen to address that forthe benefit of the audience?

Maureen Walker: Thank you very much. Byway of background it is important to know thatwhat guides that particular issue is the LondonConvention. The London Convention isrecognized as the source of the global rulesand standards on dumping that are referred toonly in a general way in the Law of the Sea

Convention. Today we have 76 parties to theLondon Convention, but what is not good isthat a little over half of the oil-producer statesare not members. We have been trying toencourage more participation by thosegovernments. In 1996 the entire regime of theLondon Convention was re-worked through aprotocol. This protocol will replace theconvention. It is a free standing agreement towhich both contracting and non-contractingparties may become party. This represents aculmination of a multi-year process of revisingthe Convention which began in 1992. Thestructural revision of the Convention is calledthe Reverse List. Basically what this does iscontracting parties are obliged to prohibit thedumping of any waste and other mattersunless they are listed on an annex. In the firstannex there is allowance for the dumping ofbulky items, vessels, offshore platforms, andother manmade structures. So there is anallowance to have these dumped at sea, butthere is, as you can imagine, a rather involvedprocess in order to accomplish it. What isoccurring now within the scientific group of theLondon Convention are meetings of expertsand scientific experts to try to come up withwhat is called the Waste AssessmentFramework for the dumping of these particularitems. That is an ongoing process and thenext meeting will occur in the first week of Aprilin South Africa. I have seen some of the earlydocuments and they take into account many ofthe things you are raising here, because thedisposal at sea option will be required to usebest environmental practices. There are anumber of considerations that every coastalstate, and when I say coastal state here Imean nation, must take into account, includingthe issues I mentioned earlier; the fishing, themarine mammals, and the fact that thematerials must be completely flushed out andcleaned, etc. before they are dumped.

There are provisions in this draft of this WasteAssessment Framework on site selection.What governments should look for; thephysical and biological characteristics, theoceanographic characteristics, amenities,values, and other uses of the sea in that area,economies and operational feasibility. Theyhave to look at geographical positioning andmy understanding of U.S. Domestic Law is thatthis is regulated under Title One of the MarineSanctuary Protection Act (MSPA), and thatEPA, and the Corps of Engineers together


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identify such areas. The answer to yourquestion is yes, deep disposal will be allowed.It will be on a case by case basis. This is theconsidered opinion of the internationalgovernments that met in devising the protocol.In the face of the move by one government toactually have a moratorium on such disposal,but that government was not successful andwe now have a situation where we hope byhaving the guidelines and standards there fornations, we may now be able to bring in someof the other oil-producing states. That is a biginterest of the United States, although we haveover half of the offshore oil platforms there areother platforms in other areas of the worldwhere there is very little consideration as to theoperation or decommissioning. As a result weare anticipating and co-sponsoring with thegovernment of Indonesia, in April of this year,a conference on decommissioning to bringtogether economies in the Asia Pacific regionto address this issue, which has economicimportance as well as environmental concerns.It does again go to the issue that I raised whenI began this morning which is the issue of theUnited States' leadership in this area. It is ourcompanies and our environmental awarenessand concerns that we bring to these countriesand help them improve their standards in away that really benefits the entire globalenvironment. That is really our objective.Thank you very much.

Melanie Stright with Minerals Managementin Washington, D.C. : I very much agreedwith a comment made by a gentleman a fewspeakers earlier. It would have been very nicehad participants been made available a lot ofinformation up front so they could havedigested it and brought that knowledge to thediscussions ahead of time. Along that line Iwanted to mention that several times thismorning the IMO guidelines for platformremoval for the purpose of navigation safetyhave been partially quoted and talked about. Ido have copies of the IMO guidelines with meif anyone is interested and would like to seethose. The only other comment I would like tomake is over the last few days I have heard acouple of times it said that in terms of theartificial reef programs in the Gulf of Mexicothat the oil companies and the states share thesavings fifty-fifty. I wanted to point out it is myunderstanding that nowhere is it stated thatthis savings is 50% or that is what is donated

to the states. It simply says that the savingswill be shared. Thank you.

Russ Schmitt: About the issue of havingmaterials beforehand, we are still waiting forsome of the position papers that were due amonth ago.

Tim Watson with Amoco: GreetingsAmericans. How are you all? I have aquestion for Maureen, but first a shortpreamble. I think the international side of thisis very vital and that is why I am glad to seeMaureen here. You must be very careful inCalifornia not to take a "holier then thou"attitude on the sea. I come from a small islandwhere it is only seventeen miles to the nearestbeach. We have been there for 1000s of yearsand there are 55 mammals that live on it, soyou must have your perspective of how youand the ocean can live side by side.

In terms of the impact of the world, I think that Iam right in saying that 350 million Europeanswill take much more notice of what happensout here in the Santa Barbara Channel thenthe rest of the United States. I think that iswhat Maureen is on about.

The U.S. Constitution I do not know muchabout, but I know it is based on commonsense, give and take, and communication. It isprobably the only legacy that the English leftyou, I hope. The communication must be withthe North Sea. The Dames and Moorerepresentative behind me was quite right thattechnically, even the Gulf of Mexico, is not upto speed. They have not had to be becausethey have shallow water platforms which is notwhat you have. So ignore them and come tothe North Sea. We have already said we arehere to help and pass on the technology. Youcannot do science on this unless you knowtechnically what you are going to do with theplatforms. This technology needs importing.You cannot make a decision without it. Youneed to know what the regulations are. Youneed to know intimately what the IMO meansto yourselves and to the rest of the world,because believe me the world does take noticeof what the U.S. does.

We do not use the word feasible in takingplatforms out anymore. We could put aplatform on the back side of the moon if wewanted to. The oil industry is extremely clever.


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Five years ago we said only when feasible andwe got exactly the same kind of reaction, quiterightly from the mothers of the moon that youwould expect. It is feasible, anything isfeasible. The question you must askyourselves is, is it worth it? Is it worth thejourney?

Let me have a quick note on some of the otheraspects of this. Environmental impacts, I amsorry to tell all the environmentalists here, butthey are very, very small in global terms, buthave fun in finding something that really hasan impact. If you do find something that hasan impact I am on the internet so please let meknow.

Much more important is the communicationwhich I will come on to, but common sensearguments and I stress the word that was inyour U.S. Constitution, common sense. Youhave got to use common sense. You cannothave it all your own way, whether you are theoil company, or the man in the street, or therepresentatives of the man on the street. Youhave got to have common sense arguments.Believe me, I have been there. They havemuch more impacts than science. I am afraidthat scientists and lawyers come at the bottomof my believability chart. I am just an engineerand I am much more believed by thehousewife. We are talking to the housewife inthe end, because they are the ones that vote inthe politicians. They have the say in the end.

On reefs. In the U.K. or the North Sea we donot talk about artificial reefs. We acknowledgethat they are a nuisance to the users of thesea. We come back to is it worth it? And wecompensate the users of the sea. We do nothide behind anything like a reef. It may well bedifferent here, but I can assure you the wholeindustry is not pushing off junk platforms andcalling them reefs. That is not the case. Werecognize they may be valued in some parts ofthe world not necessarily the North Sea, butthey are an impediment to navigation. Theyare not an environmental problem.Impediments can be compensated for and thatis the only way forward if it is worth it to leaveit.

Deep sea ocean disposal has come up severaltimes. Assuming if you can get beyond 200miles from the U.S. Navy, you can dumpwhatever you would like. I imagine that is

probably the basis of the law. Whether it isworth it is another thing. Technology says youcannot actually do it. Amoco’s point of view isif you have a jacket on a barge and you havegone to the trouble of lifting it onto the barge,then take it ashore. Do not dump it! It simplyis the wrong thing to do. Take it ashore andrecycle it, reuse it. Do not dump it justbecause you have it on a barge. You have toevaluate deep sea disposal. That does not getinto the Brent Spar which is somethingdifferent. The Brent Spar is not a rig, but afloating storage barrel.

Liability, we are very clear in the U.K. aboutthis. The only people that are going to bearound in fifty years is the government. Theyultimately should take the liability, but youmake the liability as small as possible. Youclear up your debris, you compensate thefisherman, you give them buoys if that is whatthey want, you give them instrumentation ifthat is what they want, you give them newships, if that is ultimately what the people wantand is worth it. So you do bend overbackwards for your customers and ultimatelythe people are your customers. As Shell foundout when your customers get mad they firebomb your gas stations. So look after yourcustomers.

Finally it is common sense, do not forget that.Common sense is the only way forward. I domake a plea based on five years experience,that cut out the lawyers, cut out the scientists,and get down on your knees and start talkingto the house wife, and start talking realimpacts. Let the housewife know exactly whatthis is all about. First of all tell them what aplatform is. Affably, smile on your face. Let’snot have this aggravation that is apparenthere. We have had that and it does not getanywhere. Let’s have a smile on your face.Let’s keep our feet on the ground. A lot of giveand take.

The oil industry must go out and do itstechnical work. Then you can do the science.The oil industry must invest in the best thingspossible, it has to, not the contractors, theyhave no need to do it. The oil industry must dothat and that is what they should be pledging.

Finally you must have patience. This is a longdrawn out thing. We are in unknown territory.We all use gasoline. We are all responsible for


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the platforms being out there. The oil industrycan make a pledge to you right now that if youstop using automobiles we will stop drilling foroil. It is simple, but it is absolutely true.

Now my question, leadership, to Maureen. Ifyou totally remove your platforms in the Gulf ofMexico because you get pushed into it,because it is not worth it, and it is not thecommon sense thing to do. Maureen whatimpact do you think that is going to have onthe American oil companies in the North Seaand around the world, if they too get pushedinto it? Thank you very much.

Maureen Walker: Could you just repeat. Didyou say total removal in the Gulf of Mexico?

Tim Watson: Yes, if you go for total removaland it is not the best thing to do, and theAmericans are showing leadership, and theyopt out of a proper decision, what impact isthat going to have on the North Sea? Wherewe have many more, and a lot of American oilcompanies own a lot of real estate.

Maureen Walker: One thing that yourcomment on, and asking me to comment onleadership, points up to me, and something Ialways say before we head off to a negotiationsomewhere in the world, is that the mostdifficult negotiation always happens before weleave our shores. That is because we do haveso many competing interests to take intoaccount and the scenario you projected for theGulf of Mexico would not be possible becauseof all those various interests that we have totake into account. In fact as I indicated earlier,when Denmark made the proposal for amoratorium we could not support it as an oil-producing state. That was unacceptable, andalso because we do tend to take the commonsense approach, looking at the science andtaking all the views into account. That leadsme to one other comment that I would like tomake, that is an attempt within internationalorganizations to try to regulate the oil and gasindustry on an international basis. This issomething that we oppose because theregions are different. The North Sea is verydifferent from the Gulf of Mexico, which is verydifferent from Southeast Asia, etc. It is thesedifferences in regions that have scientificimplications, legal implications, that we wouldtake into account. For this reason we willcontinue to oppose what I consider a "head in

the sand" approach. We do have expertisehere and we would never want to ignore it.Thank you very much for the opportunity tomake that comment.

Russ Schmitt: More questions? Comments?

Bill Stolp: I would like to make just one finalcomment. I promise this is the last time I willcomment. An interesting postmortem of theBrent Spar backs up exactly what Tim Watsonwas saying. The postmortem of the BrentSpar incident, it was done exactly by theregulatory regime. It was done with goodscience, good economics, and goodtechnology. The point here that everyoneneeds to listen very carefully to, it was theGerman housewife that turned that around.They tried to prove a technical problem. Theytried everything they could, but it was not untilthey got onto recycle of 14,000 tons of steel.Now the German housewife is the mostefficient recycle entity in the world. Virtuallyeverything that comes into her kitchen isrecycled. When she found out that there was14, 000 tons of steel that was not going to berecycled, she did not care that it cost $5,000 aton to recycle it, when you can go out and buynew steel for $200 a ton. I leave that with youas a point of what Tim Watson was trying tomake. Somebody outside Ventura County,somebody outside California, somebodyoutside the continental United States ofAmerica, can have one hell of an impact onwhat happens offshore Ventura County.

Susan Benech, Marine Biologist: I justwanted to make one final comment. What Ilearned in the past three days, I brought backwith me "3 C's." That is Common Sense, bigunderline under that, Communication, tenunderlines under that, and Cost, bothenvironmental and economic. That is what Ihave learned and I am glad I attended. Thankyou.

Russ Schmitt: I would like to thank you all,the panel members, for both their insight aswell as their willingness to listen and answercomments. I would like to give a very briefsummary and closing remarks. This is clearlya case where less is more. It seems to methat there were lots of "letters," for example the"3 C's," common sense, communication, cost,"S & S," science and safety, "L & L," listen andlearn. It is the "listen and learn" I think that we


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all did. That is what Bill asked us to do earlyon, and I think we did it very well.

One of the purposes here was for us to find outmore about what the issues are. To find outmore about decommissioning, the process asa whole. I think we did that. We listened toeach other. As a result we have a betterappreciation, a better sense for where we allagree, where the common ground is. We havea better sense of what we do not agree on.We have a better sense of why there are thoseissues that we do not agree on. I think it was avery valuable exercise for us to come to that inthese past couple of days. The big issue thatconfronts us is where do we go from here?That is one that we are not going to have aquick answer from. So it is something I wantyou all to think about. Quite clearly we aregoing to need to have more of these types ofsessions, maybe not in this type of format. It isgoing to be very useful for all of you to givefeedback to Minerals Management Serviceand the State Lands Commission on where weshould go next. Those agencies are going tohave to take a step back and digest what theyhave learned and heard too. Maybe the nexttime there will be more focus groups. Weheard a lot for example from Rigs to Reefs,maybe we need more on Rigs to Reefs, but ina different kind of format. We do not want tobeat it to death, but yet there are issues therethat need to be resolved. We touched on them.They are still important, even if we do notagree on them. We still need to worry moreon, for example liability issues, or thealternative use issues. Please let’s walk awayfrom here thinking more about these issuesand how we are going to deal with it!

With that I want to thank all of you forparticipating. I especially want to thank theState Lands Commission again and MineralsManagement Service for hosting this timelyworkshop. And a special thanks to just a fewpeople; Frank Manago, John Smith, MineralsManagement Service people who did a heroicjob in helping organize this thing, andespecially to my assistant, Bonnie Williamson,who actually did everything. Thank you verymuch.

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POSITION PAPERS

Environmental Defense Center, Linda Krop and Nichole Camozzi...... 172

Exxon Co., USA, Dave Tyler ................................................................ 177

Recreational Fishers, Merit McCrea ..................................................... 179

Santa Barbara Lobster Trappers, Chris Miller ...................................... 181

Southern California Trawlers Association............................................. 182

United Anglers of Southern California / AmericanSportfishing Association, Daniel Frumkes ..................................... 184

Position Papers

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POSITION PAPERS

Position Papers were solicited from over 100 ocean-user groups (oil and gas industry, environmentalgroups, commercial fishing and recreational fishing). These groups were asked to submit theirpositions on the various issues that would be discussed at the workshop. Each group was asked tosubmit up to one page on the 16 issues below that had been identified by the working groups.Ocean-user groups were asked to submit one set of position papers, reflecting the position/opinion ofthe group.

Following is the list of issues and list of disposition options which was distributed to the ocean-usergroup representatives.

ENVIRONMENTAL ISSUES [addressing theeffects that occur during the actualremoval process, or as a direct result ofremoval (e.g., anchor scarring)]:

A. Air QualityB. Commercial/Recreational Fisheries

(effects during removal - long-term effectsaddressed under Disposition Issues)

C. Marine MammalsD. Marine Benthic ImpactsE. Water QualityF. Contamination/Remediation of Onshore

SitesG. Future Land Use

DISPOSITION ISSUES [addressing long-termeffects of the decommissioning process]:

H. Commercial FishingI. Recreational FishingJ. Habitat ValueK. Enhancement of Platform StructureL. Site ClearanceM. Onshore Disposition (ultimate fate of

materials - reuse, recycling, etc.)N. Social ImpactsO. Economic ImpactsP. Fate and Longevity of Materials

DISPOSITION OPTIONS (you may want to address issues in light of the various options listed)• Non-Removal of Platform, Alternative Use• Full Removal of Platform• Remove Topsides, Partial Platform Jacket Removal, Topping (e.g., remove jacket to 85’ depth,

leave remainder in place)• Remove Topsides, Partial Platform Jacket Removal, Topple (e.g., cut platform at sea-bottom,

topple in place)• Remove Topsides, Move Platform Jacket to alternate site as Artificial Reef• Remove Topsides, Deepwater Disposal of Platform Jacket (e.g., cut platform at sea-bottom,

transport to deep water)• Full Pipeline Removal• Partial Pipeline Removal• Onshore Facility Removal, Restoration


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ENVIRONMENTAL USER GROUP REPRESENTATIVE,DISPOSITION PANEL

LINDA KROPEnvironmental Defense Center, Santa Barbara

As stated in the EDC’s position papers onplatform abandonment and shell moundremoval, environmentalists in the Tri-CountyArea (Ventura, Santa Barbara, and San LuisObispo Counties) support complete removalof offshore oil and gas facilities upon projectabandonment. Complete removal isnecessary to avoid safety hazards and toensure restoration of the natural environment.Removal is also consistent with existing stateand federal laws and policies.

Contrary to these laws and policies, the oilindustry desires to leave platforms in place,allegedly “converting” the platforms to“artificial reefs.” However, there is noevidence that platforms function as reefhabitat. Although fish may congregate at theplatforms, there is no evidence that the fishwould not exist without the platforms, eitherelsewhere in the ocean or at natural reefs.

Any decision to change existing laws, therebyallowing the oil companies to avoid theirresponsibility to remove the platforms, shouldbe based upon an objective analysis. Asmany of the other workshop speakers pointedout, an artificial reef program must be basedon science, not the economic whim of the oilcompanies. The most pertinent scientificpaper on the subject is “Artificial Reefs: TheImportance of Comparisons with NaturalReefs,” by Mark H. Carr and Mark A. Hixon(Fisheries, Special Issue on Artificial ReefManagement 22(4):28-33). As stated in thatpaper, research should be conducted todetermine whether artificial reefs merelyattract fish, or whether they provide a habitatfor increased production that would otherwise

not be possible. Production is determined byexamining how the reef affects fishreproduction, growth, emigration, andmortality on a regional basis. Studiesconducted thus far indicate that artificial reefsmay not be as productive as natural reefsbecause they lack the structural complexityand natural forage base. If recruitment to anartificial reef reduces recruitment to naturalhabitats where survival and growth aregreater, the artificial reef may actually reducethe regional production of fish.

The industry’s desire to leave deepwaterplatforms in place would set a significantprecedent. Even in the Gulf of Mexico, wheresome platforms are disposed offshore, theplatforms are first removed and the sites arecompletely cleared of debris. The platformsare then deposited in an approved area. Also,in the Gulf of Mexico, the states assumeliability for the rigs once they are depositedoffshore.

In conclusion, there is no evidence thatoffshore disposal will have any beneficialimpact; whereas there is ample evidence thatplatform debris creates environmentaldegradation and safety hazards. Existingpolicy and permits should be enforced torequire complete removal of offshoreplatforms. If it was feasible to put theplatforms in, it must be feasible to take themout. The oil companies knew all along thatthe platforms would have to be removed andshould not be relieved of their obligations nowthat their production operations have ceased.

Position Papers

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PLATFORM ABANDONMENT AND THE SANTA BARBARACHANNEL

NICHOLE CAMOZZIIntern, Environmental Defense Center, Santa Barbara

Between 1958 and the 1980s, thirty-oneplatforms have been installed in the SantaBarbara Channel. Production on some ofthese platforms is now complete and theplatforms must be removed. The first four ofthese platforms were removed in 1996 fromstate waters off the coast of Santa BarbaraCounty, raising the issues of platformabandonment options and impacts. Whenremoving a platform, a myriad of optionsarise, raising the question of which is “best”for all parties involved. Environmental groups,commercial and recreational fishers, state andfederal agencies, and the oil industry mustchoose the most feasible economic andenvironmental option while not violating anypermit conditions or laws. Although currentstate and federal regulations require completeremoval of the rigs, the full range of optionsare as follows:

1) Complete removal2) Use of platform as scrap onshore3) Rigs-to-Reefs program converting

platform pieces to “artificial reefs”4) Sell in place to other oil company5) Relocate the platform for use elsewhere

in the ocean6) Store the platform onshore for possible

reuse7) Partially abandon the platform in place

by either cutting it off below the waterline (“topping”) or tipping the platformover (“toppling”)

8) Leave in place for research, recreationalfishing, restaurants, etc.

9) Deepwater dumping

The current debate focuses on whether tocompletely remove the platforms or whetherto convert them to “artificial reefs.” TheEnvironmental Defense Center, on behalf oflocal environmental organizations andcommercial fishers, supports the option ofcompletely removing the platforms incompliance with state and federal permitconditions. Another goal of the above partiesis restoration of the marine environment to itsnatural state.

For 20 years, the Environmental DefenseCenter (EDC) has been working to protect theCalifornia coast from oil development, thecatharsis of which comes in complete removalof the oil platforms. Additionally, 40% offisheries in the Santa Barbara Channel havebeen lost to the oil industry and thecommercial fishers feel it is only just for the oilcompanies to restore this region. Thepermitting state and federal agenciesapparently agree. However, there is a currenteffort to modify government regulations tocircumvent complete removal by focusing ona “rigs-to-reefs” option.

The scientific argument surrounding the issueof platform abandonment, namely “rigs-to-reefs,” centers on the need to study each areaaround a platform to determine if an artificialreef is necessary and whether a platform issuitable to act as a reef. Additionally, theDepartment of Fish and Game (DFG) doesnot consider an area that fish use merely as arefuge to be an artificial reef. According to theDFG’s “Guide to Artificial Reefs in SouthernCalifornia,” the primary factor of considerationfor an artificial reef is the following:

“Reefs must provide adequate habitatfor shelter, forage, growth, andreproduction, thereby increasing(regional) fish production. The goal ofreefs is to increase species’ carryingcapacity.” (p. 5)

Each artificial reef is unique; therefore todetermine an artificial reef’s effectiveness,each reef must be studied individually. Moreimportantly, platforms are not the mostdesirable materials or design for artificialreefs, and natural reefs already exist in thearea. According to an article by MarineEcologists Dr. Mark Carr and Dr. Mark Hixon,titled “Artificial Reefs: The Importance ofComparisons with Natural Reefs,” “… thegreater vertical relief and shelter availability(number of holes) of artificial reefs did not


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compensate for the great structural complexity(variety of hole sizes) and natural footagebase provided by the corals and associatedbenthos of natural reefs.” (p. 3) There areboth shallow- and deep-water natural reefs inthe area of the Santa Barbara Channel, suchas Carpinteria Reef, Horseshoe Kelp,Horseshoe Reef, and Four-Mile Reef.Therefore the urgency for artificial reefs in theSanta Barbara Channel is not imminent. Infact, artificial reefs may attract fish away frommore effective natural reefs. Permitconditions for complete removal of theplatforms should be enforced immediately.

The participating agencies on the state levelare the State Lands Commission (SLC),California Coastal Commission (CCC), andthe DFG. The SLC and CCC act aspermitting agencies which both require thecomplete removal of platforms includingremoval of all debris on the seafloor (see, forexample, SLC, Negative Declaration, Section15073 CCR and Final Mitigation MonitoringProgram; CCC Chevron 4-H PlatformAbandonment, CDP No. E-94-6). The DFGacts as an advisory agency on issues such aswhether the rigs should be used as possibleartificial reefs.

On the federal level, the Army Corps ofEngineers (Corps), Environmental ProtectionAgency (EPA), National Marine FisheriesService (NMFS), and the MineralsManagement Service (MMS) have jurisdictionover platform issues on the Outer-ContinentalShelf (OCS). The Corps’ permitting power isgranted under the River and Harbor Act,Section 10, which regulates work onstructures in or affecting navigable waters ofthe United States. In accordance with theSLC and CCC, the Corps also requiresremoval of debris on the seafloor (see,Special Conditions for Chevron’s PlatformAbandonment 94-50801-TAW). The EPAshares responsibility with many of theseagencies in overseeing air and water qualityissues, along with hazardous waste and toxicsubstance management. The NMFS has

jurisdiction under the Endangered Species Actto manage species and marine mammals.And the MMS oversees leases and approvesall development of oil and gas on the OCS.

All of these federal agencies, under the leadof MMS, currently require complete removal ofoil platforms. Politically though, the MMSappears willing to support rigs-to-reefs. TheEnvironmental Defense Center, localenvironmental groups, and fishers would liketo see state and federal agencies enforcetheir own permit requirements by expeditingcomplete removal of platforms whenproduction has ceased.

Complete removal of the oil platforms is alsonecessary for liability issues. Aside from theobvious polluting environmental impacts ofdumping rig debris in the ocean, who isresponsible when this material deteriorates?What happens when platform pieces becomenavigational hazards? Who pays for newfishing gear when commercial fishers snagtheir nets and possible capsize their boats,thus endangering lives? The safetyprecautions that must be taken if platformsare left in the ocean are numerous. Completeremoval of the platforms is the only feasibleoption; it is cost effective, environmentallysound, and safe.

The State Lands Commission, the leadingstate agency on oil platform issues, allowsconstruction of platforms on the condition thatupon completion, the oil industry must “restorethe marine environment to its natural state.”(SLC Negative Declaration, Chevron 4-HPlatform Abandonment, Section 10573 CCRand Final Mitigation Monitoring Program, p. 5-107.) “Natural state” means absolutely nopresence of a rig or rig debris. It is time torestore the Santa Barbara Channel to thepristine environmental conditions before 1958,when fishers and recreationalists could roamfreely and our sea floor was clear.

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SHELL MOUNDS

NICHOLE CAMOZZIIntern, Environmental Defense Center, Santa Barbara

In 1996, Chevron removed oil platforms Heidi,Hilda, Hazel and Hope off the coast ofSouthern California near Summerland andCarpinteria, leaving behind massive moundsof mussel shells. The mounds, approximately200 feet wide and 20-30 feet tall, haveaccumulated as a result of periodic scrapingsof the initial platform legs. Although theplatforms are now gone, the issues arisesover what to do with these shell mounds.Who is responsible? Who enforcesdecisions? What are the options? Localfishers, community environmental groups, andstate and federal agencies are currently tryingto answer these questions. As a result,unenforced permit requirements, ambiguousguidelines, and confusion have surfaced.

The involved parties include both commercialand recreational fishers, the EnvironmentalCoalition of Santa Barbara (Sierra Club,League of Women Voters of Santa Barbara,and Citizens Planning Association), TheEnvironmental Defense Center (EDC), theState Lands Commission (SLC), the CaliforniaCoastal Commission (CCC), the Army Corpsof Engineers (Corps), the Department of Fishand Game (DFG), and of course, Chevron.The commercial fishers (mostly trawlers),along with the environmentalists, would like tosee the shell mounds removed immediatelydue to the hazards the mounds pose to thelivelihood of fishers. Fishers feel the threatsof snagging gear and capsizing boatsendanger not only their property, but theirlives as well. Restoration of the marineenvironment to its natural pre-oil industry stateis also a main concern of the trawlers andenvironmentalists. On the other hand, therecreational fishers and the mussel harvestersbelieve that the shell mounds act as artificialreefs which provide ideal fishing grounds.The conflicting agendas of the commercialtrawlers and the Environmental Coalition,versus the recreational fishers and the musselharvesters, cannot be resolved withoutguidance from both state and federalagencies.

The SLC and the CCC are the state agencies(Chevron’s four platforms are in state waterswithin the three-mile jurisdiction) whosepermits require the removal of all debris onthe seafloor, as well as a trawl test andverification of site clearance (SLC, NegativeDeclaration, Section 15073 CCR and FinalMitigation Monitoring Program; CCC Chevron4-H Platform Abandonment, CDP No. E-94-6).Chevron flunked both agencies’ trawl tests.The Corps (the federal agency) also requiresremoval of debris within a 1,000 foot radiusand “Preparation and execution of a ‘trawlplan’ providing the test trawls of the area, andsurvey of the project area with a ROV highresolution side-scan sonar to verify thatpotential hazards to commercial fishingoperations have been removed ” (Corps,Special Conditions for Chevron’s PlatformAbandonment 94-50801-TAW). Chevron didnot pass this trawl test either.

The State Lands Commission and theCalifornia Coastal Commission are looking tothe Department of Fish and Game for adviceon this case, specifically to answer whetherthere shell mounds act as artificial reefs.According to the DFG’s “Guide to ArtificialReefs in Southern California,” the primaryfactor of consideration for an artificial reef isthe following:

“Reefs must provide adequate habitatfor shelter, forage, growth, andreproduction, thereby increasing(regional) fish production. The goal ofreefs is to increase species’ carryingcapacity.” (p. 5)

Two marine biologists at the University ofCalifornia Santa Barbara’s Marine ScienceInstitute have recently studied artificial reefsand shell mounds. Dr. Milton Love, one of thescientists, has studied the mussel moundssurrounding platform Gina (east of the SantaBarbara Channel) and does feel that fishreside in the area. Although Milton Love wascited in the SLC’s Negative Declaration on theChevron Platform Abandonment Project asfinding the area of the platforms “not suitablefor many rockfish species” (p.5-55), he does


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feel that even if fish just use an area for arefuge, that refuge can preserve the species’life, thus indirectly increasing carryingcapacity.

Dr. Mark Carr, a former UCSB MarineEcologist now working at UC Santa Cruz, haspublished journals on artificial reefs and feelsthat each artificial reef is unique. Todetermine a reef’s effectiveness, Carr statesthe reefs must be studied individually.Because the mussel mounds being discussedhave not yet been researched, Carr is hesitantto assert or deny the mounds’ performance asan artificial reef.

This lack of information leads right back to theDFG investigation of the mussel mounds’ roleas possible artificial reefs. The DFG feels it isChevron’s responsibility to conduct videoreconnaissance of the mounds for DFG toevaluate and determine the role of themounds. If the DFG decides the mounds areartificial reefs, the SLC and CCC will mostlikely concur. This means if Chevron wouldlike to leave the mounds in place, they willhave to seek amendments to their permitrequirements. In the process of seeking thisamendment to forego the permit-required“trawl-test,” Chevron will have to undergosupplemental environmental review whichincludes public review and comment.Additionally, the question remains regardingresponsibility for damage incurred by trawlers’gear from the mounds. Will Chevron be liableand continue to pay for new gear or will theSLC take over responsibility if the permits areamended?

EDC Shell Mound Removal

In the meantime, the Army Corps ofEngineers has decided that although Chevronflunked the Corps’ trawl test, the shell moundsare not an issue because the Corps considersshell mounds “natural” and not “debris.” Thismay lead one to inquire what exactly defines“debris,” considering the mussel moundsresulted from the presence of the oil rigs.According to the Army Corps’ EnvironmentalAssessment of this project, “debris” is referredto as “… all man-made obstructions (e.g.,pieces of the topsides, jacket and equipmentused during the operation)…” (p. 12). Thispresents a problem for all parties involved ifthe Army Corps is not willing to recognize 200

feet wide, 12-30 feet tall mussel moundswhich formed after being chipped off oil rigsas “debris.” As far back as 1987, the MineralsManagement Service (another federal oilpermitting agency) clearly recognized themussel mounds as “debris” in a study titled“Ecology of Oil/Gas Platforms OffshoreCalifornia.” Numerous times throughout thereport the mussel mounds were mentioned as“debris” or “debris pile(s)” under the platforms(pp. ix. 17, 19-20). More importantly, theArmy Corps’ permit contains the additionalrequirement that all potential hazards tocommercial fishers must be removed. Thesemounds define potential hazards tocommercial fishers. The Corps may notignore this fact, choosing to enforce only theportion of its permit requiring debris recoveryof strictly man-made materials.

With the Corps neglecting the fact that musselmounds interfere with commercial fishers andthe DFG waiting for Chevron to eventuallyvideo the mounds for further study, thecommercial fishers and the EnvironmentalCoalition are disconcerted. Claims havealready been filed by fishers for damagednets, tensions are mounting due to theunenforced permit requirements, and almost ayear has passed since the platforms havebeen removed, making the mussel mounds apressing issue. The people with the most atstake, the trawlers and environmental groups,are tired of being in limbo.

The State Lands Commission’s NegativeDeclaration seeks to “restore the marineenvironment to its natural state” (p. 5-107)and that is what the Environmental DefenseCenter is asking of Chevron. Althoughstudies need to be done to determine whetherthese mounds do serve as artificial reefs,there already exist many natural reefs in thearea. Removing the mounds will not bedetrimental to the regional fish populationconsidering the presence of many nearbynatural reefs. Sending a message to oilcompanies that they must clean up our coastwhen they are done extracting their profits isthe most vital issue in this case. Oil rigs wereallowed on the condition that completeremoval would follow the end of a rig’spresence, in this case this shell mounds. It istime to force Chevron to promptly abide by itspermit requirements.

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OIL AND GAS INDUSTRY PERSPECTIVE REGARDINGENVIRONMENTAL EFFECTS DURING DECOMMISSIONING

DAVID TYLERPublic Affairs Advisor, Exxon Co., USA

It's a distinct honor to address this workshopon oil and gas facility decommissioning. It isalso a pleasure to be back in the Tri-countyarea and again renew long friendships withmany of you.

Before I begin, I want to commend theMinerals Management Service, the StateLands Commission, and the other localagencies and interested parties for theirproactive and continuing attention to thedecommissioning issue. It's one of theimportant issues facing offshore and evenonshore oil and gas production in Californiaduring the next decades.

While I am representing the oil and gasindustry today, I will be referencing one recentdecommissioning experience associated withExxon's Santa Ynez Unit or SYUdevelopment. This experience was thesuccessful, as it turned out, decommissioningof the Offshore Storage and Treatmentfacilities, or OS&T for short. And I say"successful" thanks in large part to theexpertise and dedication of many individualsand organizations too numerous to name --but well represented at this workshop --including regulators, contractors, consultants,and fisheries reps. By the way, if you havenot already visited Exxon's exhibit, Iencourage you to take a look at the pictures ofsome other recent SYU decommissioningprojects.

With that said, I have been asked to give anoil and gas company perspective regardingthe environmental effects duringdecommissioning and removal operations.You have already heard what the effectsmight look like for air quality, fisheries, marinemammals, and other resources. I would liketo talk about three ingredients that areabsolutely essential, in our view, to a positiveenvironmental outcome, and which applyregardless of the resource or dispositionoption.

The first ingredient is sound science. Thisapplies as much to the prospective industryapplicant wanting to decommission a facilityas it does to the regulators. The analysis andresulting regulatory decision should be basedon the best available science, taking intoaccount human safety, technical feasibility,environmental benefits and risks, and cost-effectiveness principles. Consultants andmarine contractors obviously play animportant role here. For instance, theirexpertise was vital in helping Exxon generateaccurate vessel emissions forecasts andproject durations for the OS&Tdecommissioning project. This informationwas used by Exxon and the agencies torationally compare abandonment alternativesduring the NEPA permitting process.

The second ingredient is removal flexibility.Each offshore facility is site-specific and alldisposition options need to be consideredbefore making any decisions. This includesthe ocean disposal option. Conversely, a rigid"one size fits all" regulatory policy sometimesresults in greater environmental impacts,inefficient use of capital resources, and mayeven dampen technological innovation.

Flexibility is also important in how the job isperformed. For example, Exxon was able toavoid explosives during OS&T pile removaloperations because it had the flexibility to cutthe support piles as shallow as two feet belowmudline, if necessary. As it turned out, theabrasive cutting method worked fine and thepiles were cut about 15 feet below mudline.The point is, the agencies built-in the flexibilityup-front to respond to actual seafloorconditions so that we could pursue theoptimum solution.

The last ingredient is open communications. Icannot emphasize enough the importance ofopen dialogue with all jurisdictional agenciesand affected groups with legitimate concerns,including non-jurisdictional agencies and otherocean users like fisheries. Of course, this


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dialogue needs a strong lead agency to keepthe process moving forward efficiently. MMS,as the lead agency for the OS&Tdecommissioning project, did a superb job ingetting all the agencies together with Exxonearly and often to discuss issues and options.

Exxon also communicated openly and widelythroughout the OS&T permitting process. Wedid not wait until the work barges wereoffshore to discover whether there were anypotential conflicts. For example, Exxonconsulted early in the process with the joint oilfisheries liaison office. Letters were also sentto potentially affected commercial fisheriessoliciting their comments and suggestions.From this information, a plan acceptable to all

parties was worked out to minimize anyimpacts. Moreover, prior to and during theoperation, notices to mariners were broadcastby Coast Guard radio and, just in case,notices were posted at harbor master officesto keep fisheries informed duringdecommissioning.

In summary, I believe these three ingredients--sound science, removal flexibility, and opencommunications--are essential to a positiveenvironmental outcome for all concerned.That certainly was the case for Exxon's OS&Tproject.

Position Papers

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POSITION WITH RESPECT TO THE DECOMMISSIONING OFOFFSHORE OIL PLATFORMS

MERIT McCREAOwner/Operator of Seahawk LXV

Representative for Southern California Commercial Passenger FishingVessel Industry

Board Member of the Sport Fishing Association of California

It is my feeling that platform jackets be left insitu in the fashion that meets the requirementsfor both safety and safe navigation. Of theoptions covered in the Workshop and in orderof preference after considering the technicalconsiderations involved and the pointsbrought forward by other speakers at theWorkshop these would be most suitable formy user group.

1. Alternate use in conjunction with “MothBalling” where safe and practicablepending market shifts or technologicaladvances that might make renewed oiland gas production efforts viable. It isinteresting to note that some of theservices to the navigational community inconjunction with the current operationsmay be worth while enough to justify thecontinued maintenance of a particularplatform. e. g., Harvest Traffic Center’ssupervision and vigilance over theWestern terminus of the Santa BarbaraChannel Vessel Traffic SeparationScheme. Weather reports andobservations on site provided to NWS andrebroadcast to the public.

2. Partial removal with a portion of the

Jacked left above water to support lightingand sound equipment to make its positionevident to mariners.

3. Topping the jacket below a level that

assures safe navigation of vessels typicalto the area and conceivable for the future.

Key to all of these options is that both part ofthe cost savings to be realized by these lessthan complete removals and the scrapmaterials being made available to be usedtoward environmental enhancement of the

local coastal area and continued maintenanceof the remaining site.

It is the specific interest of my user group thatthe jacket structures continue to act asrecruitment and/or production sites for thefishes that use them currently. These rigstructures have historically been the site ofgood sport fishing opportunities for ourclientele at times. We would hope that theywould continue to be so. Enhancements ofother nearby areas resulting from thedeposition of scrap materials of thedecommissioning process and madeeconomically possible by cost savings in thedecommissioning process would be anadditional plus for us. If it is the position of theCa. DFG that additional types of materials beused in conjunction with the scrap steel thattoo would be supported by us. I. Sport fishing is importantII. Reefs are important to sportfishingIII. Platform based reefs would be a

good thing for sport fishermen

I. Sport fishing is important

1) Outdoor Life network mentioned that sportfishing was surveyed to be the secondmost popular sporting activity nation wide.

2) I spoke with Bob Fletcher and he notedthat we had carried 550,000 ANGLERSindustry wide last year.

3) There are over 300 CPFVs currentlyoperating in California.

4) He also mentioned that Mr. Steve Crookof DFG had noted that as of 1995 thereslightly more private boat anglers thanCPFV anglers for the first time.


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5) Sport Anglers do lots of stuff besides fishalong the way…

Eat at Restaurants Buy boats and tackle Incur travel expenses Stay in hotels Pay for fees and licenses

Are members of the public and haveopinions…

6) Sport fishing is important.

II. Reef structures are important to sportfishing

1) From a local party boat perspective muchof our fishing occurs over hard substrate,reefs:

Kelp bass rock fish much of yellow tail much of white seabass much of barracuda much of Sand Bass Sculpin & some tuna

2) I Spoke with Russ Izor about his reefs.He was instrumental in the construction of17 artificial reefs in the Newport area.Apparently, there are times when these

reefs provide the best/only sportfishingopportunity for the Newport ¾ and ½ dayboats .

3) They produce literally thousands ofsculpin at times when water conditionsare such that other fish aren’t biting. “TheNewport boats have lived off it.”

4) He noted that key in reef productivity wasthe use of a dump barge where materialsare dumped on top of one another insteadof scattered thinly over a wider area.(high relief).

III. Platforms make good sport fishing sites

1) The areas that the rigs are located evenin the channel area lack high reliefstructure also. None greater than 4 m andmostly less.

*= lost opportunity

2) In ’87 and ’88 Herman* First desire tohave left in place as reef.

3) In ’89, ’90, ’91 and on Hazel,* Hilda,*Hope,* Heidi,* Houchin, and Hogan.

4) In the late 70’s Widows on ABC Hillhouse.

5) Also Bocaccio on Holly.

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SANTA BARBARA LOBSTER TRAPPERS PERSPECTIVERIGS-TO-REEFS POSITION PAPER

CHRIS MILLERSanta Barbara Lobster Trappers

We believe that the introduction of artificialreefs in our area should have well definedgoals. Our goal for artificial reefs is that theyare designed to promote the growth of thekelp forest ecosystem. We find that thecurrent concept of rigs-to-reefs fordecommissioned oil platforms is biased in itsfocus of providing sport fishing opportunitiesfor one species, rock fish. We wish topromote a more holistic goal for artificial reefs.

As commercial fishermen we view the loss ofour coastal kelp forests with the same alarmthat land based environmentalists viewdeforestation. The kelp forests and bottom

growth of various marine algae provide habitatthat plays a major role in the life cycles of themajority of our coastal marine life. Wesuggest that artificial reefs be composed ofappropriate materials and placed inside sixtyfeet to promote kelp forest ecosystems. Wealso would like to see these artificial reefsplaced in relationship to existing reef habitatto enhance and expand them.

The Santa Barbara Lobster Trappers opposeall artificial reef proposals that conflict withtraditional fishing methods in historic fishinggrounds of the Santa Barbara commercialfishing community.


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SOUTHERN CALIFORNIA TRAWLERS ASSOCIATIONPERSPECTIVE

1) ENVIRONMENTAL ISSUES

A. Area Preclusion.

During rig removal, trawl fishermen loseadditional fishing area due to the deploymentof barges, moorings, support craft and relatedequipment. This causes an economic impactthat should be mitigated.

B. Fishery Impacts.

Underwater abandonment activity – especiallydetonations that break up legs or oil rigs –scatter fish such as halibut, a primary speciestargeted by local trawlers. Not only does thisdecrease our ability to catch fish near the rigs,experiences in fisheries impacted by seismicblasting suggest that, depending on thespecies and duration of sonic disruptions, thisphenomenon can last several weeks. In deepwater, species affected could includecommercially-harvested rockfish, sole andshrimp. Economic impacts could range frommoderate to severe, and should be mitigated.

C. Recommendations.

Oil companies should communicate withfishermen prior to start-up of abandonmentoperations, in order to 1) schedule andundertake activities in a manner that createsthe least amount of impact to trawlers; 2)deploy barges, moorings and other equipmentin areas where trawlers would not fish anyway(such as hard bottom rocky areas), thusreducing the amount of area preclusion; 3)coordinate abandonment activities withseasonal or area fishing closures, in order tobest accommodate commercial fishingactivities; and 4) notify fishermen about thetiming, progress and results of allabandonment activities, including detonationsand seafloor cleanup. Oil companies shouldalso develop a system for day-to-daycommunication with fishermen, in order toalert them to which areas are clear for trawlingand which might present hazards, dependingon abandonment operations. Mitigation foreconomic losses due to area preclusion andfish dispersal during abandonment should beimplemented.

2) DISPOSITION ISSUES

A. General Comments: Removal vs. Non-Removal.

Based on permits issued by the Army Corpsof Engineers, State Lands Commission,Minerals Management Service, CaliforniaCoastal Commission and Santa BarbaraCounty, fishermen have been led to believe oilrig “abandonment” would mean completeremoval of the rigs and restoration of theocean floor to pre-development conditions.Negotiations and mitigation measures havebeen undertaken based on thatunderstanding. As the abandonment processdraws closer, however, concepts such as“rigs-to-reefs,” which would preclude totalabandonment, are receiving increasedattention. The following comments are based,to a degree, on that perception or possibility.

B. Recommendations.

Oil rigs should be completely removed duringthe abandonment process, as required bypermits the companies signed years ago.This perspective is shared by many otherfishermen’s groups, including the CaliforniaLobster and Trap Fishermen’s Associationand Pacific Coast Federation of Fishermen’sAssociations, which are on record in thatregard. Once rigs are removed, the seafloorshould be restored to its natural state. Thatmeans removal of all debris, including shellmounds. If the mounds are left in place,trawlers lose an area even greater in size thanthe area lost when the rigs were operating.Without benefit of sophisticated GlobalPositioning Satellite (GPS) navigation andplotting devices (which most local trawlers donot have), they cannot risk fishing anywherenear the mounds, due to the possibility ofdamaging or losing gear, damaging theirboats and endangering their crews. Recentdata supports this perspective. In June 1997,for example, halibut trawlers from severalports – including Santa Barbara and MorroBay – fishing near the abandoned “4-H” rigsrepeatedly snagged and severely damagedtheir gear on shell mounds. They also caughttires, chains, steel pipes and chunks ofcement in areas that were supposedly clean

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and ready for fishing. Remaining pipelines donot pose a particular threat to trawling, as longas they are sufficiently buried. Pipelineconnections, however, must be shrouded(covered), removed or well-buried to avoidsnagging trawl nets. This has been a problemwith abandoned rigs and pipelines in the past.

C. Other Considerations.

If the rigs are not removed, SCTA wouldprefer that they be left in place withsuperstructure protruding above the waterline,so their exact location can be determinedwithout GPS plotters. In addition, mitigationfor the continued loss of fishing areas and thecontinued presence of subsea hazards(including commensurate economic impacts)should be considered. If the rigs are left inplace, SCTA also has the following, specificconcerns:

1) For environmental protection andprotection of the boating public, some agency,private party or association must acceptliability for corrosion of remaining rig materialsand their dispersal through the water columnof along the seabed. “Rot” and “reef” are twodifferent concepts. In addition, some entitymust accept liability for potential harm tocommercial fishing boats, their gear and theircrews, should fishermen snag rig structures ordebris associated with the rigs, or be harmedby pieces of rigs that dislodge themselves andcause “offsite” impacts.

2) The superstructure of at least one rigshould be modified to accommodate weather-sensing and weather-reporting equipment.This project would benefit all mariners,especially since individual offshore weatherbuoys are temporary. Offshore rigsdismantled in the southern Santa Maria Basin(western end of the Santa Barbara Channel)would be good candidates for this project Therig chosen for a weather station should beselected by consensus amongrepresentatives of the fishing community,National Weather Service, and the ScrippsInstitution of Oceanography.

3) The location of any rigs dismantledbelow the waterline must be marked abovethe water line. In other locales, attempts tomark the location of artificial reefs with sparbuoys have proven difficult, since, over time,the buoys grew heavy with marine growth andeventually sink. Thus, a maintenance

contract (with funding identified and securedbeforehand) and a maintenance scheduleshould be completed before any rigs areturned into artificial reefs. The agreementshould cover the reef itself, plus anyapparatus used to mark the site for marinersand fishermen. To avoid posing hazards tonavigation, buoys marking artificial reefsshould include radar reflectors and strobelights. If concern arises over the fact that ahighly-visible, well-lit buoy will attract toomany sportfishermen and result in the take oftoo many fish (possibly drawn to the area fromnearby hard-bottom habitats), then theartificial reefs should not be established in thefirst place. Safety is a primary considerationof all options, should the rigs – in whateverform or at whatever depth – remain.

4) Full environmental review should beundertaken before rigs are turned into reefs.This study should review potential impacts toseveral commercial fisheries, including bottomtrawlers, swordfish and shark drift-netters,salmon trollers and hook-and-line rockfishfishermen. Participants in these fisherieshave anticipated full removal of offshoreplatforms, and all would be impacted invarious manners and to various degrees,should a “rigs-to-reefs” plan be implemented.


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UNITED ANGLERS OF SOUTHERN CALIFORNIA / AMERICANSPORTFISHING ASSOCIATION PERSPECTIVE

DANIEL FRUMKESChairman, Habitat Research and Enhancement Committee, United

Anglers of Southern California (UASC)Director, Conservation Network, American Sportfishing Association

(ASA)A. Air QualityThe less time that heavy equipment must beemployed during decommissioning the less airquality will be negatively impacted. The costof complete removal of the five platformsunder discussion has been estimated to totalseveral hundred million dollars. Partialremoval will result in savings of millions ofdollars. Chevron is willing to share savingsderived from using the platform jackets as partof a Rigs To Reefs program. This provides anunprecedented opportunity for habitatenhancement. Environmental effects ofdecommissioning including air quality shouldreceive primary attention. Next, we would liketo see that maximum funding is madeavailable for artificial reefs. This will beenabled by maximizing the shared savings,and will probably result from finding analternative use for the platforms or “topping”them, i.e., removing the topsides and cuttingthe jackets at a safe depth.

The effect on air quality became a major issuein the recent decommissioning of the 4 H rigsnear Carpinteria. Our solution involvedtopping the rigs and would have reduced theair pollution and enabled improved marinehabitat. Unfortunately the minority positionheld by special interests prevailed and theenvironment suffered.

B. Commercial/Recreational FisheriesCommercial and recreational stakeholdersfish and dive close to the platforms andexposed pipelines because their productivityresults in increased concentrations of marinelife. The decommissioning process should besafe and take reasonable care to avoidharming mammals and causing chemicalpollution. Otherwise it should proceed rapidlyso as to minimize the disruption of fishing anddiving. The appropriate regulatory agencieshave expertise in these areas and we areavailable to support and assist them.

We would like to see both environmentalprotection and maximum funding madeavailable for artificial reefs (see A. Air quality).This will be enabled by maximizing the sharedsavings and probably involve finding analternative use for the platforms or toppingthem, i.e., removing the topsides and cuttingthe jackets at a safe depth. Since “time ismoney”, solutions designed to safelymaximize savings will probably tend tominimize the time that fishing activities aredisrupted.

C. Marine MammalsThe less explosives and the less time thatheavy equipment is employed duringdecommissioning, the less that marinemammals will be negatively impacted. Theappropriate regulatory agencies haveexpertise in the appropriate measures toprotect marine mammals and we are availableto support and assist them. We would like tosee both environmental protection andmaximum funding made available for artificialreefs (see A. Air Quality ). This will resultfrom maximizing the shared savings, and willprobably involve finding an alternative use forthe platforms or topping them at a safe depth.These solutions are also in the interest ofmarine mammals.

D. Marine Benthic ImpactsGiven proper attention to the environmentalconcerns discussed above, the disturbance ofthe benthos should be minimized. Sincescientists believe that the productivity of thejacket remaining after decommissioning willbe enhanced by the addition of non-toxic hardsubstrate. Leaving as much as possible ofwhat is already there should be of benefit themarine environment.

Mounds of shells produced by invertebratesliving on the jackets have accumulated at thebase of rigs. Scientists believe that shellmounds provide productive nursery habitat.The ones at the base of the 4 H rigs measure

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hundreds of feet across and up to 30 feethigh. Although the trawlers are currentlydemanding that the remaining shell moundsbe removed, the state and Chevron areplanning to evaluate their habitat value. Thetrawlers have offered to contract to removethe mounds. They have also suggested thatthey might allow these productive reefs toremain, provided that the fishers areadequately compensated.

Clearly the mounds associated with theplatforms currently being evaluated should notbe removed if they are enhancing theproductivity of the marine environment.Factors to consider include: (1) the productivevalue of the mounds, (2) potential habitatenhancement from redirected funds, and (3)the avoidance of negative environmentalimpacts associated with the removal of theselarge mounds.

See section K, (Enhancement of the PlatformStructure) for a more complete discussion ofthe value of allowing hard substrate to remainand be enhanced.

E. Water QualityEnvironmental effects of decommissioningincluding water quality should receive primaryattention. Next, we would like to see thatmaximum funding is made available forartificial reefs. This will result frommaximizing the shared savings, and willprobably result from finding an alternative usefor the platforms or topping the jackets at asafe depth.

Decommissioning solutions that requireremoval of the subterranean portion of thelegs could increase the possibility of seepage.However, the plugging mechanisms we andthe agencies support make this unlikely. Theremoval of pipelines poses risk ofcontamination and will have to be reviewed ona case by case basis. The appropriateregulatory agencies have expertise in theappropriate criteria and measures to protectthe environment from adverse effects to waterquality we are available to support and assistthem.

F. Contamination/Remediation of OnshoreSitesSome of these sites may have potential valueto recreational fishers (see G. Future LandUse). Also, some of the non-toxic materials tobe removed may be better utilized asproductive marine habitat than added to

already crowded landfills. We would likethese issues considered when solutions arechosen.

G. Future Land UseIn 1992, recreational fishing contributed $2.9billion in sales to the California economy andgenerated a value added impact of nearly $5billion while supporting 153,849 jobs. For thesame year, the value added impact of thecommercial fishing industry was only 0.7billion and supported 20,820 jobs. Thefederal government estimated marine anglers’expenditures in southern California to be $536million for 1989. Most of this was related toshore or near shore based angling. Marineanglers make a far greater contribution to theeconomy than do commercial fishers, yet doso while taking a much smaller proportion ofthe state’s marine resources. The value ofrecreational fishing should be consideredwhen determining the use of piers and othercoastal sites.

H. Commercial FishingThe halibut and other fisheries impacted bytrawls would benefit, over time, if more of thesea floor was protected from these nets.State tidelands were closed to trawlers nearthe turn of the century to protect habitat andreduce over-exploitation and waste. Some ofthe waters were reopened in 1971 by thestate Legislature in an effort to save thetrawlers from the financial effects of depletedhalibut stocks. The expansion of the trawlingarea had the potential of further depletingthose stocks and was supposed to betemporary, pending an evaluation. Thestate’s evaluation concluded that, given thedramatic increase in pressure on the halibutstocks, the expansion of the halibut trawlgrounds further exacerbated the over-exploitation. The trawl fishery for the seacucumber, a prized invertebrate in Asia, wasinitiated, in part, to compensate for reducedhalibut stocks. Sea cucumbers are easilyover-exploited, and they have beenelsewhere. Local over-exploitation is alsoexpected.

Trawlers fish near the rigs because fishcongregate there. The least beneficialstructure, from the trawler’s viewpoint, includesmall unmarked pieces of debris. Althoughthese act as mini-reefs, they do pose aproblem for trawlers because trawls are notvery selective. They catch debris in addition


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to a large bycatch of unwanted marine life. Itis precisely this characteristic of bottom trawlsthat causes them to damage natural habitat.Habitat damage is one of the reasons thattrawls have been banned in state waters.

Trawlers who use other fishing gears haveattempted to persuade other commercialfishers to oppose the Rigs to Reefs programdespite the advantages provided by the reefs.As a result of conflict with the oil companies,the trawlers have demanded and receivedmoney and equipment. Fishers, other thantrawlers, may support them based fear thatthey will be negatively impacted as the publicreacts to local over-exploitation. Theirinsecurity has increased due to publicawareness that most of the world’s importantfish stocks are depleted, and that over-exploitation driven by an exploding populationis a primary cause. It is natural for them tofeel a need to band together to protect theirfreedom. However, it is not in their interest tojoin the trawlers because most of the localfishers are not deserving of the criticismdirected at the trawlers. We want to work withthem to optimize the resource enhancementpotential of Rigs to Reefs.

The influence of the trawlers is out ofproportion to their small numbers. They havereceived millions of dollars in compensationfrom the energy industry by blaming theindustry for diminished catches. The trawlerscapitalized on the industries’ unpopularity andthe lack of public awareness that over-exploitation was the primary cause forreduced trawl landings. Recently, they wereinstrumental in defeating a plan to use of the 4H rigs in a habitat improvement and researchprogram. They not only demanded that therigs be removed, but some also demanded tobe reimbursed for lost fishing opportunityduring removal. The trawlers currently aredemanding that the remaining shell moundsbe removed and have offered to contract toremove them. Scientists believe that shellmounds provide productive nursery habitat,therefore some trawlers have suggested thatthey might allow the mounds to remainprovided that the fishers are adequatelycompensated.

The influence of the trawlers has beenenhanced because they are represented bythe Environmental Defense Center. We weretold that this organization is supposed to workfor the protection and enhancement of marine

resources. This goal is not furthered bysupporting those who damage and over-exploit marine resources or by opposingresource enhancement programs.

I. Recreational FishingWe represent southern California’s largestconservation organizations dedicated toincreasing the value of marine resources tothe citizens of California. Increasedabundance of marine fishes and invertebratesis essential to achieve that end, and artificialreefs can be very beneficial. We believe thatthe design and management of reefs shouldbe based on the best available science.

Our dedication to improving habitat has beenestablished. We have provided most of thefunding for California’s artificial reef programsince its inception in 1958. With the reductionin government funding, most recentconstruction has been accomplished due toour initiative and with donated funds. Thecost of complete removal of the five platformsunder discussion has been estimated to totalseveral hundred million dollars. Partialremoval will result in savings of millions ofdollars. Chevron participates in the Rigs ToReefs programs in states bordering the Gulf ofMexico. There, 50 percent of the savingsrealized by using the rigs in the program arededicated to marine habitat enhancement.We are committed to working with responsibleagencies and industry to ensure that fundingfor the enhancement of nearshore coastalhabitat is maximized as a result of anenvironmentally sound decommissioningprocess.

Reefs are beneficial to anglers and divers aswell as to commercial fishers, because theyproduce and aggregate marine life. Fishersusing stationary gear such as most anglers,commercial hook and line, and commercialtrap fishers concentrate their efforts nearreefs. Even mobile gear fishers such ashalibut trawlers drag their nets close to reefsbecause halibut concentrate there. Tallcomplex structures such as the bottom ofplatform jackets are good to fish near but canentangle fishing gear which is dragged acrossthem. This is one reason that scientists havesuggested that the jackets be left in place asharvest refugia. Anglers would supportharvest refugia as one of several alternativemanagement concepts for artificial reefs.

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Anglers are working to implementmanagement that restores fish stocks tolevels that produce the maximum sustainablesurplus. We fund and provide volunteer staffin experimental mariculture facilities in aneffort to rebuild depleted stocks and to learnmore about our marine resources. Artificialreefs can function as habitat for mariculture.Indeed, platform jackets are presently soutilized. Mariculture offers the potential ofenabling the over-capitalized segments of thecommercial industry to move from capture toculture by raising marine life instead offurther depleting existing stocks. We want tomaximize the value of stocks to society whilewe work to maximize the quantity of importantmarine resources. Improved habitat andmanagement are essential to attain theseobjectives.

We would like to see that the maximumfunding is made available for artificial reefs.This will result from maximizing the savingsshared as part of a rigs to reefs program andwill probably involve finding an alternative usefor the platforms or topping the jackets at asafe depth.

J. Habitat ValueOnly 5 percent of southern California’sshallow marine bottom is hard substrate.Scientists have established that the habitatvalue of hard substrate is between 6 and 15times greater than that of soft substrate. Inaddition, the marine life associated with hardsubstrate are generally valued more highlythan those associated with soft substrate.Even halibut, which are commonly associatedwith sand bottom, concentrate to feed nearhard substrate.

The most productive hard substrate has highrelief such as that found in reefs. Also, thediversity of marine life increases with reefheight. Since productivity increases withavailable light, reefs should come as close tothe ocean’s surface as possible. Kelpenhances the productivity of hard substrate,but it is relatively unproductive in the absenceof additional high substrate. Some scientistshave hypothesized that an improperly locatednew reef could interfere with the productivityof nearby reefs. Others have observed thatincreasing the concentration of reefs can bebeneficial by diluting the average rate ofexploitation. The siting of new reefs shouldconsider these potential effects.

Artificial reefs have been observed to containhigher concentrations of marine life thannatural reefs. The consensus among marinescientists is that, in the absence ofexploitation, properly sited artificial reefsincrease the productivity and abundance ofmarine life in our coastal waters. However,both natural and artificial reefs have beenover exploited in southern California.

Over-exploitation and effects of urbanizationhave reduced the abundance of marine life. Itis clear that we can partially mitigate for theseeffects by creating reefs. It is characteristic ofproductive habitat to attract marine life andpredators, including man. Therefore, there isa need to develop management solutions thatappropriately balance productivity andexploitation. The issue is not if reefs shouldbe constructed, but how they should bedesigned and managed, and where theyshould be sited.

There are many available managementoptions. For example, if the reefs weretopped in deep water, it might be best to makethe remaining structure a harvest refugia forrockfish. Reefs built in shallow water couldhave more restrictive bag and size limits thanare the current norm. The choice ofrestrictions will be dependent upon socio-economic as well as biological issues.

Pipelines provide hard substrate and, ideally,should be left in place. Reasonableprecautions must be taken to protect theenvironment from toxins. Trawlers have beenprovided special gear to enable them to rollover the pipelines.

As a part of the decommissioning process,Chevron has indicated a willingness to fundthe construction and monitoring of reefs in aneffort to provide answers to the questionsrelevant to an expanded artificial reefprogram. We strongly support this approach.However, there is substantial funding currentlydedicated to the construction of artificial reefsthat could enable the process to begin thisyear. We urge industry and the regulatoryagencies to begin relevant research soon toenable us to be better informed prior to theactual decommissioning. Lets enhance theresource while increasing knowledge aboutresource enhancement.

K. Enhancement of Platform StructureThe most productive hard substrate has highrelief such as that found in reefs. Also, the


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diversity of marine life increases with reefheight. Since productivity increases withavailable light, reefs should come as close tothe surface of the ocean as possible. Kelpenhances the productivity of hard substrate,but it is relatively unproductive in the absenceof additional high substrate.

The consensus among scientists is that highrelief increases the diversity of marine life.Biomass tends to increase with the complexityof the structure, while increased complexity ofthe surface of the structure benefits juvenilestages. Steel structures such as platformjackets colonized by invertebrates providegood surfaces. Scientists also believe thathigh relief should be supplemented bycomplex low relief such as that created frompiles of recycled concrete. The habitat valueof a topped structure would likely beenhanced by the nearby placement of thetopped portion of the jacket.

Although we know enough to build reefs thatare more productive than the soft structureupon which they are founded, we believe thatwe could improve our reef building abilitygiven appropriate research. There are manyquestions concerning the optimal design ofthe complex low relief component. Webelieve that it should contain both low andhigh piles of concrete but we do not know howthey should be configured to obtain optimalresults. Similarly, we are unsure of theoptimum combination of sizes of concretecomponents. We also need to know moreabout the movement of marine life betweenreefs and reef modules. These questionshave been delineated in research proposalsby leading ecologists and fisheries experts.

There is substantial funding currentlydedicated to the construction of artificial reefsthat could enable the process to begin thisyear. We urge industry and the regulatoryagencies to expand on the research currentlyplanned so that we will be better informedprior to the actual decommissioning. Letsenhance the resource while increasingknowledge about resource enhancement.Chevron has indicated a willingness to fundthe construction and monitoring of reefs inconjunction with the decommissioningprocess. We strongly support this approachas part of a continuing effort to increase ourknowledge in areas relevant to an expandedartificial reef program.

L. Site ClearanceWe have established, in other sections, thatthe marine habitat value, marine lifeabundance and the society as a whole willreceive maximum benefits by maximizing thesavings that Chevron has agreed to use formarine resource enhancement. This willprobably result from decommissioningprogram involving: (1) the removal of thesuperstructure, (2) topping the jacket at a safedepth, (3) locating the topped portion close tothe remaining jacket, and (4) augmenting thebase of the jacket with recycled concrete.

The site destined to become the low relief reefneed only be cleared of toxic materials. Nontoxic structures (debris) outside the new reefprovide habitat value. These structures alsocan inconvenience trawlers.. Non toxicstructures clearly need not be removed if theyare in an area designated as a harvestrefugia.

In determining which of the non toxic hardsubstrate (debris) to remove, the responsibleagencies will have to balance public views,the views of scientific researchers, the desiresof the trawlers (see N. Social Impacts ), withthe value to other stakeholders and to themarine environment Fishers refer to thesematerials as “structure” and it has habitatvalue to some forms of marine life. The leastbeneficial structure, from the trawlersviewpoint, include small unmarked pieces ofdebris. Although these act as mini-reefs, theydo pose a problem for trawlers because trawlsare not very selective. They catch debris aspart of a large bycatch of unwanted marinelife. It is precisely this characteristic of bottomtrawls that also causes them to damagenatural habitat. How far should we go tofacilitate the use of destructive fishing gear?

We do not believe that the habitat value ofsmall debris is sufficient reason for it toremain. However, the cost of removal and themitigation that could be accomplished withshared savings will also need to beconsidered. We look forward to assistingthese agencies in their pursuit of solutionsthat maximize the benefits to the public.

M. Onshore DispositionThe regulatory agencies are experienced inthis area and we are available to provideassistance if needed. We would like to helpensure that the public is well informed as tothe environmental costs of alternatives.

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Creating habitat for marine life is farpreferable to adding to the waste in landfills.Moving less material also reduces airpollution. Creating reefs may increase airpollution from tugboats but it reduces airpollution from trucks. Unless the rig is left inplace or removed intact, onshore impacts willprobably be minimized by topping the rigs andallowing the appropriate part of the top of thejacket to be placed near the topped rig. If therig is in an unproductive location, the topportion might be moved to a more productivelocation, such as the edge of a near shorecanyon. All rig material could be augmentedwith recycled concrete to enhance thecomplexity of the benthic structure. We wouldlike to see the superstructure recycled if at allpossible.

Clearly, there are many disposition optionsthat provide positive benefits to society andmarine habitat. These should be fullyexplored prior to approval of options thatfurther tax our landfills. The use of concreteas reef components has the added advantageof reducing the amount of material otherwisedestined for landfills.

N. Social ImpactsThe debate concerning artificial reefs insouthern California has focused on biologicalquestions. The most common issue being: doartificial reefs produce marine life or do theyjust attract it? There is little doubt in thescientific community that artificial reefs bothproduce and attract marine life. Productionand attraction are a function of siting anddesign. However, artificial reefs can increasethe availability of marine life to predators,including people. Had the reason for thedebate been about maximizing theproductivity of the most valued marineresources, we would have increased ourefforts to: (1) learn how to design, site, andmanage reefs to maximize the production ofthe most valued marine resources (see O.Economic Impacts) and (2) learn how tobalance production and consumption. Wehave not taken advantage of majoropportunities to do so. Some of the reasonsfor this are discussed below.

California pioneered artificial reefdevelopment in the 1950s. The program hasbeen funded by millions of dollars, primarilyfrom the recreational fishing community, and,until recently, was robust. The Department ofFish and Game approved the placement near

Palos Verdes of two jackets from oil platformsin 1988. Although the project was consistentwith California policy and the National ArtificialReef Plan, the project was viewed as “oceandumping” by some, and it was canceled withlittle public discussion.

There are many reasons for opposing theconstruction of artificial reefs. However theyare often disguised and expressed in terms ofdoubts about reef productivity. The opinionthat we should leave the coastal habitat in anatural state, even if altering it could increaseproductivity, should be expressed directly.Also, reefs concentrate marine life and makeit more available to fishers and divers. This isan anathema to those who do not approve ofinjuring marine life. This opinion is oftenexpressed in terms of reef productivity. Otheropinions are related to the energy industries’poor reputation in southern California. Thereare those who do not like the idea of theindustry profiting by participating in theconstruction of artificial reefs. There would belittle acceptance of the position: “biologicalproductivity be dammed” if industry benefits.Therefore it is often expressed in terms ofproductivity. For example the use of platformjackets in reefs is precluded by the argumentthat “the only productive reefs are kelp reefs”.This statement has no factual basis and iscontradicted by available research. The biasis illustrated by the relative lack of oppositionto the use of a large steel structure in a reef atabout the same time that the use of platformjackets was being vigorously opposed..

Artificial reefs are disparaged by some whoare concerned that acknowledging theproductivity of artificial reefs would inhibitwetland restoration. The logic is thatproductive reefs might be approved asmitigation for habitat damaged duringdevelopment, especially harbor development.Although wetlands are of little benefit to themost valued fisheries in southern California,they are valued by most of us. We do not feelthat it is appropriate to disparage theproductivity of reefs in order to protectwetlands. We prefer a balanced approachthat supports both wetlands and reefs.

The importance of the attitude towardartificial reefs also varies widely amongindividuals. The views of stakeholders whofrequently interact with coastal waters wouldbe expected to be more strongly held than theviews of people who have little contact with


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the ocean. We are supporting research toevaluate public attitudes concerning artificialreefs. Such research can provide aframework in which to develop and managecoastal habitat to maximize the value tosociety.

O. Economic ImpactsIn 1992, recreational fishing contributed $2.9billion in sales to the California economy andgenerated a value added impact of nearly $5billion while supporting 153,849 jobs. For thesame year, the value added impact of thecommercial fishing industry was 0.7 billionand supported 20,820 jobs. The most recentestimate available for annual expenditures bymarine anglers in southern California was$536 million during the 1989 calendar year.Most of this was related to shore or nearshore based angling.

The value of edible fish and fish productsimported into California in 1992 was almosteight times the value of exports. Most of thelittle remaining seafood caught in our watersis not consumed by Californians. Marineanglers make a far greater contribution to theeconomy than do commercial fishers, yet doso while taking a much smaller proportion ofthe state’s marine resources. None the less,the value of the marine resources of Californiais usually expressed as a sum of the numberof pounds of each species landed bycommercial fishers times the price per pound.This number is doubled or tripled whenexpressed as the value to the economy.

The value of marine life to the stakeholdersvaries widely. A few fish are worth a greatdeal to the non-consumptive diver (snorkel orscuba diver), or catch and release angler.Each fish provides repeated pleasure overtime. Even the consumptive recreational uservalues the activity involved in obtaining“dinner” much more highly than the marketvalues the commercial landing. For example,a commercial fisher receives about $2 perpound for salmon, while economists havedetermined that anglers spend over $100 perpound for the experience of catching their ownsalmon. Sharks are being increasingly valuedby our society, yet they are usually wasted asunwanted accidental bycatch of the nets ofthe commercial swordfish and tuna fishers, orthey may be wasted in the process of takingthe fins for sale.

The cost of complete removal of the fiveplatforms under discussion has beenestimated to total several hundred milliondollars. Partial removal will result in savingsof millions of dollars. Chevron is willing toshare savings derived from using the platformjackets as part of a Rigs To Reefs program.This provides an unprecedented opportunityfor habitat enhancement. Environmentaleffects of decommissioning should receiveprimary attention and we discuss our positionson some of these in other sections. Next, wewould like to see maximum funding madeavailable for artificial reefs. This will beenabled by maximizing the shared savings,and will probably result from finding analternate use for the platforms or by toppingthem at a safe depth.

The California Rigs To Reefs program maydiffer from existing programs in other statesbecause the newly constructed reefs may notcontain material from rigs. Most of our reefsare likely to be constructed from recycledconcrete. High relief may be created fromconcrete of other appropriate materials. Ourprogram will have many benefits includingincreased knowledge of coastal marine life,habitat enhancement, cost effective recyclingfor those providing materials, and redirectionof those materials otherwise destined forcrowded landfills.

P. Fate and Longevity of MaterialsThe non-removal option would requireprotection of the platform from decay and itslife span would be maximized. Coastal pierswould require maintenance. Their value ashabitat, for recreation, or other uses couldcompensate for the cost of upkeep. Concreteused to augment and enhance the benthichabitat lasts many decades and does notpresent a problem as it ages. Topped rigsmay not be protected. However, the non toxiccomponents of the rigs that have beenapproved under the National Artificial ReefPlan have life spans estimated to be fromdecades to hundreds of years. The value ofthe platform jackets as marine habitat willcontinue beyond the date that the structuresbegin to collapse.

Clearly, there are many disposition optionsthat provide positive benefits to society and tomarine habitat. These should be fullyexplored prior to the approval of options thatfurther tax our landfills.

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APPENDICES

Appendix I: Regulatory Framework & Environmental Review Processfor the Decommissioning of Oil and Gas Facilities............... 193

Appendix II: Platform Schematic, Locations of California OffshoreFacilities, Decommissioning Decision Trees ........................ 221

Appendix III: Glossary................................................................................ 231

Appendix IV: Biographical Sketches .......................................................... 245

Appendix V: List of Attendees................................................................... 257

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APPENDIX I:

Regulatory Framework and

Environmental Review Process

for the Decommissioning of Oil and Gas Facilities

Prepared for:

DECOMMISSIONING AND REMOVAL OF

OIL AND GAS FACILITIES OFFSHORE CALIFORNIA:

RECENT EXPERIENCES AND FUTURE DEEPWATER CHALLENGES

Doubletree HotelVentura, California

September 23 – 25, 1997

Sponsored by:Minerals Management Service

andState Lands Commission

Hosted by:University of California, Santa Barbara

andUniversity of California, Berkeley


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TABLE OF CONTENTS

Introduction ......................................................................................................................... 195

I. Federal Agencies

A. National Environmental Policy Act (NEPA) .............................................................. 198

B. Major Federal Agencies with Regulatory Authorities for Decommissioningof Offshore Oil and Gas Facilities

• Minerals Management Service.......................................................................... 200• National Marine Fisheries Service..................................................................... 203• U.S. Army Corps of Engineers .......................................................................... 204• U.S. Fish and Wildlife Service ........................................................................... 205• U.S. Environmental Protection Agency ............................................................. 206• U.S. Coast Guard .............................................................................................. 207• U.S. Department of Transportation, Office of Pipeline Safety........................... 208

II. State and Local Agencies

A. California Environmental Quality Act (CEQA).......................................................... 210

B. Major State and Local Agencies with Regulatory Authorities forDecommissioning of Offshore Oil and Gas Facilities

• California State Lands Commission .................................................................. 212• California Coastal Commission ......................................................................... 214• California Department of Fish and Game.......................................................... 215• California Division of Oil, Gas, and Geothermal Resources ............................. 216• California State Fire Marshal, Hazardous Liquid Pipeline Safety Division......... 217• Local Planning and Resource Management Departments................................ 218• Local Air Pollution Control Districts .................................................................. 219

Appendix I: Regulatory Framework

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INTRODUCTION

This regulatory framework and environmental review process overview focuses on Federal, State,and local laws and regulations, as well as the National Environmental Policy Act (NEPA) and the CaliforniaEnvironmental Quality Act (CEQA), with respect to applicable regulatory authorities for offshore oil andgas facility decommissioning. Some of the decommissioning activities would include the abandonment ofoil and gas platforms, wells, pipelines, and onshore facilities.

Federal agencies are responsible for the environmental authorities under NEPA, while local andState of California agencies are responsible for the environmental authorities under CEQA. The Federal,local, and State of California agencies below are the major agencies having regulatory authorities fordecommissioning activities offshore California.

Federal Agencies

• Minerals Management Service• National Marine Fisheries Service• U.S. Army Corps of Engineers• U.S. Fish and Wildlife Service• U.S. Environmental Protection Agency• U.S. Coast Guard• U.S. Department of Transportation, Office of Pipeline Safety

State and Local Agencies

• California State Lands Commission• California Coastal Commission• California Department of Fish and Game• California Division of Oil, Gas, and Geothermal Resources• California State Fire Marshal, Hazardous Liquid Pipeline Safety Division• Local Planning and Resource Management Departments• Local Air Pollution Control Districts

Figure 1 provides a matrix of permitting responsibility for facilities in the Outer Continental Shelf, StateWaters and onshore areas.

PERMIT REQUIREMENTS BY FACILITY LOCATION

Permit Requirement by Facility LocationFederal OCS State Waters Onshore – County/City

Federal AgenciesMinerals Management Service- Lease Conditions/Stipulations z

- Development and Production Plan z

- Lease Term Pipeline Application z

- Pipeline Right-of-Way z

EPA – NPDES Permit z

ACOE – Section 10 Permit z z z

USCG – Aids to Navigation z z

State AgenciesCalifornia Coastal Commission - Consistency Certification z

- Coastal Development Permit z

SLC – Lease Agreement/Permit z z

RWQCB – NPDES Permit z z

CDF&G – Section 1603 z

City or CountyPreliminary Development Plan z

Conditional Use Permit z

Final Development Plan z

Coastal Development Plan z

Misc. Permits z

Air Pollution Control District - Authority to Construct z z z

- Authority to Operate z z z

Figure 1

. Perm

it Requirem

ents by Facility Location196

Proceedings: D

ecomm

issioning Workshop, S

eptember 1997


197

National Environmental Policy Act (NEPA)

and

Major Federal Agencies with Regulatory Authorities forDecommissioning of Offshore Oil and Gas Facilities


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NATIONAL ENVIRONMENTAL POLICY ACT (NEPA)

NEPA (Public Law 91-190) was promulgated in 1970. It requires all administrative agencies of theFederal Government to consider the environmental impacts of their actions in the process of projectdevelopment and decision-making. Further, NEPA allows other officials, Congress, and the public toindependently evaluate the environmental consequences of government action. Finally, NEPA directs allFederal agencies to carry out their duties to the fullest extent possible in order to preserve and protect theenvironment and public health, safety, and productivity.

In many respects, the core requirement of NEPA is Section 102, under which environmentalimpact statements (EIS) are required for Federal actions that could significantly affect the environment.Under this provision, every recommendation or report on proposals for major Federal actions significantlyaffecting the quality of the human environment must include a detailed statement on: (1) theenvironmental impact of the proposed action; (2) any adverse environmental effects which cannot beavoided should the proposal be implemented; (3) alternatives to the proposal; (4) the relationship betweenlocal short-term uses of the environment and the maintenance and enhancement of long-term productivity;and (5) any irreversible and irretrievable commitments of resources involved in the proposal. According tothe Council on Environmental Quality Guidelines, the primary purpose of the EIS is to ensure that thepolicies and goals of the Act are carried out. Federal agencies are to make their decisions based on theinformation contained in the EIS, as well as on other material.

The threshold question is whether an EIS is even required (See Figure 2). The answer dependson whether the proposal under consideration constitutes a "major Federal action significantly affecting theenvironment." "Federal Action" means both actions that a Federal agency undertakes and those theagency merely has the discretion to permit or approve. The "major action" provision allows agencies toavoid preparation of an EIS for minor matters with little potential for adverse impact. The standard"significantly affecting the quality of the human environment" means having an important or meaningfuleffect (direct or indirect) upon a broad range of aspects of the human environment. The cumulativeimpact with other projects must be considered.

An "Environmental Assessment (EA)" is prepared when a Federal agency determines an actionmay have no significant impact. The EA is a concise document briefly providing sufficient evidence andanalysis for determining whether the proposal would have a significant impact and aiding the agency indetermining when an EIS is necessary.

The basic rules for determining whether an EIS is adequate depends on: (1) whether the agencyin good faith has taken an objective look at the environmental consequences of a proposed action andalternatives; (2) whether the EIS provides detail sufficient to allow those who did not participate in itspreparation to understand and consider the pertinent environmental influences involved; and (3) whetherthe EIS explanation of alternatives is sufficient to permit a reasoned choice among different courses ofaction. Particular attention must be given to the analysis and comparison of alternatives to the proposedproject. The details regarding EIS criteria may be found in the NEPA Regulations adopted by the Councilon Environmental Quality. The Council was created under NEPA to assist with the implementation of theAct.


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Exclusion/Exemption NoApplies Exclusion/Exemption

No EISEIS Required

Figure 2NEPA Environmental Review Process: An Overview

Proposed AgencyAction

CategoricalExclusion orExemption

EnvironmentalAssessment

Notice of Intent

Scoping Process

Draft EIS

Agency/PublicComments

Final EIS

Record of Decision

Agency ActionAgency Action

Finding of NoSignificant Im pact

Agency Action


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MINERALS MANAGEMENT SERVICE (MMS)

The MMS is responsible for regulating oil and gas exploration and development operations on theFederal Outer Continental Shelf (OCS) which offshore California are those submerged lands locatedseaward of the three-mile State lands boundary. Regulations for oil and gas operations on the OCS arefound in 30 Code of Federal Regulations (CFR) Part 250. The following is a summary of the MMSregulatory requirements pertaining to the decommissioning of OCS oil and gas facilities that are includedin CFR 250 and the OCS lease instrument. Interested parties should refer to the regulations for additionaldetail.

OCS OIL AND GAS REGULATIONS (CFR 30 - 250)

Platform Removal and Location Clearance (250.143)

• Structures are to be removed in a manner approved by the Regional Supervisor (RS) that ensuresthe location has been cleared of all obstructions to other activities in the area.

• All platforms (including casing, wellhead equipment, templates, and piling) shall be removed to adepth of at least 15 feet below the ocean floor or to a depth approved by the RS based upon thetype of structure or ocean bottom conditions.

• The lessee shall verify the location has been cleared of all obstructions.

• The results of a location clearance survey conducted by the company performing the work shallbe submitted to the RS.

• The company performing the work shall submit a letter to the RS certifying the area was clearedof all obstructions, the date the work was performed, the extent of the area surveyed, and thesurvey method used.

Permanent Abandonment of Wells (250.110, 250.111, 250.112, 250.114)

• All well sites shall be cleared in a manner so as to avoid conflict with other uses of the OCS.

• The lessee shall not initiate abandonment operations without the prior approval of the DistrictSupervisor (DS).

• The lessee must submit a request to abandon a well on Form MMS-124, Sundry Notices andReports on Wells, to the DS for approval, and submit a subsequent report on abandonmentdescribing procedures and results within 30 days of completion of the work.

• Form MMS-124 shall specify the date the work is to be performed, the extent of the area to besearched around the location, and the search method utilized.

• All wellheads, casings, pilings, and other obstructions shall be removed to a depth of at least 15feet below the mud line or to a depth approved by the DS.

• The lessee shall verify that the location has been cleared of all obstructions.

• The requirements for removing subsea wellheads or obstructions or for verifying locationclearance may be reduced or eliminated if the DS determines the wellheads or other obstructionsdo not constitute a hazard to other uses of the seafloor or other legitimate uses of the area.

• The lessee shall verify site clearance after abandonment by one or more of the following methodsas approved by the DS:


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(1) Drag trawl in two directions across the location.

(2) Perform a diver search around the wellbore.

(3) Scan across the location with a side-scan or on-bottom scanning sonar, or

(4) Use other methods based on particular site conditions.

• The lessee shall submit certification the area was cleared of all obstructions, the date the workwas performed, the extent of the area searched around he location, and the search methodutilized on Form MMS-124.

Temporary Abandonment of Wells (250.113)

• Subsea wellheads, casing stubs, or other obstructions remaining after temporary abandonmentabove the seafloor shall be protected in such a manner as to allow commercial fisheries gear topass over the structure without damage to the structure or fishing gear.

• Depending on water depth, nature and height of obstruction above the seafloor, and the types andperiods of fishing activity in the area, the DS may waive this requirement.

• The lessee shall follow the requirements of the U.S. Coast Guard in identifying and reportingsubsea well heads, casing stubs, or other obstructions extending above the mud line.

Abandonment of DOI Pipelines (250.156)

• A pipeline may be abandoned in place, if the RS determines it does not constitute a hazard tonavigation, commercial fishing operations, or unduly interfere with other uses in the OCS.

• Pipelines abandoned in place shall be flushed, filled with seawater, cut, and plugged with the endsburied at least 3 feet

.General Requirements for a Pipeline Right-of-Way Grant (250.159 and 250.164)

• The holder of a right-of-way grant shall submit an application for the relinquishment of the grant tothe RS.

• A relinquishment shall be effective on the date it is filed subject to the satisfaction of alloutstanding debts, fees, or fines and requirements

• Upon relinquishment, forfeiture, or cancellation of a right-of-way grant, the right-of-holder shallremove all platforms, structures, domes over valves, pipes, taps, and valves along the right-of-way.

• All of these improvements shall be removed by the holder within 1 year of the effective date of therelinquishment, forfeiture, or cancellation unless the requirement is waived in writing by the RS.

• All such improvements not removed within the time period provided herein shall become theproperty of the U.S., but that shall not relieve the holder of liability for the cost of their removal orfor restoration of the site.


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• The holder of the right-of-way grant is responsible for accidents or damages which might occur asa result of failure to remove improvements and equipment and restore a site.

Supplemental Regulations

The requirements for specific offshore decommissioning activities, as outlined above, aresupplemented by generic regulations of 30 CFR Part 250 that relate to the conduct of offshoredecommissioning activities. These include:

- 250.3, Performance Requirements: Allows the use of new or alternative techniques,procedures, equipment, or activities other than those prescribed if they afford a degree ofprotection, safety, or performance equal to or better than that intended to be achieved bythe regulations.

- Also provides the MMS the flexibility to depart from the operating requirements of theregulations of this part when such departures are necessary for ……. The conservation ofnatural resources, or the protection of life (including fish and other aquatic life), property,or the marine coastal, or human environment.

- 250.20, Safe and Workmanlike Operations: Requires that all offshore operations beconducted and facilities maintained in a safe and workmanlike manner to a levelconsistent with the regulatory objectives.

- 250.22, Best Available and Safest Technologies : The MMS requires that the bestavailable and safest technologies (BAST) be used when practicable.

OCS LEASE INSTRUMENT

Removal of Property on Termination of Lease

• Within a period of 1 year after termination of this lease in whole or in part, the lessee shall removeall devices, works, and structures from the premises no longer subject to the lease in accordancewith applicable regulations and orders of the Director.

• The lessee may, with the approval of the Director, continue to maintain devices, works, andstructures on the leased area for drilling or producing on other leases.


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NATIONAL MARINE FISHERIES SERVICE (NMFS)

The Protected Species Management Division (PSMD) of the NMFS is responsible for themanagement of protected marine species (i.e., marine mammals, sea turtles and winter-run chinooksalmon) in the Southwest Region, under the provisions of the Endangered Species Act (ESA) and theMarine Mammal Protection Act (MMPA). The PSMD reviews NEPA and CEQA environmental documentsprepared for projects that are likely to affect protected marine species. If a determination is made that anon-Federal action "may affect" protected marine species, alternatives will be recommended in order toinsure that these species are not affected by the proposed project. In contrast, all Federal agencies arerequired to consult with the Secretary of Commerce/Interior, under Section 7(a)(2) of the ESA, to insurethat any action it authorizes, funds, or carries out will not jeopardize the continued existence of any listedspecies or result in the destruction or adverse modification of critical habitat.

Informal Section 7 Consultation is initiated when a Federal agency or designated non-Federalrepresentative provides to the NMFS Regional Director (for most protected marine species): (1) writtenrequest for a list of any "listed species" (including any proposed species, designated critical habitat, orproposed critical habitat) that may be present in the project area; or (2) written notification of the listedspecies that may be present in the project area. Within 30 days of the notification receipt of or request fora species list, the Regional Director shall concur or revise the list or advise the Federal agency in writingwhether any listed species may be present in the project area. The Federal agency prepares within 90days of receipt of the species list: (a) a biological assessment (BA) or (b) equivalent environmental impactstatement (EIS) or environmental assessment (EA) that evaluates the effects of the proposed action onany listed species. Subsequently, the Federal agency submits the BA or equivalent document to theRegional Director for review (at the option of the Federal agency, Formal Section 7 Consultation could beinitiated at this point). If the BA or equivalent document concludes that no listed species are present thatare likely to be adversely affected by the action and the Regional Director concurs with this finding, theRegional Director will respond in writing within 30 days and conclude the consultation process. However,the Regional Director may request the Federal agency to initiate formal consultation if the BA or equivalentdocument concludes that listed species are present that are likely to be adversely affected by the action.

Formal Section 7 Consultation is initiated when a written request to initiate formal consultation issubmitted to the NMFS Regional Director by the Federal agency. The NMFS (in the case of mostprotected marine species) will formulate a biological opinion (within 90 days of receipt of the request)which will include the NMFS's finding on whether the action is likely to jeopardize the continued existenceof listed species or result in the destruction or adverse modification of critical habitat. If a "no jeopardy"biological opinion is issued; conservation recommendations to assist the Federal agency in reducing oreliminating impacts may be included. If a "jeopardy" biological opinion is issued; it will include reasonableand prudent alternatives (if any). An Incidental Take Statement will be included in the biological opinion ifthe NMFS determines that a Federal action will "take" listed species.

In addition to Section 7 requirements of the ESA, Federal and non-Federal actions that are likelyto "take" listed or non-listed marine mammals must receive authorization under Section 101(a)(5) of theMMPA- Section 101(a)(5) provides a mechanism for allowing (upon request) the incidental taking of smallnumbers of marine mammals by U.S. citizens who engage in a specified activity other than commercialfishing. Incidental taking may be authorized for a period of up to five years as long as the taking has onlya negligible impact on the species or stock. Regulations must be promulgated that set forth permissiblemethods of taking, monitoring, and reporting.


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U.S. ARMY CORPS OF ENGINEERS (COE)

33 CFR Part 320 - General Regulatory Policies

The COE has regulated certain activities in the nation's waterways since 1899. The regulatoryjurisdiction of the COE includes all ocean and coastal waters within a zone three geographic (nautical)miles seaward of the baseline (territorial seas). In addition, wider zones are recognized for navigablewaters of the United States for special regulatory powers exercised over the Outer Continental Shelf(OCS).

Section 10 of the River and Harbor Act of 1899 - prohibits the unauthorized obstruction oralteration of any navigable water of the Unites States. The construction of any structure in or over anynavigable water of the United States, the excavating from or depositing of material in such waters, or theaccomplishment of other work is unlawful unless the work has been specifically authorized by the Corps ofEngineers. The authority to prevent obstructions to navigation in navigable waters of the United Stateswas extended to artificial islands, installations, and other devices located on the seabed, to the seawardlimit of the OCS, by Section 4(f) of the OCS Act of 1953, as amended.

Section 404 of the Clean Water Act - prohibits the unauthorized discharge of dredged or fillmaterial into waters of the United States. The selection and use of dredged disposal sites will be inaccordance with the guidelines developed by the Environmental Protection Agency (EPA) Administrator inconjunction with the Secretary of the Army. The EPA Administrator can deny, prohibit, restrict or withdrawthe use of any defined area as a disposal site whenever, if it is determined, that after notice andopportunity for public hearing and after consultation with the Secretary of the Army, that the discharge ofsuch materials into such areas will have an unacceptable adverse effect on municipal water supplies,shellfish beds and fishery areas, wildlife, or recreational areas.

Permits Issued

1. Individual Permits (33 CFR Part 325) - are processed through the public interest reviewprocedures, public notice publication, and receipt of comments.

2. Letters of Permission (33 CFR 325.2(e)(1) - are issued through an abbreviated processingprocedure which includes coordination with Federal and state fish and wildlife agencies, publicinterest evaluation, but without publishing a public notice.

3. Nationwide Permits (33 CFR Part 330) - are general permits issued by the Chief of Engineers andare designed to regulate with little, if any, delay or paperwork, certain activities having minimalimpacts.


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U.S. FISH AND WILDLIFE SERVICE (FWS)

The primary concern of the FWS is the protection of public fish and wildlife resources and theirhabitats. The FWS mandates require that it provide comments on any public notice issued for a Federalpermit or license affecting the nation's waterways, in particular, U.S. Army Corps of Engineers' permitspursuant to Section 404 of the Clean Water Act and Section 10 of the Rivers and Harbors Act of 1899.

In addition, the FWS administers certain portions of the Endangered Species Act (ESA) of 1973,as amended. Section 9 of the ESA prohibits any taking of a listed species. The definition of "take"includes to harass, harm, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to engage in anysuch conduct. A notable component of this definition is the definition of "harm. “‘Harm’ in the definition of'take' in the ESA means an act which actually kills or injures wildlife. Such act may include significanthabitat modification or degradation where it actually kills or injures wildlife by significantly impairingessential behavior patterns, including breeding, feeding, or sheltering (50 CFR 17.3)." Anyone whoengages in a take would be subject to prosecution under Section 9 of the ESA. Such taking may occuronly under the authority of the FWS through a permit pursuant to Section 7 or Section 10, as mandated inthe ESA.

Section 7(a)(1) of the ESA requires all Federal agencies to use their authorities in furtherance ofthe purposes of the Act by carrying out programs for the conservation of endangered and threatenedspecies. Section 7(a)(2) requires Federal agencies to review their proposed activities and determinewhether listed species will be affected. Section 7(a)(4) requires Federal agencies to confer with the FWSon any agency action that is likely to jeopardize the continued existence of a proposed species.Information consultation or conference may be used to exchange information and resolve conflicts withrespect to listed or proposed species prior to a written request for formal consultation or conference.

It is important to note that the FWS will confer on actions affecting Federally listed endangered orthreatened species. The National Marine Fisheries Service takes the lead on all marine mammals (exceptsea otters, walrus, manatees/dugongs, and polar bears), including those that are Federally listed asendangered or threatened species.


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U.S. ENVIRONMENTAL PROTECTION AGENCY (EPA)

The EPA’s role in the Clean Water Act (CWA) Programs which may affect decommissioning ofOCS platforms, pipelines, and onshore facilities include:

National Pollution Discharge Elimination System (NPDES) Permit Program

Section 301 (a) of the CWA requires an NPDES permit for discharges of pollutants from pointsources to surface waters. The following discharges could accompany the decommissioning of OCSplatforms, pipelines, or onshore facilities and, thereby, require an NPDES permit:

1. Discharges associated with the flushing of pipelines prior to removal or decommissioning in place.

NPDES permits for these discharges would include technology-related effluent limitations and anyadditional limits necessary to ensure compliance with the Ocean Discharge Criteria regulations(40 CFR 125, Subpart M). Permits for these discharges would have to consider the nature of thedischarges and the pollutants that might be present. Permits issued in Federal waters (3 milesfrom the coast and beyond) are issued by the EPA, while those in state waters or onshore areissued by the California Regional Water Quality Control Boards (RWQCBs).

2) Storm water runoff from onshore facilities during dismantling (if 5 or more acres would bedisturbed).

The 1987 Water Quality Act requires that NPDES permits be issued for storm water dischargesassociated with industrial activity. On November 16, 1990, the EPA promulgated final regulations(55 Fed. Reg..47990) which set forth permit application requirements and also define thecoverage of the program. These regulations require permits for construction activity (includingdismantling) where 5 or more acres are disturbed. As such, storm water runoff occurring duringthe dismantling of onshore facilities could be subject to NPDES permitting. On August 20, 1992,the State of California issued a general NPDES permit for construction site runoff that would covermost storm water discharges associated with decommissioning of onshore facilities.

3) Miscellaneous discharges such as sanitary and domestic wastes that may occur from the platformduring part of the decommissioning phase.

EPA-Region 9 has issued a general permit and individual permits for some platforms thatauthorize and set forth effluent limitations and monitoring requirements for the above dischargesin Federal waters. Similar permits have been issued by the California RWQCBs for the samedischarges in state waters.

Section 404 Permits

Section 404 of the CWA requires permits for discharges of dredged or fill material into waters ofthe United States (excluding discharges more than 3 miles from the coast). Although the U.S. ArmyCorps of Engineers issues Section 404 permits; the EPA has an oversight role regarding theimplementation of this permit program. Various Memorandum of Agreements (MOAs) have beendeveloped between the EPA and U.S. Army Corps of Engineers regarding Section 404 permit reviewprocedures. Platform or pipeline removal could require a Section 404 permit for backfilling operations.On December 24, 1980, the EPA adopted guidelines that set forth the procedures for evaluating proposeddischarges and determining when permits may be granted.


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U.S. COAST GUARD (CG)

33 CFR Part 62 - United States Aids to Navigation System

The CG administers the United States Aids to Navigation System. The system consists ofFederal aids to navigation operated by the CG, aids to navigation operated by the other armed services,and private aids to navigation operated by other persons.

The CG maintains systems of marine aids to navigation consisting of visual, audible, andelectronic signals that are designed to assist the prudent mariner in the process of navigation. Theprimary objective of the aids to navigation system is to mark navigable channels and waterways, andobstructions in areas of general navigation that may not be anticipated. Other waters, even if navigation,are generally not marked.

33 CFR Part 67 - Aids to Navigation on Artificial Islands and Fixed Structures

The regulations in this part prescribe the obstruction lights and fog signals to be operated asprivately maintained maritime aids to navigation on artificial islands and structures which are erected on orover the seabed and subsoil of the Outer Continental Shelf and in the waters under the jurisdiction of theUnited States, for the purpose of exploring for, developing, removing and transporting resourcestherefrom.

"Structures" include all fixed structures, temporary or permanent, for which a Corps of Engineers'permit is issued. It shall include, but is not necessarily limited to, all drilling platforms, productionplatforms, quarters platforms, pipe line riser platforms, manifold platforms, loading platforms, boatlandings, caissons, well protective structures, tank battery barges submerged on station, drilling bargessubmerged on location, artificial islands and all other piles, pile clusters, pipes, or structures erected in thewaters.

33 CFR Part 153 - Control of Pollution by Oil and Hazardous Substances and Discharge Removal

This part concerns notification to the CG of the discharge of oil or hazardous substances asrequired by the Federal Water Pollution Control Act (FWPCA), as amended; the procedures for theremoval of a discharge of oil; and the costs that may be imposed or reimbursed for the removal of adischarge of oil or hazardous substances under the FWPCA. Chief, Office of Marine Safety, Security andEnvironmental Protection is the CG Officer designated by the Commandant to assist and advise theCommandant on matters related to marine environmental response, port and environmental safety, andwaterways management.

Oil Pollution Act (OPA) of 1990

OPA has new provisions for oil liability; prevention; preparedness and cleanup pertaining tovessels, offshore oil and gas facilities, onshore terminals, and other petroleum industries. Majorprovisions of the law include: (1) oil pollution liability and compensation; (2) prevention and removal of oilpollution; (3) oil pollution research and development program; and (4) amendments to the oil spill liabilitytrust fund. The U.S. USCG has greater responsibility to direct oil spill cleanups.


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U.S. DEPARTMENT OF TRANSPORTATIONOFFICE OF PIPELINE SAFETY (OPS)

OPS is a part of the Research and Special Programs Administration, U.S. Department ofTransportation. OPS has regulatory authority over pipeline safety under the (1) Natural Gas PipelineSafety Act of 1988, as amended; (2) the Hazardous Liquid Pipeline Safety Act of 1979; and (3) theHazardous Materials Transportation Act, as amended, OPS regulations are in 49 of the Code of FederalRegulations (CFR). 49 CFR Part 192 - Transportation of Natural and Other Gas By Pipeline: MinimumFederal Standards and 49 CFR Part 195 Transportation of Hazardous Liquids By Pipeline are the twomajor sections governing pipeline safety.

49 CFR 192.727 Abandonment or Inactivation of Facilities

a) Each operator will provide an operating and maintenance plan for abandonment or deactivation ofpipelines.

b) Each pipeline abandoned in place must be disconnected from all sources and supplies of gas;purged of gas; in the case of offshore pipelines; filled with water or inert materials; and sealed atthe ends. The pipeline need not be purged when the volume of gas is so small that there is nopotential hazard.

c) Except for service lines, each inactive pipeline that is not maintained must be disconnected fromall sources and supplies of gas; purged of gas; in the case of offshore pipelines; filled with wateror inert materials; and sealed at the ends. The pipeline need not be purged when the volume ofgas is so small that there is no potential hazard.


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California Environmental Quality Act (CEQA)

and

Major State and Local Agencies with Regulatory Authoritiesfor Decommissioning of

Offshore and Onshore Oil and Gas Facilities


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CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA)

CEQA was enacted in 1970 in response to growing concern over environmental protection andhas four basic purposes: to inform the public and governmental decision-makers of potentialenvironmental effects of proposed activities; to identify ways to reduce or avoid environmental damage; toprevent damage by requiring changes in projects through alternative projects and/or mitigation measures;and to make the public aware if an approved project will have significant environmental effects. CEQAregulations are found in the Public Resources Code, Section 21000, et seq.) and the CEQA Guidelines(California Code Regulations, Title 14, Section 15000, et seq.).

Any activity proposed, funded, or permitted by a state or local public agency which has thepotential for resulting in a physical change in the environment, is considered a "project" by CEQA- Unlessa project is statutorily or categorically exempt from CEQA review, either a Negative Declaration (ND) orEnvironmental Impact Report (EIR) must be prepared to assess potential impacts to the environment.Generally, an EIR is required if a project (individually or cumulatively) has a significant effect on theenvironment. If there is no substantial evidence that a project may cause a significant effect on theenvironment, then an ND may be prepared (See Figure 3).

Very clearly, CEQA has a profound effect on applications for all types of proposed activities. Mostpublic agencies have devised internal policies, systems, and environmental management divisions tomaintain responsibilities as required by CEQA.

CEQA is continuously modified and interpreted by legislation and court decisions that reflectenvironmental changes and concerns of public agencies, developers, special interest groups and thegeneral public.

Mitigation Monitoring (Public Resources Code, Section 21081.6)

Legislation adding this section to CEQA was enacted in 1988 to assure that mitigation measuresimposed in an environmental document are monitored for proper compliance and to analyze theeffectiveness of the measures. A public agency must adopt a reporting and monitoring program wheneverit makes a finding relative to mitigating or avoiding significant environmental effects of a project. Thisprogram puts "teeth" in the CEQA process by causing public agencies to monitor projects they haveapproved so that specified mitigation measures are not ignored, avoided, or modified.

Phases in the CEQA Environmental Review Process

Normally, the CEQA process entails three separate phases. The first phase consists of preliminary reviewof a project to determine whether it is subject to CEQA. The second phase involves preparation of anInitial Study to determine whether the project may have a significant environmental effect and thepreparation of a ND if no significant effects will occur. The third phase is the preparation of an EIR if theproject may have a significant environmental effect (CEQA Guidelines Sec. 15002(k).


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Figure 3. Steps in the Environmental Review Process under CEQA

Preliminary Review♦ Application Submitted to the Lead Agency

♦ Determination that Application is Complete (30 Days)*♦ Determination that Project is Subject to CEQA

♦ Review for Exemptions♦ Start of EIR/Negative Declaration Time Limits

Initial Study♦ Check List Completed

♦ Consultation with Responsible and Trustee Agencies♦ Decision to Prepare EIR or Negative Declaration (30 days)*

Environmental Impact Report

♦ Notice of Preparation sent to Responsibleand Trustee Agencies

♦ Responses to Notice of Preparation sent toLead Agency (30 days)

♦ Preliminary Draft EIR prepared

♦ Independent review by Lead Agency

♦ Draft EIR completed and submitted for review

♦ Public Notice and Review of Draft EIR (30-45days)

♦ Written Comments received

♦ Response to comments sent to commentingagencies for review (10 days)

♦ Final EIR certified by Lead Agency (within 1year after acceptance of completeapplication)*

♦ Findings written and adopted

♦ Mitigation reporting and monitoring programadopted

♦ Lead Agency makes decision on project

♦ Notice of Determination filed and posted(within 5 working days of project approval)

♦ Fish and Game review fee paid ($850)

♦ Responsible Agency makes decision onproject (180 days)*

Negative Declaration

♦ Mitigation measures identified and agreed toby project proponent

♦ Draft Negative Declaration prepared

♦ Public Notice and Review (21-30 days)

♦ Responses to Negative Declaration received

♦ Comments “considered”

♦ Negative Declaration completed (within 105days after acceptance of completeapplication)*

♦ Commenting agencies notified of date ofhearing on project

♦ Negative Declaration adopted

♦ Mitigation reporting and monitoring programadopted

♦ Lead Agency makes decision on project(within 180 days after acceptance ofcomplete application)*

♦ Notice of Determination filed and posted(within 5 working days of project approval)

♦ Fish and Game Review fee paid ($850)

♦ Responsible Agency makes decision onproject (180 days)*

Phase 1

Phase 2

Phase 3

*Applicable only to projects subject to the Permit Streamlining Act


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CALIFORNIA STATE LANDS COMMISSION (SLC)

The SLC is responsible for the management of extractive development of mineral resourceslocated on State lands. The public lands under the SLC's jurisdiction include sovereign and school lands.Oil and gas development has primarily been concentrated on those sovereign tide and submerged landsadjacent to the coast and out three nautical miles offshore southern California.

Division 6 of the Public Resources Code (PRC) provides the statutory framework for theCommission's responsibilities. The statutory requirements are implemented through Title 2 of theCalifornia Code of Regulations. To carry out these responsibilities, SLC staff provides land management,resource management, and engineering oversight services for all marine facilities in state waters pursuantto leases issued by the SLC. These activities include all oil and gas drilling and production facilities. Theoversight responsibilities extend from the construction and development stages of a project, through itsoperational life and decommissioning and abandonment phases.

The following is a brief summary of the principal SLC statutory and regulatory requirementspertaining to decommissioning of offshore oil and gas facilities.

General:

Section 6216.1 (PRC) authorizes the Commission to remove or cause to be removed anymanmade structures or obstructions from ungranted lands under its jurisdiction if the Commissiondetermines that such removal is appropriate and the Attorney General advises that there is nolegal recourse to compel other responsible parties to effect such removal.

Section 6819 (PRC) directs the Commission to promulgate rules and regulations to require anyperson extracting oil or gas or other minerals from lands under the jurisdiction of the Commissionto remove beach and underwater obstructions.

Section 6829 (PRC) requires every oil and gas lease executed by the Commission to containprovisions specifying methods of operation and standard requirements for carrying on operationsin proper and workmanlike manner; the prevention of waste; the protection of safety and health ofworkmen; and the liability of the lessee for personal injuries and property damage.

Section 8755 (PRC) requires the Commission to adopt rules, regulations, and guidelines, andCommission leasing policies governing the operation of all marine terminals within the state, andall marine facilities under lease from the Commission to minimize the possibilities of a dischargeof oil.

Section 8756 (PRC) requires periodic review of these regulations to ensure that all operators ofmarine terminals within the state and marine facilities under the Commission's jurisdiction alwaysprovide the best achievable protection of the public health and safety and the environment.

Section 2125 et. Seq. (CCR) provide specific requirements for oil and gas drilling, production,and pollution control, including the requirements that all operations be carried on in accordancewith accepted good oilfield practice, that prevents and eliminates pollution and assures protectionof human health and safety. In addition, the regulations require submission and Staff approval ofOil Spill Contingency Plans and Critical Operations and Curtailment Plans.

Wells:

Section 2128(q) (CCR) provides for plugging and abandonment of wells. This section addressesthe design, placement, and testing of cement plugs pumped into the wellbore to isolatehydrocarbon zones and prevent future leakage. Minimum requirements are specified for isolationof cased and uncased hole, plugging of perforated intervals, isolation of zones behind cemented


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or uncemented casing, junk in hole or collapsed casing, plugging of casing stubs, plugging ofannular spaces, surface plugs, and surface clearance. Written Staff approval of individual wellabandonment programs is required prior to commencement of rig operations.

Platforms and Pipelines:

Section 2122 (CCR), Lease Operations Offshore, requires timely removal of structures orfacilities used for the drilling of wells that are no longer operative.

Section 2123 (CCR), Lease Operations on Uplands, specifies similar requirements for onshorefacilities used to drill offshore.

Section 2124 (CCR), Surrender of Leased Premises, requires that upon expiration of a lease, thelessee must surrender the lease with permanent improvements in good order and condition or, atthe option of the Commission, to remove all structures and facilities as specified by theCommission.


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CALIFORNIA COASTAL COMMISSION (CCC)

The California Coastal Act of 1976 (Public Resources Code Section 30000 et seq.), thefoundation of the Federally approved California Coastal Management Plan (CCMP), was enacted by theState Legislature to provide for the conservation and development of the State's 1,100-mile coastline.Under the Coastal Act and the CCMP, the Commission must consider the impacts of removal andabandonment activities on resources and uses within the coastal zone. Although removal andabandonment projects generally have overall environmental benefits, specific activities including vesseloperations and equipment use (e.g., the equipment proposed to cut a platform's legs prior to platformremoval) can potentially cause adverse impacts to marine resources, sensitive species and habitats,water quality (both from project-related operations and upset events such as an oil spill), air quality,commercial and recreational fishing, other recreational opportunities such as surfing and boating, culturalresources, aesthetics, and access.1

With regard to the removal or decommissioning of offshore oil and gas structures, Coastal ActSection 30106 includes under the definition of "development" the following: "... on land, in or under water,the ... change in the [intensity of use of land and water, and]; ... demolition, or alteration of the size of anystructure....... Section 30600(a) states in part: "... any person wishing to perform or undertake anydevelopment in the coastal zone ... shall obtain a coastal development permit." Consequently, mostremoval and decommissioning activities occurring within the coastal zone including state waters willrequire a coastal development permit (CDP).

In addition, the Federal Coastal Zone Management Act (CZMA) and the regulations of theSecretary of Commerce give the Commission authority to review Federally licensed or permitted activities"in or outside of the coastal zone affecting any land or water use or natural resource of the coastal zone"to assure that such activities are conducted in a manner consistent with the enforceable policies of theCCMP. (See CZMA Section 307(c)3)(A) and (B); 15 CFR 930.50 and 930.70). The Commission may alsoreview renewals and major amendments of Federally licensed or permitted activities (15 CFR 93051(b)).For example, the MMS requires in its leases and in an operator's Development and Production Plan(DPP) that the operator provide for the abandonment of wells, removal or decommissioning of platformsand pipelines, and clearance of the project site of all obstructions to other activities in the area (30 CFRSections 250.100-4; 250-143; and 250-156.) Although an decommissioning plan may be included in aDPP, the DPP and Environmental Impact Report/Statement (EIR/S) may not address specific removal anddecommissioning activities and associated environmental impacts in sufficient detail for the Commissionto make a complete assessment of the impacts of these activities to the coastal zone. Therefore, theCommission typically reviews the abandonment phase of a project separately from the developmentphase.

1 Coastal Act Chapter 3 policies that may be pertinent to the Commission's review of removal and decommissioningprojects address marine resources and environmentally sensitive habitat areas (Section 30230, 30231 and 30240),oil spills (Section 30232), air quality (Section 30253(3)), commercial and recreational Fishing (Section 30234.5),recreation (Section 30220), cultural resources (Section 30244), visual quality (Section 30251), public access(Section 30211), and cumulative effects (Section 30250).


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CALIFORNIA DEPARTMENT OF FISH AND GAME (CDF&G)

The CDF&G's participation in offshore oil and gas development and decommissioning process isprimarily as a review and commenting agency. The CDF&G reviews NEPA and CEQA documents withrespect to fish and wildlife resource and habitat impacts resulting from project implementation.Specifically, the CDF&G reviews Federal permit actions under the authority of the Fish and WildlifeCoordination Act. These include permits from the U.S. Army Corps of Engineers, U.S. Coast Guard, andother Federal permits.

In addition, the CDF&G reviews proposed state permits issued by State Lands Commission andRegional Water Quality Control Board (NPDES permits) and provides comments and recommendationsfor project modification as well as mitigation measures and permit conditions to offset or eliminateresource and habitat losses which would result from project implementation.

A permit for the use of explosives in state waters is required pursuant to Fish and Game CodeSection 5500.


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CALIFORNIA DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES (DOGGR)

The California Department of Conservation's DOGGR is responsible for supervising the drilling,operation, maintenance, and abandonment of wells throughout the State, including those wells within theterritorial seas. The Division enforces statutes in Division 3 of the Public Resources Code and regulationsin Title 14 of the California Code of Regulations. Division staff in district offices evaluates operator wellapplications on engineering and geologic bases and issue permits to conduct well operations.

General plugging and abandonment regulations require the well bores to be plugged with cementacross various intervals, including the oil- and gas-producing zones, casing stubs and shoes, and at thesurface. Furthermore, any intervals not plugged with cement must be filled with drilling mud of sufficientdensity to control subsurface zone pressures. All operations must be carried out following good oil fieldpractices and with appropriate safety equipment installed. In addition, Division inspectors conduct onsiteverification of many of the operator's procedures to plug and abandon wells.


217

CALIFORNIA STATE FIRE MARSHALHAZARDOUS LIQUID PIPELINE SAFETY DIVISION

The Hazardous Liquid Pipeline Safety Act of 1979 had vested upon the Federal Governmentjurisdiction over all hazardous liquid pipelines (both interstate and intrastate). However, the CaliforniaState Fire Marshal entered into a certification agreement with the U.S. Department of Transportation(DOT) and was granted jurisdiction over intrastate hazardous liquid or carbon dioxide pipelines which itnow exercises. Also, under the certification, the Hazardous Liquid Pipeline Safety Division of theCalifornia State Fire Marshal acts as an agent for the DOT as it relates to interstate pipelines.

The Division's mission is to ensure the safety of the citizens of California and to protect itsenvironment as it relates to potential hazards created by jurisdictional hazardous liquid or carbon dioxidepipelines. The Division regulates all interstate and intrastate hazardous liquid pipelines in California,including, pipelines emanating from offshore oil and gas platforms that cross state boundaries. TheDivision inspects and evaluates pipeline operator's facilities, written procedures and records forcompliance with Federal (49 CFR Part 195) and state (California Government Code/ Chapter 5.5 Sections51010 through 51019) pipeline safety laws and regulations. All spills, ruptures, fires or similar incidentsare responded to immediately and such accidents are investigated for cause. In addition, hazardous liquidpipelines are periodically tested for integrity using approved Division procedures.


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LOCAL PLANNING AND RESOURCE MANAGEMENT DEPARTMENTS

The County of Santa Barbara Planning and Development Department submitted the summarybelow. Other California counties would expect similar regulatory requirements for the decommissioning ofoil and gas facilities in Federal and State waters.

Virtually all remaining offshore oil and gas development facilities in Southern California haveonshore facility components associated with them. Federal and State environmental review andpermitting laws consider decommissioning and removal activities to be “development” and when thepotential environmental impacts of development are evaluated, these laws require that the “whole of theproject” be considered. Therefore, the County believes that when offshore facilities are proposed fordecommissioning, that the related onshore facilities must be considered as part of the environmentalreview process even if the operator is not immediately planning to abandon the facilities. Anenvironmental analysis that only consider the offshore impacts of an offshore decommissioning projectthat also has onshore facilities does not meet the legal requirements of environmental review andpermitting. (Conversely, the same would hold true for an onshore decommissioning proposal that hasoffshore components that aren’t analyzed).

On most occasions, offshore decommissioning projects also have onshore staging areas that arenecessary to support the offshore activities. When pipelines are proposed to be removed from theshallow subtidal region, the proposed removal will include some onshore pieces of pipeline above themean high tide line. In both cases, local agencies will typically have permits to issue and anyenvironmental analyses must include the impacts from the onshore activities.

Even if there were no legal need to include the onshore impacts from offshore facilitiesdecommissioning efforts, coordination with the County and other local governments ensures that thelevels of review are consistent and that issues important to local governments are addressed. Localcitizens and various businesses, such as tourism and commercial fishing, consider local governmentsresponsible for preventing impacts to their businesses form offshore oil and gas activities, including facilitydecommissioning.

When an operator ultimately decides to decommission and abandon onshore facilities thatsupported offshore oil and gas development, the County has clear permit authority. Virtually any form ofdemolition of existing facilities requires a permit. For those facilities in the “Coastal Zone” of the County,local governments who have approved local coastal programs issue permits for abandonment. Thelocally approved coastal permits for decommissioning activities can, in most cases, be appealed to theCalifornia Coastal Commission for further review. Outside of the Coastal Zone, permits are approvedsolely by a local government and are not appealable to the Coastal Commission. Where an operator hasan existing permit to operate that also includes a condition or other requirement to abandon the facility; theCounty may be able to amend the permit to allow the specific abandonment project. Otherwise, permitsmay range form ministerial permits approved by staff for simple abandonment efforts to more complexdiscretionary permits approved by the Planning Commission and/or Board of Supervisors. In all cases,permits require that adequate environmental review be completed. That can range from simpleexemptions to more complex environmental impact reports.


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LOCAL AIR POLLUTION CONTROL DISTRICTS (APCDs)

The following overview was provided by Santa Barbara County APCD. Similar requirements areexpected for other County’s. Offshore decommissioning plans submitted to the appropriate regulatoryagency (e.g., Minerals Management Service and California State Lands Commission) are reviewed by thelocal APCD for compliance with APCD rules and regulations and the applicant's existing permitrequirements.

Permits or permit modifications are required in Santa Barbara County for decommissioning andabandonment project. Such permits are usually done as a consolidated Authority to Construct/Permit toOperate (ATC/PTO). CEQA review is also performed during the permit processing to assess the permitair quality impacts. Significant issues to be addressed for any decommissioning project during theenvironmental review phase includes the analysis of potential impacts to air quality and feasible measuresthat may be used to reduce and or eliminate any air quality impacts. The primary purpose of definingsignificant issues is to identify, document and plan for the environmental and safety requirements that willneed to be addressed during the pre-abandonment, abandonment, and the post-abandonment phases ofa project.

The criteria used to determine the significance of air quality impacts are based on federal, state,and local air pollution rules and regulations. Air quality impacts are normally determined by estimating thenet change in ambient pollution concentrations caused by the project. Baseline air quality is establishedusing existing data from state and local air monitoring (SLAM) stations and prevention of significantdeterioration (PSD) stations. To evaluate the significance of impacts pursuant to CEQA, emissionincreases from the project are compared to specific emission thresholds that define the significance ofpotential air quality impacts. Major sources of air emissions from decommissioning projects include, butare not limited to, derrick barges, support vessels such as tug boats, crew and supply boats, multiplediesel powered internal combustion equipment, and chemical solvent usage.

Project information and emission calculations are used to determine the permit requirements,applicability and compliance status of the project.

The potentially applicable requirements include:

• The standards promulgated in the State and Federal Implementation Plans (SIP and FIP);• The National and State Ambient Air Quality Standards (AAQS);• New Source Review (NSR) and Prevention of Significant Deterioration (PSD) Rules;• Other requirements of the 1990 Clean Air Act Amendments (CAAA);• OCS Regulations;• Air Quality Attainment Plans (AQAP), and;• Local prohibitory rules.

Large scale projects often result in emissions that exceed established significance thresholds andtherefore require mitigation measures that reduce these emission levels. Emissions associated withdecommissioning activities have been mitigated on previous projects through the use of Best AvailableControl Technology (BACT) and emissions offsets.

Assembly Bill Number 3047 (Olberg Act, 1996) which has been recently enacted prohibits any airdistrict from requiring emission offsets from abandonment activities. It should be noted that this Bill hasyet to be tested. Furthermore, some recent development projects have existing agreements with the localAPCD that offsets the entire project through abandonment. In some areas including Ventura County,there is a community bank of emissions offsets that may be available for decommissioning projects.


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In order to reduce emissions during the abandonment, best available control technology (BACT)and/or reasonably available control technology (RACT) may be applied to emitting equipment to reduce airemissions. Currently, the thresholds for requiring controls are based on project daily emissions.Depending on the type of equipment, different control technologies can be applied. For internalcombustion equipment, the most likely controls would consist of turbo charge units, inter/after cooling,timing retard, different injector types, low sulfur fuel, and reduced operations (equipment shutdown whennot in use).

221

APPENDIX II

Platform Schematic ........................................................................ 223

California Offshore Oil & Gas Facilities .......................................... 224

Onshore Decommissioning Decision Tree ..................................... 228

Offshore Decommissioning Decision Tree ..................................... 229

Appendix II

223

Source: MMS, Pacific OCS Region

CALIFORNIA OFFSHORE OIL AND GAS FACILITIESPLATFORMS LOCATED IN FEDERAL WATERS, PACIFIC OCS REGION

Land Water FirstFacility distance Depth Installation No. Initial ProductionName Operator Lease miles (feet) Date Slots Spud Date Field/Unit X Y Longitude W Latitude NHogan Pacific Operators 0166 3.7 154 09/01/67 66 04/29/68 06-10-68 Carpinteria 1,006,354 805,646 119 32 29.35 34 20 15.63

Houchin Pacific Operators 0166 4.1 163 07/01/68 60 01/30/69 04/28/69 Carpinteria 1,003,115 804,772 119 33 7.62 34 20 5.97

Heritage Exxon 0182 8.2 1075 10/07/89 60 09/03/93 12/18/93 Pescado/Santa Ynez 783,935 818,089 120 16 45.06 34 21 1.41

Hondo Exxon 0188 5.1 842 06/23/76 28 09/15/77 04/02/81 Hondo/Santa Ynez 832,341 830,947 120 7 13.91 34 23 26.63

Harmony Exxon 0190 6.4 1198 06/21/89 60 07/23/93 12/30/93 Hondo/Santa Ynez 817,978 826,364 120 10 3.09 34 22 36.03

Gina Nuevo 0202 3.7 95 12/11/80 15 10/27/81 02/11/82 Hueneme/Pt. Hueneme 1,084,073 723,121 119 16 34.53 34 7 2.99

Gail Chevron 0205 9.9 739 04/05/87 36 06/16/88 08/08/88 Sockeye/Santa Clara 1,046,650 726,990 119 24 0.78 34 7 30.29

Gilda Nuevo 0216 8.8 205 10/08/81 96 10/20/81 12/19/81 Santa Clara/Santa Clara 1,041,733 747,989 119 25 6.83 34 10 56.43

Grace Chevron 0217 10.5 318 07/30/79 48 01/19/80 07/25/80 Santa Clara/Santa Clara 1,026,807 747,437 119 28 4.18 34 10 46.46

Habitat Nuevo 0234 7.8 290 100/8/81 24 01/16/82 12/15/83 Pitas Point/Pitas Point 991,694 787,520 119 35 17.14 34 17 11.82

Henry Nuevo 0240 4.3 173 08/31/79 24 02/08/80 05/15/80 Carpinteria 1,000,596 804,219 119 33 37.43 34 19 59.72

Hillhouse Nuevo 0240 5.5 190 11/26/69 60 05/25/70 07/21/70 Dos Cuadras 987,642 803,937 119 36 11.69 34 19 52.84

A Nuevo 0241 5.8 188 09/14/68 57 11/19/68 03/03/69 Dos Cuadras 984,865 804,224 119 36 44.89 34 19 54.79

B Nuevo 0241 5.7 190 11/08/68 63 06/23/69 07/19/69 Dos Cuadras 982,134 804,478 119 37 17.53 34 19 56.43

C Nuevo 0241 5.7 192 02/28/77 60 07/09/77 08/01/77 Dos Cuadras 979,355 804,781 119 37 50.76 34 19 58.53

Edith Nuevo 0296 8.5 161 01/12/83 72 11/05/83 01/21/84 Beta/Beta 1,424,274 525,198 118 8 26.47 33 35 44.83

Ellen CalResources 0300 8.6 265 01/15/80 80 08/09/80 01/13/81 Beta/Beta 1,427,981 520,247 118 7 41.60 33 34 56.52

Elly CalResources 0300 8.6 255 03/12/80 n/a n/a n/a Beta/Beta 1,428,333 520,618 118 7 37.52 33 35 0.25

Eureka CalResources 0301 9.0 700 07/08/84 60 12/29/84 03/17/85 Beta/Beta 1,431,431 513,421 118 6 59.38 33 33 49.61

Harvest Chevron 0315 6.7 675 06/12/85 50 11/12/86 06/03/91 Pt. Arguello/Pt. Arguello 664,622 866,189 120 40 50.94 34 28 8.89

Hermosa Chevron 0316 6.8 603 10/05/85 48 01/30/87 06/09/91 Pt. Arguello/Pt. Arguello 674,783 860,793 120 38 47.00 34 27 19.83

Irene* Torch 0441 4.7 242 08/07/85 72 04/25/86 04/13/87 Pt. Pedernales/Pt. Ped. 708,195 3,831,989 120 43 45.94 34 36 37.51

Hidalgo* Chevron 0450 5.9 430 07/02/86 56 11/27/87 05/27/91 Pt. Arguello/Pt. Arguello 710,975 3,819,245 120 42 8.24 34 29 42.05

*Irene and Hildago are in UTM 10 (meters).All others are Lambert Zone 6 (feet).Source: MMS, Pacific OCS Region

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CALIFORNIA OFFSHORE OIL AND GAS FACILITIESSTATE WATERS OFFSHORE FACILITIES

Distance Water Lamber Coordinate FirstLocation on from Land Installation Depth (feet) Initial Production No. Present

Facility Name Operator State Lease # (Nautical Miles) Date (feet) Zone X Y Spud Date Slots Status

Platform Emmy Aera Energy PRC 425 1.2 1963 47 6 1,454,245E 548,870N Mar-63 Apr-63 53 Producing

Platform Eva Torch Operating PRC3033 1.8 1964 57 6 1,448,916E 548,783N Mar-64 Jan-66 39 Producing

Platform Esther Torch Operating PRC 3095 1.2 1985 35 6 1,433,450E 569,790N n/a Jul-95 64 Producing

Platform Holly Venoco PRC 3242 1.8 1966 211 5 897,722E 828,627N Jul-65 Apr-66 30 Producing

Belmont Island Exxon PRC 186 1.3 1954 42 6 1,429,978E 570,927N May-54 May-54 70 Process of BeingDecommissioned

Rincon Island Rincon Island PRC 1466 0.5 1958 45 6 1,035,710E 808,299N Feb-60 Mar-60 68 ProducingLimited Partnership

Source: California State Lands Commission

Appendix II

225


226


Appendix II

227


ONSHORE OIL & GASFACILITY

DECOMMISSIONING

OIL & GASPROCESSINGEQUIPMENT &

PIPING

PIPELINES

SOIL

REFURBISHED &REUSED

SOLD FOR SCRAP

WASTE TO LANDFILL

LEAVE IN PLACE

REMOVE

ENVIRONMENTALSITE ASSESSMENT

NO REMEDIATION

SOIL &/ORGROUNDWATER

REMEDIATION

Site Restoration

Revegetation

Onshore Oil & Gas FacilityDecommissioning Decision Tree

Source: Dr. Robert Byrd, Twachtman, Snyder & Byrd, Inc.

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OFFSHORE OIL & GASFACILITY

DECOMMISSIONING

OIL & GASPROCESSING

EQUIPMENT & PIPING

DECK & JACKETSTRUCTURE

SENT TO SHORE

ONSHORE SCRAPING

MOVED TO NEWLOCATION &

REINSTALLED

DISPOSED OF INDEEP WATER

CONVERT TO ANARTIFICIAL REEF

REFURBISHED& REUSED

SOLD FOR SCRAP

WASTE TO LANDFILL

RECYCLE STEEL

WASTE TO LANDFILL

PARTIAL REMOVAL

TOPPLE IN PLACE

SINGLE PIECEPLACEMENT

OFF-SITE

MULTI-PIECEPLACEMENT

OFF-SITE

229

Appendix II

Offshore Oil & Gas FacilityDecommissioning

Decision TreeSource: Dr. Robert Byrd, Twachtman, Snyder & Byrd, Inc.

231

APPENDIX III

Glossary ......................................................................................... 233

Abbreviations.................................................................................. 244

Appendix III: Glossary

233

GLOSSARY OF TERMS

AbandonmentA term generally used synonymouslywith decommissioning.

AnchorA heavy hooked instrument which,when lowered to the seabed, holds avessel in place by its connectingcable.

Anchor BuoyA barrel shaped buoy through whichthe anchor pendant wire passes. Thebuoy holds the eye free end of theanchor pendant wire above the watersurface. The pendant wire is used bythe anchor handling tug to set andretrieve anchors.

Anchor Handling Tug (Resource)A tug equipped with a winch to lift aderrick barge's anchors. It is alsoused as the derrick barge's tow tug.

Anchor PileA section (20 - 50 ft.) of largediameter (30 - 48 in.) pipe, with ananchor chain attached to it, drivenbelow the seabed to a predetermineddepth, usually 20 feet or more.Anchor piles are used to moor drillingrig tenders, other vessels or terminalmooring buoys. Anchor piles arenormally installed in a pattern orsystem consisting of 6 to 8 anchorpiles.

AnnulusThe space between the inside face ofan outer casing string and the outsideface of the next smaller casing string.

Arc GougingThe use of an electrical arc andcompressed air to cut steel.

Artificial ReefA disused structure emplaced in adesignated area either in situ or otherdesignated site. Intended as an enhancedmarine habitat for animals and plants.

Assimilation efficiencyThe percentage of energy ingested(swallowed) by an animal that is absorbedacross the gut wall.

Assistant Derrick Barge Standby (Task)The standby or idle period between theassist derrick barge's arrival at the platformlocation and the commencement of it'swork.

Barge Damage Deductible (Resource)The deductible for a typical cargo barge hullinsurance policy.

Bell GuidesSee "Conductor Guides".

BenthicLiving on (or in) the bottom of the oceanand intertidal areas.

BiomassThe weight of living material, often includingthe dead parts of living organisms (e.g., theshell of a snail). Measured as the amountof living material per unit area or volume.Also known as Standing Crop.

Blasting CapSee "Detonator".

Blasting MachineA mechanical or battery operated deviceused to electronically ignite a detonator.

Bottom Clean Up (Task)The removal of debris by divers from thesea floor.


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Bottom Time (B.T.)The amount of time during a dive thatis spent working on bottom.

Brent SparA cylindrical oil storage and loadingbuoy operated by Shell UKExploration and Production on behalfof Shall and Esso.

Bring In Cargo Barge (Task)The process of maneuvering andsecuring the cargo barge along sidethe derrick barge.

BuoyA float of any type used as a marker.

CaissonA large diameter pipe driven into theseafloor through which well casingsrun. The purpose of the caisson is toprotect and support the well casings.The caisson may have a small deck.

Cargo Barge (Resource)A flat deck barge used to transportplatform components, equipmentmodules and other cargo.

Carrying CapacityThe theoretical maximum number ofindividuals in a population that can besupported indefinitely by a givenenvironment.

CasingSteel pipe placed in an oil or gas wellas drilling progresses to prevent thewall of the hole from caving in duringdrilling and to provide a means ofextracting petroleum if the well isproductive.

Casing StringPipe inside an oil or gas wellconductor installed during the drillingoperations often cemented to theconductor.

Closure PlatesPlates welded into the tops of piles or jacketlegs to seal them so that water can beevacuated using compressed air.

Coil TubingRig like unit with continuous length of pipeon a big coil.

CommunicationThe movement of a substance(hydrocarbons, water, cement) from oneposition to another.

Concrete Gravity Base StructureA concrete substructure which is not fixedinto the seabed by piles but resists windand wave force by its own bulk and weight.

Conductor or Drive PipeA large diameter pipe driven into theseafloor to protect the surface casing and toprotect against a shallow gas blowout.

Conductor GuidesGuides built into the jacket and deck, duringfabrication, used to install the conductors intheir correct location.

Consumable Items (Resource)Items used in the course of a typical project,the cost of which is not covered by thecontract or the schedule of rates.

Continental ShelfThe seabed and subsoil beyond theterritorial water over which a country hassovereign rights for the purpose of exploringfor and exploiting natural resources.

Crew Boat (Resource)A small fast boat used to transportpersonnel and supplies to and from the jobsite to shore.

Critical PathThe sequence of events that determine theduration of a project.


235

Cut Deck Legs, Equipment andMiscellaneous (Task)The cutting of all equipment,miscellaneous piping and the deck legto pile splices to allow lifting theequipment from the deck and thedeck from the jacket.

Cut JacketThe cutting of all braces necessary toremove the jacket in two or moresections. If a jacket is so large that itsweight will exceed the capacity of thederrick barge, or if it is not structurallysound, it may have to be cut andremoved in pieces. If this is required,the members to be cut above thesurface would be cut by welders in theconventional manner and thosemembers below water would be cutby divers using the Oxy-arc method.

Deballast Piles (Task)The displacement of water inside thepiles with compressed air to reducethe on-bottom weight of the jacket bycausing it to be more buoyant.

DeckThe platform superstructure whichsupports drilling, wellhead, and/orproduction equipment.

DecommissioningThe process of deciding how best toshut down operations at the end of afield's life, then closing the wells,cleaning, making the installation safe,removing some or all of the facilitiesand disposing or reusing them.

Decommission Pipeline (Task)The process of flushing a pipelinewith water to purge it ofhydrocarbons. After the pipeline isflushed, a pig is run using water andthe pipeline is left filled with water.

Decommission Platform (Task)A two phase operation, performed prior tothe arrival of the derrick barge spread, toprepare the platform for salvage. The firstphase is to make the environment safe forburning and welding. The second phase isto do any work which does not require, orwill facilitate, the derrick barge operation.

Deep Water DisposalOffshore disposal of a structure byemplacement at licensed, designated deepwater sites.

Demobilize Assist Derrick Barge (Task)The movement of the assist derrick bargefrom the platform location to it's point oforigin.

Demobilize Cargo Barges (Task)The movement of a cargo barge and it's towtug from the platform location to thedisposal contractor's yard.

Demobilize Derrick Barge (Task)The movement of the derrick barge fromthe platform location to it's point of origin.

Depth PayPremium paid to divers that dive below 50feet, increasing at each 50 foot interval.Depth pay is paid once in 24 hours for thedivers deepest dive.

Derrick Barge (Resource)A barge (floating construction plant/camp)equipped with a revolving crane, a mooringsystem and crew quarters.

DetonationThe setting off of an explosive charge.

DetonatorA device or small quantity of explosivesused for detonating high explosives.

Disposal ContractorContractor that will dispose of the platformcomponents (scrap dealer).


236

Diving Services (Resource)Services of a diving contractor usedduring a salvage or constructionproject.

DolphinsA cluster of piling at the entrance to,or alongside, a dock or wharf forservice as a fender, alongside ofwhich boats may be moored.

Drive Pipe or ConductorA large diameter pipe driven into theseafloor to protect the surface casingand to protect against a shallow gasblowout.

DumpingA term sometimes used for offshoredisposal.

E&P ForumThe Oil Industry InternationalExploration and Production Forum, aglobal association of the oil andnatural gas exploration andproduction industry.

Electric Line UnitA piece of equipment that allows workto be performed in an oil or gas well.

EmplacementRegulated lowering of a platform in adesignated disposal area, principally adesignated artificial reef area.

EpifaunaThe animals that live on the uppersurface layers of ocean floorsediments. (Epiphytes are microalgalorganisms that live on a surface.)

Explosive Charges (Resource)High explosives and their sizedcontainers used to sever conductorsand piles.

Explosive MagazineA portable container used to transportexplosive charges and equipment from theexplosive contractors facility to the job site.

Fabricate Deck Padeyes (Task)Replacement deck lifting padeyes arefabricated for decks cut into sections andfor decks whose padeyes are no longersafe for the lift. These padeyes arefabricated at the decommissioningcontractors facility. The contractor wouldinstall these padeyes during itsdecommissioning.

Fabricate Explosive Charges (Task)The assembly of high explosives in properlysized containers. The explosive chargescontainer are sized to fit the internaldiameter of either the pile or conductorpipe. The quantity of explosive material isdetermined based on the size and type ofmaterial to be severed (steel, cement, etc.).This work is performed at the explosivecontractor's facility then packages forshipment.

Fish Attraction Device (FAD)A manufactured object placed in oceansurface waters around which fish tend toaggregate.

Flame CuttingThe cutting of steel using a controlled flameand oxygen

Flame WashingThe use of a controlled flame and oxygen toremove metal.

Flared ConductorSee "Flared Pile".

Flared PileThe outward spreading (mushrooming) ofthe metal above the area where the pile isexplosive severed.


237

Gang WayA portable access walkway used tospan the gap between the platformand the derrick barge.

Gas FreeFree of explosive or poisonous gas.A safe working area.

GroutCement slurry used betweenconcentric structural members. Groutwas used to secure one member toanother.

Grouted PileThe annular region between the pileoutside wall and the inside wall of ajacket leg or sleeve is filled with grout.The grout may be several feet deepor fill the length of the jacket leg.

Grout PlugA plug of cement/water mix placed ina pile extending above and below themudline to strengthen the platform,sometimes with reinforcing bar cages.

Hand JetHigh pressure water nozzle used bydivers to move soil on the seabed.

HelideckA pad to land helicopters on anoffshore vessel or platform.

InfaunaThe animals that live in the softsediment layers of the ocean floor.

In-Water Decompression (IWD)The time a diver must spend in thewater decompressing at specificdepths enroute to the surface.

In-situIn the original position, on site.

Injection RateThe rate fluids can be injected into theproduction formation and the pressurerequired to inject the fluids; example 10barrels per minute at a pressure of 4200pounds per square inch.

Inspector (Resource)A representative of the oil companyrequired to be present during all phases ofthe platform removal when work is beingperformed. His function is to observe thework and maintain a daily log of activities, toverify that the work is performed inaccordance with the specifications and toverify extra contractual work.

InstallationA generic term for an offshore platform ordrilling rig (but excluding pipelines).

Install Closure Plates (Task)Placing and welding prefabricated steelplates in the tops of piles or jacket legs sothat the water inside can be evacuated bycompressed air.

International Maritime OrganizationThe United Nations body charged withshipping safety and navigation issues.

JacketThe portion of a platform extending from theseabed to the surface used as a templatefor pile driving and as a lateral bracing forthe pile.

Jet/AirliftA device used to remove the pile mud plug.High pressure water breaks up the mudplug and expanding air lifts the particles tothe surface.

Jet/Airlift Mud Plugs (Task)The removal of the soil from inside the pilesusing a jet/airlift system.

Lifting BlockA block, containing one or more sheaves,connected to the crane boom by wire rope,that is used to lift and lower loads.


238

Lifting CapacityThe weight a crane can lift at a givenboom radius or angle.

Lifting EyesSee "Padeyes".

Load SpreaderA pad of wood, steel, etc. Normallyplaced on a cargo barge to distributea concentrated load over a largerarea.

London ConventionAn international treaty signed by morethan 70 nations governing disposal ofsubstances at sea.

MagnetometerAn electrical device towed by a boatover a location to locate metalobjects, i.e. pipelines, wellheads,wrecks, and similar ferrous objects.

Marine GrowthSea life (e.g. barnacles) attached tohard objects submerged in the sea.

MembersThe structural pieces or componentsthat make up a jacket or deckstructure.

Mobilize Assist Derrick Barge(Task)The movement of the assist derrickand it's tow/anchor handling tug boatfrom its point of origin to the platformlocation.

Mobilize Cargo Barge (Task)The movement of a cargo barge andit's tug boat from their point or originto the platform location.

Mobilize Derrick Barge (Task)The movement of a derrick barge andit's tow/anchor handling tug boat fromits point or origin to the platformlocation.

MosaicNumber of pictures making up a big picture.

Mud PlugThe soil (mud, clay, sand) inside an openended pile that has been driven into theseabed.

Mudline (M.L.)The elevation of the natural seabed.

North East AtlanticThe sea area to which OSPAR Conventionsapply, This is defined as westwards to theeast coast of Greenland, eastwards to thecontinental North Sea coast, south to theStraits of Gibraltar, and north to the NorthPole. This maritime area does not includethe Baltic or Mediterranean seas.

North SeaThe sea bounded primarily by the coasts ofGreat Britain, Norway, Denmark, Belgium,Germany, Sweden, France and theNetherlands.

Off-Load Cargo Barge (Task)The removal of all sea fastening and theplatform components from the cargo bargeat the disposal contractor's yard.

OffshoreOperations carried out in the ocean asopposed to on land.

OperatorThe company either solely or in a jointventure which manages the operation of oiland gas production for itself or on behalf ofthe partners.

Oslo CommissionSee "Osparcom".

OsparcomThe Oslo and Paris Commission whichregulates pollution from offshore andonshore sources in the North East Atlantic.


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Oxy Acetylene TorchA device using oxygen and acetyleneto cut steel.

Oxy-Arc TorchA device using oxygen and anelectrical arc to cut metal, usuallyunderwater.

PadeyeA plate with a hole cut in it that isattached to a structure which allows ashackle connection for lifting thestructure.

Paris CommissionSee "Osparcom".

PelagicLiving in the water column offshore ofthe coastal zone (i.e.,. seaward of thedownward break in the continentalslope).

Pendant WireThe cable connected to the head ofan anchor used by the anchorhandling tug to raise or lower theanchor. The free end is held at thewater surface by a buoy.

Pick Up Assist Derrick BargeAnchors (Task)The retrieval of the assist derrickbarge's anchors at the end of itsportion of the project.

Pick Up Derrick Barge Anchors(Task)The retrieval of the derrick bargeanchors at the end of the project.

PigA plug, forced through a pipeline byliquid or gas, used to clean the pipe'sinterior or separate different fluidmediums.

PileSteel pipe driven into the seabed to secureand support an offshore structure.

Pile Driving HammerA steam, diesel or hydraulically operatedimpact hammer used to drive piles into theseabed.

PipelineA conduit of steel pipe extending fromplatform to platform or platform to shoreused to transport oil and/or gas.

Pipeline Abandonment (Task)The cutting and plugging of a pipeline thatis to be abandoned in place. Prior to thejacket removal and after the pipelinedecommissioning is completed, the pipelineis cut and abandoned in place using adiving crew. The diving is performed fromthe derrick barge or a dive boat prior to thederrick barge arriving on location.

Pipeline Surveying Services (Resource)The services of a surveying contractor andhis equipment or mark pipelines and othersubmerged objects to avoid interferencewith derrick barge anchor placement.

PlanktonOrganisms living suspended in the watercolumn and incapable of moving againstwater currents.

PlatformA structure secured to the seabed andextending above water for the production ofoil and gas.

Population DynamicsThe variations in time and space in thesizes (number of individuals) and densities(number of individuals per unit area orvolume) of a population.

PopulationA group of individuals of the same speciesin a defined area.


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Primary ProductivityThe rate at which biomass isproduced per unit area by plants.

Processing FacilitiesPart of the topsides that treat oil andgas, remove impurities and pump theproduct into pipelines to shore.

Production CasingA pipe set in the well after it is drilled.The tubing is inside the productioncasing.

Production EfficiencyThe percentage of energy assimilatedby an organism that becomesincorporated into new biomass.

Production FormationThe sub strata in which hydrocarbonsare present. Where the oil and gasenters the tubing to be transported tothe surface.

ProductivityThe rate at which biomass isproduced per unit area by any class oforganisms.

RecruitmentThe addition of individuals of aspecified size or age to a population.In a fisheries context, recruitmentrefers to the addition of individuals tothe size (or age) groups that canlegally be caught. Otherwise,recruitment typically refers to theknown addition of ‘newborns’ (seeYoung of the Year) to a population(also see Settlement).

RecyclingRemoval of an installation or parts ofan installation to shore where they areseparated into different materials andmelted down or reprocessed to bereused.

Remove Conductors(Task)The removal of the conductors from thejacket and placing them on a cargo barge.The conductor guides in the jacket cannotsupport the weight of the conductors,therefore they must be removed prior to theremoval of the jacket.

Remove Deck(Task)The lifting of the deck from the jacket andplacement of it on a cargo barge.

Remove Equipment (Task)The lifting, placing and seafastening on acargo barge, of all equipment removed fromthe deck.

Remove Jacket (Task)The lifting of the jacket from the seafloorand placement of it on a cargo barge fortransport to shore.

Remove Piles from Jacket Legs (Task)The removal of the piles from the jacket toreduce the jacket's lift weight.

RigThe derrick or mast, drawworks, andattendant surface equipment of a drilling orwork over unit.

Rigless AbandonmentP&A without a rig.

Rig Up Cargo Barge (Resource)The installation of protective pads toprepare a cargo barge for receiving thesalvaged platform components.

Rigs to ReefsA national policy in the US enshrined inlegislation, promoting the conversion ofdisused platforms into artificial reefs formarine lift at designated sites.

RiserThe portion of a pipeline that rises form theseabed to the water surface, supported bythe platform jacket.


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Riser BendThe section of the riser that turns thepipeline from horizontal to vertical.

Salvage ContingencyAn allowance of 15% of the estimatedon site derrick barge spread worktime to account for unforeseen factorswhich will increase the time requiredto perform the work. Examples ofitems to be covered by thiscontingency are as follows:1. Conductor flaring

In the process of explosivelysevering the conductors, flaring ofthe cut ends occurs. This flaringwill not allow the conductor topass through the conductor bellguide framing in the jacketresulting in divers having to cutthe flared end. This will requireone hour of bottom time perconductor plus in waterdecompression time asdetermined by the dive tables forthe applicable water depth.

2. Pile flaringAs in the case of conductor flaringdescribed above, flaring of the pileends also occurs. Additional timeis required to trim the pile ends,eliminating the flared obstruction.

Sea BuoyThe first buoy encountered whenapproaching the entrance of a river orport from sea.

SeafastenThe securing by welding of platformcomponents or cargo to the cargobarge for transport at sea.

Set Up Derrick Barge (Task)The placement of the derrick barge'smooring anchors on the seafloor around theplatform location at pre-selected positions.The derrick barge will be positioned alongside the platform using its mooring system.A walkway will be placed between thederrick barge and the platform.

SettlementMany marine organisms that live on thebottom (see Benthic) have earlydevelopmental stages that grow in the watercolumn (see Plankton and Pelagic).Settlement refers to the event when theyoung leave the water column permanentlyto take up life on the bottom. Recruitmenttypically refers to the first observation ofyoung following settlement from the water.

Sever Conductors (Task)Cutting the conductors using highexplosives.

Sever Piles (Task)Cutting the piles using high explosives.

ShackleA "U" shaped device with a removable pinor bolt across the end used to connect asling or cable to a padeye.

Shaped ChargeAn explosive charge designed to focus itsblast onto a very small area, used to cutvery thick materials.

ShimCurved steel plates wedged between andwelded to the jacket leg and pile, used to tiethe jacket and piles together at the top ofthe jacket leg.

ShoeA piece of equipment installed on the end ofthe casing when it is run into the well bore(i.e. that point in which the casing ends).

Side-scan SonarRadar like device used to determine shapesin the water on the sea floor.


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Skirt PileA steel pipe driven into the seafloorthat passes through a sleeve attachedto the jacket. The sleeve and skirtpile extend from the mudline up 50 to100 feet along the jacket leg. Theannular region between the pile andsleeve is filled with grout. Thepurpose of a skirt pile is to secure andsupport offshore structures.

SlicklineA machine with a hydraulicallycontrolled spool of wire used forsetting and retrieving safety valves,lugs, gas lift valves, and runningbottom hole pressures. Slicklines arealso used for a variety of other jobssuch as recovering lost tools andswedging out tubing. Slickline wiregenerally ranges in size from .072inches to .108 inches.

SlingUsually a wire rope of a given lengthwith a loop formed on each end, usedfor lifting loads.

Spatial DistributionThe pattern of placement of items(e.g., individuals) in space.

Spreader BarA pipe or beam arrangement used tospread the slings to keep them fromdamaging the load while lifting.

Spreader FrameSee "Spreader Bar".

Spud BargeA derrick barge moored by droppingpipe or beam spuds into the seabed.

StakeholdersAll the parties having an interest in anissue, including among otherscorporate shareholders, regulators,employees, community groups, thepublic at large.

Stiffleg BargeA derrick barge with a crane that does notrevolve and which may or may not boom upand down.

StopsMetal plates welded to the sides of a pile tohold the pile at a desired elevation in thejacket leg.

Subsea Tie InPoint where a branch pipeline ties into amain pipeline on the seabed.

Survey Location for Pipelines (Task)The locating and buoying of pipelinesaround a platform. A survey boat and creware mobilized to the location to locate andmark, with buoys, all pipelines within a 4000foot radius of the platform to enable thederrick barge(s) to place its anchors safely.

Temporal PatternVariation in some attribute (e.g., number ofindividuals in a population) over time.

Tension Leg Platform (TLP)A floating platform anchored to the sea bedby long steel pipes (tension legs). Thetension legs keep the platform from movingup and down on the waves.

Tonne1000 Kilograms - a common weight unitused in offshore structure design andconstruction; also used as a measure for oil(approx. 1200 liters).

TopplingControlled "tipping over" of the platform(generally but not always without topsides)from it's vertical position to restinghorizontally on the seabed.

TopsidesThe facilities which contain the plant forprocessing oil and bas andaccommodations.


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Tow Tug (Resource)A tug boat used to tow a barge, eithera cargo barge or derrick barge. Itmay also be used as an anchorhandling tug by the derrick barge.

Trophic CouplingA strong linkage among organisms ontwo or more different levels in thefood chain (e.g., herbivores -carnivores).

Tubing StringThe smallest diameter pipesuspended in a well. Thehydrocarbon product flows to thesurface inside the tubing.

Trunk Line, ExplosivesA detonation cord that connects allthe explosive charges so they may bedetonated in a group.

Walk WaySee "Gang Way".

Weather Contingency (Task)An allowance of 6% of the estimatedonsite derrick barge spread work timeto account for lost time due toweather.

WellThe holes drilled through the seabedinto the reservoir where oil or gas istrapped, often two thousand or moremeters below the seabed. The hole islined with piping which extends upthrough conductors onto the platformdeck.

Well HeadThe well head sits on top of the drivepipe. Casing and tubing strings aresuspended from the well head.Valves on the well head allow theentrance to the tubing and the casingannuli.

Wire RopeSteel wire formed into a cable.

Wood PilesWooden (timber) piles driven into theseabed to support equipment offshore.

Young of the Year (YOY)The young of a species that were born inthis year; typically applied to fishes (alsosee Settlement and Recruitment).

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ABBREVIATIONSAPI American Petroleum InstituteBHT bottom hole temperatureBOP blow out preventerCB cargo bargeCEQA California Environment Quality AssessmentCG center of gravityCIBP cast iron bridge plugCIRC. circulateDB derrick bargeDEMOB de-mobilizeDOT Department of TransportationDP dynamic positioningDPV dynamic positioning vesselHAZMAT hazardous materialI. Csg. intermediate casingLAT lowest atmospheric tideLD lay downML mud lineMLW mean low waterMMS Minerals Management ServiceMOB mobilizeMT metric tonNDT nondestructive testingNDE nondestructive examinationNEPA National Environmental Protection AgencyNMFS National Marine Fisheries ServiceNORM naturally occurring radioactive materialNOAA National Oceanic and Atmospheric AdministrationOCS outer continental shelfOD outside diameterP&A plug and abandonmentPERF. perforatePL pipelinePOOH pull out of holePP pumpRD rig downRETR. retrieveROV remote operated vesselSAT saturation divingST short tonSSCV semi-submersible crane vesselTBG tubingUT ultra sonic testingWL wire lineWOC wait on cementWOR work over rigWT weightYOY young-of-year

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APPENDIX IV

Biographical Sketches .................................................................... 247

Appendix IV: Biographical Sketches

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BIOGRAPHICAL INFORMATION ON SPEAKERS, PANEL MEMBERS,CHAIRPERSONS, AND ORGANIZERS

Lee Bafalon : Lee Bafalon is Senior LandRepresentative for Chevron U.S.A. Inc., based atChevron's Ventura offices. He has been withChevron for over 17 years, all of that time workingon behalf of Chevron's offshore Californiaoperations. Lee is responsible for permitting andregulatory affairs for Chevron's Santa BarbaraChannel assets, offshore and onshore. In thatcapacity, he was on the permitting team for theinstallation of the Point Arguello and Gaviotafacilities in the 1980's, the permitting coordinatorfor Chevron's 4H State Platforms Project from1992-1996, and is currently on the permittingteam for Chevron's contemplated OCS FacilitiesDecommissioning Project.

Ann Scarborough Bull : Dr. Ann ScarboroughBull was born and raised in San Diego, California,and has worked as a marine biologist for theMinerals Management Service since 1988. Sheperformed her graduate research at the MarineBiological Laboratory, Woods Hole, and her postdoctoral work at Johns Hopkins in Maryland. Herresearch interests focus on the role of offshoreplatforms in the fisheries of the Gulf of Mexico.

Robert C. Byrd : Dr. Byrd is a Principal inTwachtman, Snyder & Byrd, Inc. (TSB), Houston,Texas, a project management and engineeringfirm which specializes in offshore oil and gasfacility decommissioning. TSB has managed thedecommissioning of over 200 facilities in the Gulfof Mexico and is active in planning thedecommissioning of facilities offshore Californiaand in Europe’s North Sea. Dr. Byrd joined TSBin 1993. Prior to that he was President and Chiefof Operations at IMODCO, Inc., Agoura Hills,California, for a period of seven years. IMODCOspecializes in offshore oil and gas terminals andfloating facilities worldwide. In total Dr. Byrd hasover twenty years experience in a wide range ofpositions involving offshore facilities engineering,construction, and decommissioning. He is also aformer U.S. Coast Guard offices. Dr. Byrdreceived his Ph.D. in Engineering from theUniversity of California, Berkeley, where he was aHans Albert Einstein Fellow in Ocean Engineeringand was a recipient of the National Sea GrantAssociation Award for Applied Research. Heholds a Masters in Ocean Engineering from theUniversity of Alaska, Fairbanks, and a B.S. inMarine Engineering from the United States Coast

Guard Academy at New London, Connecticut.Dr. Byrd is a licensed Professional Engineer.

Peter Cantle : Peter Cantle has been employedwith Santa Barbara County Air Pollution ControlDistrict since September 1988, providingengineering management, analysis andpermitting services. Prior to Air Pollution ControlDistrict, he worked three years with the EnergyDivision (Planning and Development, SantaBarbara County), responsible for permitting andcompliance of major energy projects (ExxonSYU, Chevron Point Arguello, Gaviota MarineTerminal, Celeron Pipeline, etc.) Prior to that, heworked five years with Shell as EnvironmentalSpecialist (Houston, TX). Prior to Shell, heworked two years with Hydril Co., manufacturingand marketing oilfield equipment. Peter earned aBachelor and a Master of Science degree inEcology from Texas A&M University. He is thefather of two sons, and he is an avid enjoyer ofthe ocean and its related sports.

Mark H. Carr : Dr. Mark Carr is an AssistantProfessor in the Department of Biology, at theUniversity of California, Santa Cruz. He is alsoDeputy Program Director for the UC-MMSCoastal Marine Institute and the SouthernCalifornia Educational Initiative. His currentresearch involves experimental studies ofrecruitment and population dynamics of reeffishes in the Bahamas and the ecological role ofoil/gas production facilities in the Santa BarbaraChannel. He received his B.A. at the Universityof California, Santa Cruz, his M.S. from SanFrancisco State University and Moss landingMarine Laboratories, and a Ph.D. from theUniversity of California, Santa Barbara, all ofwhich are in Biology with an emphasis on AquaticBiology.

Marc Chytilo : Marc Chytilo is Chief Counsel ofthe Environmental Defense Center, a publicinterest law firm and advocacy organization withoffices in Santa Barbara and Ventura, California.EDC has been attorneys in numerous air qualitycases involving the oil industry and OuterContinental Shelf activities, including Citizens toPreserve the Ojai v. Petrochem (CEQA:Cumulative air quality impacts), Citizens toPreserve the Ojai v, EPA (federal implementationplant): EDC v. EPA (Clean Air Act § 328


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regulation promulgation); and Get Oil Out v. StateLands Commission (subsea well abandonmentproject). Marc is a member of the Santa BarbaraCounty Air Pollution Control District CommunityAdvisory Council and an active outdoorspersonregularly enjoying the recreational opportunitiesprovided in the Santa Barbara Channel.

Gordon Cota: Gordon Cota is a tenth-generation Santa Barbaran who isowner/operator of the F/V Genoa, a commercialfishing vessel home-ported in Santa Barbara. Hehas fished with tool and line, traps, and trawl netsfor over 25 years in the Southern California Bight.Gordon has served on the Department of Interior,Mineral Management Service’s RegionalTechnical Working Group, and is a former SantaBarbara Harbor Commissioner. He currentlyserves as a representative for the trawl fleet onthe Joint Oil/Fisheries Committee, an ad-hocgroup formed in 1983 to resolve interindustryconcerns. He also serves as the Secretary of theSouthern California Trawlers Association.Gordon has been very active in helping to solveat-sea interindustry problems, including servingas scout, chase, or pilot vessel for oil industryactivities which might impact commercial fishing,and site clearance test-trawling after oil facilityabandonments.

Andrew S. Culwell : Andy Culwell has beenactive in the decommissioning and removal ofoffshore oil and gas facilities for the past 24years. As Vice President, Special Projects forAmerican Pacific Marine, Inc. (his currentaffiliation), he planned and directed the removalof Chevron’s Platforms Hope, Heidi, Hilda, andHazel offshore Carpinteria in 1996. He alsoplanned and directed the removal of Texaco’sHelen and Herman Platforms offshore Gaviota in1988 and supervised the removal of portions ofAminoil’s Ellwood Pier off Goleta in 1979. Mr.Culwell has an extensive background inunderwater construction and demolition, oilplatform and pipeline installation and removal,and the use of remotely operated vehicles andmanned submersibles in deep water constructionapplications, working in the U.S. Gulf of Mexico,the North Sea, South America and the U.S. WestCoast.

Elmer (Bud) P. Danenberger : Mr. Danenbergerearned a B.S. degree in petroleum and naturalgas engineering and a Masters degree inenvironmental pollution control, both fromPennsylvania State University. He has been

employed as an engineer in the Department ofInterior’s offshore oil and gas program since1971. He has served as District Supervisor forthe Minerals Management Service (MMS) fieldoffices in Santa Maria, California, and Hyannis,Massachusetts, as a staff engineer in the Gulf ofMexico regional office, and as chief of theTechnical Advisory Section at headquarters officeof the U.S. Geological Survey. He is currently theChief of MMS’s Engineering and OperationsDivision with responsibilities for safety andpollution-prevention research, engineeringsupport, offshore operating regulations, andinspection programs.

Frank DeMarco : Frank DeMarco, RegisteredCivil Engineer in the State of California, is anAssociate Water Resource Control Engineer forthe Regional Water Quality Control Board,Central Coast Region. He has worked for theRegional Board for over sixteen years. Currently,he is working in the Board’s “Spills, Leaks,Investigation and Cleanup” (SLIC) program andthe “Underground Storage Tank” program.Projects Frank has worked on that might be ofinterest to those attending this workshop include:Unocal-Avila Beach, tank farm near the City ofSan Luis Obispo, pipelines, sumps/abandonment;Chevron-Estero Bay and Carpinteria marineterminals/facilities, Texaco-Estero Bay tank farmabandonment, San Ardo brine disposal; Shell-Hercules Gas Plant near Gaviota.

Leray A. deWit : Leray A. deWit is anindependent environmental consultant,specializing in resource assessment andpermitting for coastal and offshore developments.He has over 23 years of experience inenvironmental consulting, including managementof multidisciplinary environmental documents forfederal, state, and local agencies, marine andcoastal surveys, permitting of port, harbor,marina, and oil and gas developments, andassessment of impacts of proposed projects onbiological resources. In addition to hisexperience throughout California, Mr. de Wit hasworked on several international projects includingenvironmental analysis for proposed or existingmarine and coastal developments in Iran, Qatar,Abu Dhabi, Cameroon, Curacao, Peru, theBahamas, United Kingdom, Russia and Thailand.Mr. de Wit has developed and managed largefield surveys and is an accomplished diver,having logged over 1,300 dives, including a one-week saturation dive in the Hydrolab UnderwaterHabitat as part of a study on the effects of oil on


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coral reef communities. He has completed pre-and post-construction and abandonment marinebiological surveys for oil and gas facilitiesthroughout the Santa Barbara Channel.

Robert B. Ditton : Dr. Ditton received his B.S.from the State University of New York College atCortland and his Masters and Ph.D. from theUniversity of Illinois. He is a member of thefaculty of the Department of Wildlife andFisheries Sciences where he teaches graduatelevel courses in coastal zone management andthe human dimensions of wildlife and fisheries.He is the only social scientist in this Departmentcurrently. Most of his current research focuseson the human dimensions aspects of recreationalfisheries (fresh and saltwater). Ditton has writtenextensively on the need for integratedapproaches to natural resources management.He served as a Senior Research Scientist on anIPA assignment with the Minerals ManagementService, Gulf of Mexico Region, from 1981-83.Also, Ditton served as a member of the NationalResearch Council Committee on the Dispositionof Offshore Platforms in 1984-85. Later, heserved as a member of the board of experts thatdeveloped the National Artificial Reef Planpursuant to the National Fisheries EnhancementAct in 1985. He is currently completing thesecond year of a multi-year research project forthe Texas Parks and Wildlife Department onbetter understanding stakeholder groups thatcurrently use offshore reef systems in Texasincluding oil and gas platforms.

Tom Dunaway : Tom Dunaway works for theMinerals Management Service, a small Federalagency in the Department of the Interior. He isthe Regional Supervisor for Development,Operations, and Safety for the Pacific OCSRegion located in Camarillo, California. His officeis responsible for all oil and gas operations inFederal waters off the west coast. He has heldthis position for the last fifteen years and startedhis government service twenty-seven years agowith the U.S. Geological Survey’s ConservationDivision the precursor of MMS. He graduatedwith a bachelor’s degree in Chemical Engineeringfrom the University of Kansas. Also, hegraduated from the Tuck Executive Program,Dartmouth College. He successfully completedthe Career Development Program to enter theSenior Executive Service of the Federalgovernment. He has been awarded the Superiorand Meritorious Service Honor Awards of theDepartment of the Interior.

Steve Fields : Steve Fields is an OperationsEngineer in the Ventura Office for the State ofCalifornia, Department of Conservation’s Divisionof Oil, Gas, and Geothermal Resources(Division). He started with the Division in 1981 inthe Santa Maria Office. While in Santa Maria, hewas involved in the plugging and abandonmentoperations for the wells on Platform Helen andthe subsea completions associated with PlatformHermit. In 1985, he transferred to the LongBeach office where he spent three years as anEnhanced Recovery Engineer. In 1988, hetransferred to his current position in Ventura.While in Ventura, he has been the Lead engineerfor the 4-H well abandonment, the wellabandonment on the Rincon Piers, and for threeof the subsea well abandonment.

Daniel Frumkes : Daniel Frumkes is a graduateof UCLA in Zoology in 1963. He was assistant tothe Director of the UCLA Health SciencesComputing Facility through 1978, first in theUCLA Department of Biomathematics and laterin directing the Brentwood Hospital StatisticalResearch Laboratory. He interfaced with a widerange of scientific research which provided thefoundation for the development of newtechniques for computer assisted data analysis.Dan was a commercial hook and line fishermanfrom 1959 through 1970. He began his career inmarine conservation as a volunteer in 1983, firstby evaluating the selectivity of near-shore gillnetsand later by reviewing existing techniques forcollecting and analyzing fisheries data. Dandescribes his initial involvement with marineconservation as less volunteerism and morefalling into the void between marine scientistswho have valuable knowledge, and policymakers, who have little access to the bestavailable information. Dan continues to functionas an interface between scientists and both policymakers and the public. He is the Chairman of theHabitat Research and Enhancement Committeefor United Anglers of Southern California, and isthe Director of the Conservation Network for theAmerican Sportfishing Association. The objectiveof both positions is to help develop synergisticsolutions for fisheries enhancement througheducation.

Craig Fusaro : Dr. Craig Fusaro received hisDoctorate in Biological Sciences from theUniversity of California, Santa Barbara, in 1977,working on the population dynamics of intertidalcrustaceans. From 1976 to 1983, he was anassociate research biologist and co-principal


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investigator with Ecomar, Inc., involved in avariety of applied research projects ranging frommussel mariculture to ocean outfall studies to thefate and effects of offshore oil drilling fluids in themarine environment. In 1983, he became thedirector of the Joint Oil/Fisheries Liaison Office,an inter-industry effort to improvecommunications and resolve conflicts betweenthe two offshore industries in the Santa BarbaraChannel and Santa Maria Basin. Working withthe Mediation Institute, he continues that effortpresently. Concurrent since 1981, he has alsotaught courses in Animal Diversity, Kelp Ecology,Environmental Biology and Environmental FieldStudies at Santa Barbara City College. He alsovolunteers as the Central Coast Board Memberfor California Trout, a statewide trout and streamhabitat conservation organization, and is workingto restore anadromous steelhead to the SantaYnez River.

W. S. (Bill) Griffin : Bill Griffin is Director ofSpecial Projects for Worldwide Drilling andProduction at Phillips Petroleum Company. Hebegan his work for Phillips in 1961, after receivinga B.S. degree in Petroleum Engineering from theUniversity of Oklahoma. His first assignmentinvolving the decommissioning of offshoreinstallations was in 1972. Bill was asked todetermine the future financial liability involved inthe removal of all offshore structures, on aworldwide basis, in which Phillips had an interest.He has subsequently held the position of ProjectManager or Advisor on every decommissioningstudy carried out by Phillips. He has served onnumerous industry committees related todecommissioning and has consulted with hostgovernments. From 1987 until 1989 he was theindustry Advisor for the U.S. Delegation duringthe IMO Guideline negotiations. Bill is currentlyworking in London as the InternationalRegulations Consultant for the industry’s OffshoreDecommissioning Communications Project.

Carolita Kallaur : Carolita Kallaur was named asthe Associate Director for Offshore MineralsManagement, Minerals Management Service, inJanuary 1997. She is responsible for all phasesof the Outer Continental Shelf (OCS) mineralresource management – from the initial offeringof OCS lands for lease through the regulation ofmineral development and lease abandonmentactivities. Ms. Kallaur had served as ActingDeputy Director from August 1994 untilNovember 1995, when she became the DeputyDirector. In that capacity, she assisted the

Director of MMS in running the day-to-dayoperations of the Agency. Ms. Kallaur alsoserved as the Chief Financial Officer for theBureau and served as Chair of its InformationResources Management Council. Ms. Kallaurhas been with the Interior Department since1968, when she began her federal career. Shejoined MMS in 1982. Ms. Kallaur has beenhonored with the U.S. Department of the Interior’sMeritorious Service Award in 1985, theDistinguished Service Award in 1987, and thePresidential Meritorious Rank Award in 1987 and1992. In 1995, she received the PresidentialDistinguished Rank Award – the highest awardbestowed a Senior Executive Service employee –for her exceptional contributions and leadershiproles in the OCS oil, gas, mineral andinternational programs. Ms. Kallaur has a B.Aand an M.A. in economics from the University ofConnecticut.

Linda Krop : Linda Krop is a Senior StaffAttorney with the Environmental Defense Center(EDC), non-profit public interest environmentallaw firm that represents community organizationsin a wide variety of issues affecting our naturalresources, air and water. Linda Krop currentlyrepresents the Environmental Coalition of SantaBarbara (comprised of the Sierra Club, League ofWomen Voters of Santa Barbara, and theCitizens Planning Association) and othercommunity groups in matters relating to offshoreoil and gas development. On of the issues theEDC is working on is the abandonment offacilities, both onshore and offshore. The EDC’sclients (environmental groups and commercialfishing organizations) strongly prefer thecomplete removal of all facilities and a restorationof affected areas to pre-development naturalconditions. EDC’s clients also seek strictenforcement of approved abandonment plansand permit conditions.

James Lima : Dr. James Lima, formerly anAssistant Professor of Social Science at TroyState University, Alabama and adjunct professorat Dauphin Island Sea Lab, Alabama, is now asociologist for the Minerals Management Service,Environmental Studies Section in Camarillo,California. Dr. Lima received his Ph.D. in PoliticalScience in 1994 from the University of California,Santa Barbara. His area of expertise is in socialand economic impacts of offshore energydevelopment, coastal zone management,submerged cultural resources, environmentaladministration and policy analysis.


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Milton Love : Dr. Milton Love is an AssociateResearch Biologist at the Marine ScienceInstitute, University of California, Santa Barbara.For the past 25 years, his research interests havecentered on Pacific Coast marine fishes ofrecreational and commercial importance.Currently, he is conducting research on the fishcommunities living around the oil platforms of theSanta Barbara Channel.

Frank Manago : Frank Manago is anEnvironmental Scientist with the MineralsManagement Service (MMS), Pacific OuterContinental Shelf (OCS) Region in Camarillo,California. He joined MMS in 1984. In hispresent position, he is responsible for thedevelopment, procurement and contractmanagement of environmental studies on theOCS in the areas of benthic, algal and fishecology. He was one of the workshopcoordinators for the 1994 MMS/CA State LandsCommission (SLC) workshop, Abandonment andRemoval of Offshore Oil and Gas Facilities:Education and Information Transfer. Previously,Mr. Manago worked as an ecologist for the U.S.Army Corps of Engineers in Los Angeles, CA andwas responsible for environmental planning andsite assessment of military and civil workprojects. Mr. Manago received his B.S. in Biologyand Chemistry from North Carolina CentralUniversity and M.S. in Environmental Sciencefrom North Carolina State University.

Jack McCarthy : Jack McCarthy is currentlyemployed as a geophysicist in the Pacific Regionoffice of the Minerals Management Service. Hehas been involved with evaluating offshoreleasing, drilling and development sites on theAtlantic, Gulf and Pacific OCS, using engineeringgeophysics and marine geotechnical methods, formore than twenty years. Site clearanceoperations depend on some of the sameevaluation techniques. Given the anticipatedincrease in decommissioning activities in the nearterm off California, Jack’s background in marinegeology and oceanography and his experience ingeoengineering survey technique, habitatmapping and commercial fishing makes him alogical candidate for assuming the functional roleof MMS’s “Marine Garbologist” for the SantaBarbara Channel.

Mike McCorkle : Mike McCorkle has been a full-time commercial fisherman for 41 years, withexperience in all types of commercial fishing. Hehas 23 years of experience trawling around oil

rigs, and extensive experience talking about thepros-cons of rig removal from trawlers’ point ofview.

Merit McCrea : Merit McCrea has worked withinthe maritime industry in the area of CommercialPassenger Fishing Vessels, (CPFV), since 1974.For the last 12 years he has owned and operateda CPFV from Santa Barbara harborpredominantly in the area of the Santa BarbaraChannel and Channel Islands. He has personalexperience in this region for 22 consecutiveyears. He also has some limited experience inboth gill net and hook and line commercialfishing. In addition to fishing operations he hasworked with Dr. Milton Love of UCSB in the areaof data and specimen acquisition on severalprojects including Life History Aspects of 19Rockfish Species (Scorpaenidae:Sebastes) fromthe Southern California Bight. He is currently anactive board member of the Sport FishingAssociation of California. He owns and operatesthe Vessel SEAHAWK LXV from Sea Landing inthe Santa Barbara Harbor.

Paul B. Mount II: Mr. Mount is Chief of theMineral Resources Management Division of theCalifornia State Lands Commission. Mr. Mountgraduated from Ohio State University, inChemical Engineering with a major in PetroleumEngineering in 1973. After his graduation, hebegan his career with Unocal working in SantaMaria and Coalinga, California. In 1978, he wastransferred to the Unocal’s Research andTechnology Center and responsible for researchin enhanced oil recovery. He was one of theleading experts in the world on using single welltracer tests to determine residual oil saturation inoil and gas reservoirs. In 1981, Mr. Mountworked for Aminoil in Huntington Beach,California. He was promoted to EngineeringManager in 1982 and continued with Aminoil until1987 in that capacity. In 1987, he took a positionas a Reservoir Engineer with the State LandsCommission, and was promoted to Chief ofResearch and Development in 1988. He waspromoted to Chief Reservoir Engineer in 1989,Assistant Chief of the Mineral ResourcesManagement Division in 1990 and became Chiefof the Division in 1991. He organizes and directsthe Commission’s Mineral ResourcesManagement Program, including all oil, gas andgeothermal and mineral resources on StateLands in the State of California. Mr. Mount is alicensed Professional Petroleum Engineer and isa member of the Society of Petroleum Engineers.


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Mr. Mount recently retired as a Colonel in theU.S. Army Reserves.

Dave Parker: Dave Parker is a Senior Biologistwith the California Department of Fish andGame’s Marine Resources Division in LongBeach. He currently supervises the Department’sArtificial Reef Program and has been involvedwith southern California nearshore invertebrateand sportfish issues with the Department for over20 years.

John Patton: John Patton is Director of SantaBarbara County, California’s Planning andDevelopment Department. Prior to becomingDirector, Mr. Patton was in charge of the County’sEnergy Division. The Energy Division isresponsible for County permitting necessary forthe $6 billion development of offshore oil and gasin the Santa Barbara Channel and Santa MariaBasin. Mr. Patton received the U.S. Departmentof Commerce National Oceanic and AtmosphericAdministration’s first annual Award for excellencein Coastal, Estuarine and Marine Management forP&D’s role in developing mitigation measures thatmake the Exxon Santa Ynez project a model ofenvironmentally-sensitive offshore oildevelopment. Mr. Patton holds a Bachelorsdegree from Tufts University and a Master ofRegional Planning degree from the University ofNorth Carolina.

Luis Perez : Luis F. Perez is an energy specialistwith the Energy Division of the Planning andDevelopment Department for Santa BarbaraCounty where he has worked for the past 6 years.During that time, Luis has been a planer orproject manager for decommissioning projectsincluding Calresources/SWEPI Molino Gas Plant,the Texaco Gaviota Gas Plant, the ExxonOffshore Storage and Treatment (OS & T) Facilityand the Guadalupe oil spill cleanup. Prior to hiswork with the Energy Division, Luis had worked inthe Caño Limon - Rio Zulia Pipeline in Columbia,South America for 3 years in sub-contractmanagement, emergency response andrevegetation. Luis holds B.A. and B.S. degrees inenvironmental science and public relations fromNorthern Arizona University.

Simon Poulter : Simon A. Poulter is a principal ofPadre Associates, Inc., a Ventura Californiabased environmental and engineering consultantfirm. Mr. Poulter has 14 years of experience as aproject manager and environmental scientistresponsible for physical, biological, and cultural

resource assessments for inland, coastal, andouter continental shelf projects. This experiencehas included numerous environmental impactreports (EIA/EIR/EIS), resource assessmentstudies, oil spill contingency plans, and regulatorypermitting and compliance programs for projectswithin the United States, as well as the RussianFederation and South America. Mr. Poulter hasbeen the project manager for the permitting andenvironmental review for a number of recent oiland gas facility abandonment programs inCalifornia. These decommissioning projectshave included: Chevron’s four State Watersplatforms located offshore of Carpinteria; 23subsea wells and associated flowlines in theSanta Barbara Channel; Unocal’s Ventura tankerberth; Mobil’s Seacliff Pier complex and Exxon’sBelmont Island. Mr. Poulter holds a Mastersdegree in Environmental Planning from theUniversity of Pennsylvania and a B/A/ inMarine/Aquatic Biology and Physical Geographyfrom Wittenburg University.

Peter H. Prasthofer: Dr. Pete Prasthoferreceived a B.S. and M.S. degrees in EngineeringMechanics from the Georgia Institute ofTechnology and a Ph.D. in MechanicalEngineering from the University of California atDavis. Currently he is seconded by ExxonProduction Research Company to be TechnicalManager of the Offshore DecommissioningCommunications Project (PDCP), funded bysome 70 companies in the Oil IndustryInternational Exploration and Production Forum(E&P Forum), the UK Offshore OperatorsAssociation and the Norwegian OperatorsAssociation OLF. Pete Prasthofer has over 23years experience in the oil and gas industry invarious research, technical and operationalassignments. He has had significant involvementin the area of offshore decommissioning for thelast 12 years, focusing on technical, regulatory,and public policy and risk management issues innational, regional and international arenas. Hehas worked full time on this issue since early fall1995. He served as chair of the E&P Forum’sEngineering Committee from 1985-1997.

J. Lisle Reed : Dr. J. Lisle Reed was born andrear in Missouri. He attended the University ofMissouri at Rolla (Missouri School of Mines),where he received his Bachelors, Masters ofScience, and Doctorate degrees in ChemicalEngineering. Following graduation, Dr. Reedworked for five years in the oil and petrochemicalindustry. Dr. Reed entered Federal Government


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service in 1970, and during the 70’s, he served inseveral management posts, including Director ofOil and Gas for both the Federal EnergyAdministration and the Department of Energy.After the oil crisis of 1979, Dr. Reed returned tothe private sector, where he was involved insynthetic fuels projects. In 1983, Dr. Reed wasasked to join the Department of the Interior,where he served as Deputy Under-Secretary andScience Advisor to the Secretary. Since 1988, hehas served as the Director of the Pacific OuterContinental Shelf Region of the MineralsManagement Service. His office is in Camarillo,California. Additionally, Dr. Reed was theSecretary’s representative to the statutorilyauthorized Klamath Fishery Management Councilform 1986 to 1995. The Council oversees therestoration of the Klamath river fishery resourcesand facilitates appropriate allocation for harvest.

Villere C. Reggio, Jr. : Villere Reggio is anOutdoor Recreation Planner with the MineralsManagement Service, Gulf of Mexico OCSRegion. His responsibilities include assessment,research, and reporting on the interrelationship ofthe OCS oil and gas program with therecreational elements of the marine and coastalenvironment throughout the Gulf region. For thepast 21 years Mr. Reggio has had a specialinterest in evaluating the fisheries value andpotential of oil and gas structures.

John B. Richards : John Richards is a marineadvisor emeritus with the California Sea GrantExtension Program and a research biologist withthe Marine Science Institute at the University ofCalifornia, Santa Barbara. In 1976, he begandevelopment of marine extension and appliedresearch program for the south-central coast ofCalifornia and served as Area Marine Advisor forthe counties of San Luis Obispo, Santa Barbara,and Ventura until 1992. During the 1980’s,Richards helped initiate a communications andconflict resolution program, worked with anoil/fishing industry mediation team, and publishedthe Oil and Gas Project Newsletter for Fishermenand Offshore Operators. John is now a memberof a team conducting research in marine fisheriesand shellfish aquaculture at the Marine ScienceInstitute. He continues to work on statewideprojects with the Sea Grant Extension Program.He has a B.A. in zoology from the University ofCalifornia, Santa Barbara and an M.S. degree infisheries biology from Oregon State University.

Dwight Sanders : Dwight Sanders joined theCalifornia State Lands Commission in 1975following more than 8 years as staff to theCalifornia Legislature. Mr. Sanders is currentlyChief of the Division of Environmental Planningand Management and in that capacity has beeninvolved in proposed State and Federal offshorelease sales, and in the policy and environmentalanalyses of: 1) offshore seismic operations; 2)the installation and operation of onshore andoffshore oil and gas related facilities; and 3) thedecommissioning and removal of such facilities.Mr. Sanders also serves as on of the ex officiomembers of the California Coastal Commission,representing the Chair of the State LandsCommission, having received his appointment in1982. Mr. Sanders is a UC Davis alumni, agraduate of the CORO Foundation, and alsoholds a Master of Public Administration.

Russell J. Schmitt : Dr. Russ Schmitt is aProfessor in the Department of Ecology,Evolution and Marine Biology at UC SantaBarbara and Director of the Coastal ResearchCenter of UCSB’s Marine Science Institute. Hereceived his Ph.D. from UCLA in 1979. Dr.Schmitt serves as Program Director for theCoastal Marine Institute and the SouthernCalifornia Educational Initiative, which arecooperative research programs supported by theState of California, University of California andthe Minerals Management Service. He is alsoProgram Director of the UC Coastal ToxicologyTraining Program, a UC-wide component of theUC Toxics Substances Research and TeachingProgram. Russ Schmitt’s primary researchprograms address the abundance and dynamicsof benthic marine animals. His interests in theapplication of basic ecology has led to hisresearch on the design and implementation ofenvironmental impact assessment studies.

Nancy Settle : Nancy Settle has managed theRegional Programs and Project Section for theVentura County Planning Division over the pasteight years. She oversees and supervises theCounty’s involvement in Offshore and OnshoreOil Development and the California Offshore Oiland Gas Energy Resources (COOGR) study.

John Smith : John Smith is a SeniorEnvironmental Coordinator with the MineralsManagement Service’s Office of EnvironmentalEvaluation in Camarillo, California. He has a B.S.degree in geology and an M.S. degree in mineraleconomics from the Pennsylvania State


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University. He joined the Department of theInterior in 1976 with the Bureau of Mines. In1983 he joined the Minerals Management Serviceand since 1988 has been with the Pacific OCSRegional Office where he has served as seniorenvironmental coordinator for major oil and gasdevelopment projects

D. C. (Dave) Tyler : Dave Tyler received hisBachelor of Science in Mechanical Engineering in1981 from the University of California at Berkeley.In 1990, he received his Masters in BusinessAdministration from the University of California atLos Angeles. He began his career with ExxonCompany, U.S.A. in Los Angeles and worked invarious engineering and regulatory positionsassociated with Exxon’s offshore California andAlaska interests. Dave also led Exxon’spermitting efforts for the Santa Ynez UnitDevelopment during its 6-year constructionphase, including removal of the Offshore Storageand Treatment Facility. In 1994, Dave moved toMidland, Texas, and became RegulatorySupervisor for production fields in the westernU.S.. Dave moved to Houston in 1996 and wasnamed to his current position as Public AffairsAdvisor.

Marina Voskanian : Marina Voskanian is theChief Reservoir Engineer with the California StateLands Commission (CSLC), supervisingReservoir Engineering and Geology section of theMineral Resources Management Division locatedin Long Beach. Marina has been employed withthe CSLC since 1987, and she has worked inprivate industry for eleven years prior to workingfor the State of California. During those yearsshe held several engineering and supervisorypositions with Exxon Oil Company, SouthernCalifornia Gas Company, Aminoil and PhillipsPetroleum company. Marina also serves on theBoard of Directors of the Society of PetroleumEngineers, and is presently the Western RegionDirector representing California and Alaska. Shehas been recipient of several awards fromprofessional organizations for her dedicatedservice to the industry. She received hergraduate degrees in Petroleum Engineering fromthe University of Southern California (U.S.C.) in1976. She has been part-time member of faculty, at the California Polytechnic University from1984 through 1990, teaching petroleumengineering courses. Last few years, she hasbeen part time lecturer at U.S.C. teachinggraduate courses in Petroleum engineering.

Maureen Walker : Maureen Walker is the DeputyDirector of the Office of Ocean Affairs, Bureau ofOceans and International Scientific andEnvironmental Affairs, U.S. Department of State.She joined the Department of State in 1983 as aForeign Affairs Officer in the Division of MarineLaw and Policy. She has been in her currentposition for the past 8 years.. She is the Chair ofthe U.S. delegations to international multilateralmeetings on issues related to energy, naturalresources and the environment. She hasparticipated on the U.S. delegation to preparatorymeetings to the United Nations Conference onEnvironment and Development (Rio EarthSummit) and negotiated key documents such asAgenda 21. She serves as Executive Secretariatto the National Security Council InteragencyWorking Group on Global Environmental AffairsTask Force on Law of the Sea, and also servesas U.S. lead negotiator within the Asia PacificEconomic Cooperation forum on marineconservation issues. Maureen Walker has a B.A.from Boston College, an M.A. from GeorgetownUniversity and a J.D. from the Catholic Universityof America.

Bonnie Williamson : Bonnie Williamson hasbeen the Assistant to the Director of the SouthernCalifornia Educational Initiative and the CoastalMarine Institute for the past 8 years. She isinvolved in the administrative and fiscalmanagement of these and other researchprograms administered by the Coastal ResearchCenter (CRC) at UC Santa Barbara. She servesas liaison between the faculty, staff, researchers,agency personnel, grant recipients and theDirectors. Bonnie has served on the organizingcommittee for numerous conferences andworkshops sponsored by the Coastal ResearchCenter. Bonnie has a B.A. in Earth Sciencesfrom SUNY Brockport and an M.A. in Geologyfrom UC Santa Barbara.

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APPENDIX V

List of Attendees............................................................................. 257

Appendix V: Attendees

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LIST OF ATTENDEES

Over 370 people attended the Decommissioning Workshop. There were representatives from fourFederal Departments and five Federal Agencies, six State Agencies, nine local and county agencies,ten academic institutions, seventeen citizen groups, and over sixty industry companies (oil producers,consultants and contractors), as well as several international representatives.

Barbara Abbriano (student)Santa Barbara City CollegeSanta Barbara, CA

Allen AdamsMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Dolores Aguillar-ZepadaChevron USA, Inc.646 County Square DriveVentura, CA 93003

Clement AlbertsPOOI2225 Sperry, Suite 1300Ventura, CA 93003

Jim Allen, PresidentHydroDynamic CuttingServicesP.O. Box 80843Lafayette, LA 70598

Richard AmbroseUC Los AngelesEnvir. Sci. & Engineering Prog.Room 46-081 CHS Box951772Los Angeles, CA 90095-1772

Mike AmmannChevron Research100 Chevron WayRichmond, CA 94802-0627

Doug AnthonySanta Barbara Co. Energy Div.1226 Anacapa Street, 2nd FloorSanta Barbara, CA 93101

Hector Hernandez AranaInstituto Nacional del la Pesca(Mexican Natl. FisheriesInstitute)Pitagoras 1320 Col. Sta. CruzAtoyacD.F. 03310 Mexico

Roma ArmbrustCoastal Issues DirectorLeague of Women Voters1151 Shelburn LaneVentura, CA 93001

Ellen AronsonMinerals Management Service770 Paseo Camarillo, MS 7100Camarillo, CA 93010

Avis AustinLeague Of Women Voters1378 – 7th StreetLos Osos, CA 93402-1223

Quang BachCalif. State Lands Commission200 Oceangate, Ste 1200Long Beach, CA 90802

Lee BafalonChevron USA, Inc.646 County Square DriveVentura, CA 93003

Brian BairdOcean Program ManagerThe Resources Agency ofCalif.1416 9th Street, #1311Sacramento, CA 95814

Brian BalcomRegional ManagerContinential Shelf Associates,Inc.310 3rd Avenue, N.E.Issaquah, WA 98027

Martha BarajasMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Joan BarminskiMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Arthur BarnettMEC Analytical Systems, Inc.2433 Impala DriveCarlsbad, CA 92008

Kristine BarskyCalif. Dept. of Fish and Game530 E. Montecito Street, Rm.104Santa Barbara, CA 93103

R.C. (Rick) BartonNew Ventures-Central CoastAera Energy LLCP.O. Box 11164Bakersfield, CA 93389-1164

Chandra BasavalinganadoddiCalif. State Lands Commission200 Oceangate, Ste 1200Long Beach, CA 90802

John BauckeBixby Ranch Company125 E. Victoria Street, Ste LSanta Barbara, CA 93101

Thomas BeamishMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Dennis BedfordCalif. Dept. of Fish and Game330 Golden Shore, Ste 50Long Beach, CA 90802


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Bill BeebeUnited Anglers of SouthernCalif.Legislative Chair24958 Malibu RoadMalibu, CA 90265

Theresa BellMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Jim BellowsChevron Products Company575 Lennon Lane, Ste N2212Walnut Creek, CA 94598

Sue BenechBenech Biological Associates487 Lincoln DriveVentura, CA 93001

Colleen BennerMinerals Management Service381 Elden St, MS 4041Herndon, VA 20170-4817

George BennettUNOCAL2125 Knoll Drive, Ste 200Ventura, CA 93003

Terry BertolineCalif. State Lands CommissionP.O. Box 1237Goleta, CA 93116-1237

David “Chip” BlankenhornEntrix, Inc.590 Ygnacia Valley Road,Ste 200Walnut Creek, CA 94596

Ken BlondenCommercial Fisherman321 Cahuenga DrOxnard, CA 93035

Tammy BlondenLight Boat Operator321 Cahuenga DrOxnard, CA 93035

Penny BloodhartLeague of Women Voters1475 TheresaCarpenteria, CA 93103

Dave BlurtonCalif. Dept. of Fish and GameP.O. Box 944209Sacramento, CA 94244

Arthur BoehmNuevo Energy Company201 South BoadwayOrcutt, CA 93455

Peter Bontadelli, AdministratorOffice of Oil Spill Preventionand ResponseCalif. Dept. of Fish and Game1416 9th StreetSacramento, CA 95814

Marianne BoucherMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Major Paul BoughmanU.S. Marine CorpsStaff Judge AdvocateIst MEFCamp Pendleton, CA 92055-5400

Edward BoyesCalif. Dept. of Fish and Game330 Golden Shore, Ste 50Long Beach, CA 90802

Paul Bradford2nd District Supervisor StaffSB County Board ofSupervisors105 E. Anapuma StreetSanta Barbara, CA 93101

John BrandonOil States Micro CuttingServices18501 Aldin WestfieldHouston, TX 77073

Jerry BrashierMinerals Management Service1201 Elmwood Park Blvd.,MS 5440New Orleans, LA 70123-2394

Julia Braun (student)Santa Barbara City CollegeSanta Barbara, CA

Nancy E. BrodbeckTorch Operating Company500 N. Kraemer Blvd., Bldg BBrea, CA 92821

Dean BrownBrown & Root Energy Services110 Capital Drive, Ste 200Lafayette, LA 70508

David BrowneMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Sharon BuffingtonMinerals ManagementServices381 Elden MS 4021Herndon, VA 20170

Dianna BurceAmerican Pacific Marine741 East Arcturus Ave.Oxnard, CA 93033

Steve BurkeTorch Operating Company500 N. Kraemer Blvd., Bldg. BBrea, CA 92821

Todd BuschCrowley MarineP.O. Box 2287Seattle, WA 98111

Dr. Robert ByrdTwachtman, Snyder & Byrd,Inc.13105 Northwest Freeway, Ste700Houston, TX 77040


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Tim CagleExxonP.O. Box 2180Houston, TX 77252

Bruce CampbellP. O. Box 761Summerland, CA 93067-0761

Rob Campbell-TaylorVenocoP.O. Box 8540Goleta, CA 93118

Peter CantleSanta Barbara County APCDAir Pollution and ControlDistrict26 Castilian Drive, B-23Goleta, CA 93117

Mark CarrDepartment of BiologyUC Santa CruzSanta Cruz, CA 95064

Roger CarryTorch Operating CompanySanta Maria, CA

Mike Carter556 Canyon Vista DriveNewbury Park, CA 91320

Carlos CasrianState Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802

Arturo CastañonInstituto Nacional De La pescaCirios No. 178Fracc. Las FincasEnsenada, B.C. 22810Mexico

Dee W. ChamberlainArco444 South Flower Street,ALF-3433Los Angeles, CA 90071

Marc ChytilloEnvironmental Defense Center906 Garden Street, #2Santa Barbara, CA 93101

Curtis Clark31 QuintoSanta Barbara, CA 93105

Del ClementChevron USA, Inc.646 County Square DriveVentura, CA 93003

Richard ClinganMinerals Management ServiceSanta Maria District Office222 W. Carmen Lane, Ste 201Santa Maria, CA 93455

Brian CollinsUC Berkeley2324 Piedmont Ave.Berkeley, CA 94704

Steve CoombsPacific Operators Offshore Inc.205 E. Carrillo Street, Ste 200Santa Barbara, CA 93101

Tim CooperChevron USA, Inc.646 County Square DriveVentura, CA 93003

Patrick CorcoranOgden Environmental1 E. Anapamu StreetSanta Barbara, CA 93101

Gordon CotaSouthern Calif. TrawlersAssoc.706 Surfview DriveSanta Barbara, CA 93109

Adriana CrasneanOffice of the State Fire Marshal1501 W. Cameron, C-250West Covina, CA 91790

Andrew CulwellV.P. Special ProjectsAmerican Pacific Marine741 East Arcturus Ave.Oxnard, CA 93033

Steve CurranCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802

Jeff DamronPadre Associates, Inc.5450 Telegraph Road, Ste 101Ventura, CA 93003

Elmer “Bud” DanenbergerMinerals Management Service381 Elden Street, MS4020Herndon, VA 20170-4817

Mark DemeoCalif. State Lands CommissionP.O. Box 1237Goleta, CA 93116-1237

Kathy deWet-OlesonSea Ventures Dive Boat5286 Shiloh WayVentura, CA 93003

Frank DeMarcoCentral Coast Regional WaterQuality Control Board81 Higuera Street, Ste 200San Luis Obispo, CA 93401

Alison DettmerCalifornia Coastal Commission45 Fremont Street, Ste 2000San Francisco, CA 94105-2219

Onno deWaardHeere Mac v.o.tP.O. Box 93212300 PH LeidenThe Netherlands

Leray DeWitL.A. deWit, Consultant2054 Bluerock CircleConcord, CA 94521-1672

Doug DienerMEC Analytical Systems, Inc.2433 Impala DriveCarlsbad, CA 92008

Robert DimitroffChevron Facilities Engineering1301 McKinneyHouston, TX 77010


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Dr. Robert DittonDept. of Wildlife & FisheriesSciencesTexas A & M UniversityCollege Station, TX 77840-2258

Frank DonahueCommercial Trawler, Owner-OperatorP. O. Box 792Avila Beach, CA 93424

J. DonlonUnited Anglers of SouthernCalif.716 Calle Palo ColoradoSanta Barbara, CA 93105

William DourosSanta Barbara Co. Energy Div.1226 Anacapa StreetSanta Barbara, CA 93101

Roderick DraughonInternational Flow Corp.23500 64th Avenue SouthKent , WA 98032

Barbara DugalCalif. State Lands Commission100 Howe Avenue, Ste 100SouthSacramento, CA 95825

Barbie DuganCal Poly San Luis Obispo331 Oahu StreetMorro Bay, CA

Candy DuganFugro West Inc.1421 State StreetSanta Barbara, CA 93101

Dan DuganCal Poly San Luis Obispo331 Oahu StreetMorro Bay, CA 93442

Dr. Jenifer DuganMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Mary Elaine DunawayMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Tom DunawayMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Chuck EbnerOceaneering Intl., Inc.2055 N. Ventura AvenueVentura, CA 93001

Hannah EckbergGet Oil Out914 Anacapa StSanta Barbara, CA 93101

Mark EckenrodeMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Stefanie EdmondsonCity of Carpinteria5775 Carpinteria AvenueCarpinteria, CA 93013

Deborah EidsonMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Alan EmsliePadre Associates, Inc.5450 Telegraph Road, Ste 101Ventura, CA 93003

John EngleMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Iraj ErshaghiProfessor and DirectorUniversity of SouthernCaliforniaHedco 316, University ParkLos Angeles, CA 90089-1211

Bryn EvansMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Matt EvansTorch Operating Company500 N. KraemerBlvd, Bldg. BBrea, CA 92821

Ellie Fairbairn (student)Santa Barbara City CollegeSanta Barbara, CA

Maurya FalknerCalif. State Lands CommissionMarine Facilities Division330 Golden shore, Ste 210Long Beach, CA 90802-4246

Rod FarrellPadre Associates, Inc.5450 Telegraph Road, Ste 101Ventura, CA 93003

A.J. FieldBenech Biological Associates487 Lincoln DriveVentura, CA 93001

Steve FieldsCalif. Dept. of ConservationDiv. Oil, Gas & GeothermalRes.1000 South Hill Road, Ste 16Ventura, CA 93003-4458

Jennifer FosterSanta Barbara Co. Energy Div.1226 Anacapa Street 2nd FloorSanta Barbara, CA 93101-2010

Nancy FrancisVentura County,Resource Mgmt. Agency /Planning Div.L-1740800 South Victoria Ave.Ventura, CA 93009

Darryl FrancoisMinerals Management Service1849 C. St., NWMS 0100Washington, DC 20240


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Daniel FrumkesUnited Anglers of SouthernCalif.24958 Malibu RoadMalibu, CA 90265

Craig FusaroJoint Oil/Fisheries LiaisonOffice121 Gray Avenue, Ste 205ASanta Barbara, CA 93101

Dave GabauerMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Peter GambleADL3916 State Street, Ste 2ASanta Barbara, CA 93105

Robert C. GardnerFairweather E & P Services,Inc.241 Market Street, No. 3Port Hueneme, CA 93041-3218

Michelle GasperiniSanta Barbara Co. Energy Div.1226 Ancapa Street, 2nd FloorSanta Barbara, CA 93101

Michael GialketsisRincon Consultants790 E. Santa Clara StreetVentura, CA 93001

Marty GoldenNational Marine FisheriesService501 W. Ocean Blvd., Ste 4200Long Beach, CA 90802

Daniel GorfainCalif. State Lands CommissionDiv. of Envir. Planning & Mgmt.100 Howe Ave., 100-SouthSacramento, CA 95825-8202

Bill GradyExxonP. O. Box 5025Thousand Oaks, CA 91359

James GrantMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Gary GrayChevron USA, Inc.646 County Square DriveVentura, CA 93003

Gary GregoryCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA

Steve Greig1014 Santa Barbara StreetSanta Barbara, CA 93101

W.S. (Bill) GriffinInternat’l Regulation ConsultantE & P ForumInternational Exploration &Production25/28 Old Burlington StreetLondon, W1X 1LBEngland

Mark GriffithOSTVentura, CA

Robert GroveSouthern California Edison2244 Walnut Grove AvenueRosemead, CA 91770

Richard HabratMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

M.L. HagoodArco444 South Flower StreetALF-3433Los Angeles, CA 90071

Bobbie HallMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

William HamnerDept. of BiologyUniversity of CaliforniaLos Angeles, CA

Connie HannahSB League of Women Voters5194 Calle AsiloSanta Barbara, CA 93111

Susan Hansch, Deputy DirectorEnergy & Ocean ResourcesUnitCalifornia Coastal Commission45 Fremont Street, Ste 2000San Francisco, CA 94105-2219

Dane HardinApplied Marine Sciences, Inc.2155 Las Positas Court, Ste. SLivermore, CA 94550

Dean HargisDames & Moore5383 Hollister Avenue, Ste 120Santa Barbara, CA 93111

Marty Harter1039 South SeawardVentura, CA 93001

Per Bull HaugsoenOffshore Shuttle ASStranden 3A0250 OsloNorway

Wendy Hawksworth (student)Santa Barbara City CollegeSanta Barbara, CA

Donna HebertPadre Associates, Inc.5450 Telegraph Road, Ste 101Ventura, CA 93003

Mark HelveyNOAA/National MarineFisheries Service777 Sonoma Avenue, Rm 325Santa Rosa, CA


262

Steve HenryFish & Wildlife Biologist2493 Portola Rd., Ste BVentura, CA 93003

Jerry HensleyChevron USA, Inc.646 County Square DriveVentura, CA 93003

Joann HerrickMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Michael HigginsWater Quality Control BoardCentral Coast Region81 Higuera St., Ste 200San Luis Obispo, CA 93401-5427

Robert Hight, Executive OfficerCalif. State Lands Commission100 Howe Ave., Ste 100 SouthSacramento, CA 95825

Maurice HillMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Cathy HoffmanMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Arne HolhjemPhillips Petroleum6330 W. Loop SouthBellaire, TX 77401

Frank HolmesWestern States PetroleumAssoc.121 Gray Avenue, Ste 205Santa Barbara, CA 93101

Jean HolmesSanta Barbara League ofWomens Voters3749 Brenner DriveSanta Barbara, CA 93105-2407

Tim HolmesU.S. Coast GuardBLDG 50-6Coast Guard IsAlameda, CA 94501-5100

Keith HowellChevron USA, Inc.646 County Square DriveVentura, CA 93006

Peter HoworthMarine Mammal ConsultingGroup389 West Hope AvenueSanta Barbara, CA 93110

Maher IbrahamMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Eiji ImamuraMarine Research Specialists3639 E. Harbor Blvd., Ste 208Ventura, CA 93001

Merrill JacobsClean Seas1180 Eugenia Place, #204Carpinteria, CA 93013

James JohnsonCalifornia Coastal Commission89 So. California St., 2nd FloorVentura, CA 93001

James P. JohnsonPhillips Petroleum6330 W. Loop SouthBellaire, TX 77401

Jay A. JohnsonApplied Marine Sciences, Inc.2155 Las Positas Court, Ste SLivermore, CA 94550

Pete JohnsonChief Petroleum EngineerCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802-4331

John JonesExxonP. O. Box 2189Houston, TX 77252

Lynne KadaVentura County ResourcesAgency800 So. Victoria Ave.Ventura, CA 93009

Carolita KallaurMinerals Management ServiceOffshore MineralsManagement1849 C Street, NW, MS 4230Washington, DC 20240-0001

Lisa KayMEC Analytical Systems, Inc.2433 Impala DriveCarlsbad, CA 92008-7227

Charles KelmHalliburton Energy Services1450 Poydras Street, Ste 2170New Orleans, LA 70112

Jeff KennedyMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Stephen J. KenneyBigge Crane & Rigging Co.10700 Bigge StreetSan Leandro, CA 94577

Pat KinnearCalif. Dep.t of ConservationDiv. of Oil, Gas & GeothermalResources1000 S. Hill Road, Ste 16Ventura, CA 93003

Donna KleeburgPort Hueneme CommericialFisherman3900 San Simeon AveOxnard, CA 93033

Dan KnowlsonMinerals Management Service222 W. Carmen Lane, Ste 201Santa Maria, CA 93458


263

Karin KochM.F. Strange & AssociatesP. O. Box 1484Santa Barbara, CA 93102

Andrew KonczvaldMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Linda KropEnvironmental Defense Center906 Garden Street, # 2Santa Barbara, CA 93101

A.W. KruegerThyssen SteelP.O. Box 19686Houston, TX 7724-19686

John LaneMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Herb LeedyMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Peter LeighNational Marine FisheriesServiceBuilding 3, Room 126071315 East West HighwaySilver Springs, MD 20910-3282

John LienCalif. State Lands Commission100 Howe Avenue,Ste 100-SouthSacramento, CA 95825-8202

Eddie Lee LimMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

James LimaMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Joseph LimaGoleta, CA

Andrew LissnerSAIC10260 Campus Point Dr., MSC-5San Diego, CA 92121-1578

Andrew LordMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Bob LoveLove Fishing and Diving Co.139 Stanford AvenueOxnard, CA 93030

Dr. Milton LoveMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Charles MacDonaldOffice of the State Fire MarshalDept. of Forestry & FireProtection1501 W. Cameron C-250West Covina, CA 91790

Michael MachuzakAquatic Bioassay &Consulting Labs29 N. Olive StreetVentura, CA 93001

Tony MackayBrown & Root Energy ServicesWellhead PlaceDyce, Aberdeen AB2 0GGSCOTLAND

Vance MackeyChevron Petroleum Tech.Comp.6001 Bollinger Canyon RoadP.O. Box 5045San Ramon, CA 94583-0945

Frank ManagoMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Michael MarksMobil Exploration & Producing1250 Poydras, Ste 1436New Orleans, LA 70113

Phil MarquezExxon Company, USAP.O. Box 4358Houston, TX 77210-4358

Gail MartinB & J Martin, Inc.P.O. Box 448Cut Off, LA 70345

Jimmie MartinB & J Martin, Inc.P.O. Box 448Cut Off, LA 70345

Sue MartinSanta Barbara Co. PlanningDept.1226 Anacapa StreetSanta Barbara, CA 93101

Scott MartindaleChevron USA, Inc.646 County Square DriveVentura, CA 93003

Jorge Escobar MartinezECODES-SAIEcologia y Desarrollos, S.P.Blvd. Teniente Azueta 130-1Recinto PortuarioEnsenada, B.C. 22800Mexico

Nabil MasriMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Tom MatteucciRincon Consultants790 E. Santa Clara StreetVentura, CA 93001

Annisa MayerOffice of the Vice Chancellor –ResearchChancellor’s Office2234 Murphy HallUC Los AngelesLos Angeles, CA 90095-1405

Randy MayesStandard Ind.P.O. Box 23278Ventura, CA 93002


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Jack McCarthyMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Mike McCorkleSouthern Calif. TrawlersAssoc.P.O. Box 713Summerland, CA 93067

Merit McCreaCaptain McCrea's Sportfishing1762-1/2 Prospect Ave.Santa Barbara, CA 93103

Genie McGaughVentura County APCD669 County Square Dr2nd FloorVentura, CA 93003

Cris McGuffeeExxonP.O. Box 22180Houston, TX 77252-2180

Melissa MeekerMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Paul MehtaQST Environmental17390 Brookhurst StreetSte 110Fountain Valley, CA 92708

Bob MenseMinerals Management Service381 Elden St., MS 4050Herndon, VA 20170-4817

Jerry MenesezMobil OilP.O. Box 8540Goleta, CA 93118

Steve MerritChevron USA, Inc.646 County Square DrVentura, CA 93003

Robert MiddletonMinerals Management Service1849 C. Street NWWashington, DC 20240

Tim MikelAquatic Bioassay &Consulting Labs29 N. Olive StreetVentura, CA 93001

Stuart Miller (student)Santa Barbara City CollegeSanta Barbara,CA

Mary Ann MilosavichMinerals Management Service381 Elden Street, MS 4030Herndon, VA 20170-4817

Jeff MiltonStaff Geological Engineer5060 California AvenueBakersfield, CA 93389

Charles MitchellMBC Applied EnvironmentalSciences3040 Redhill AveCosta Mesa, CA 92626

Mike MitchellMinerals Management ServiceSanta Maria District Office222 W. Carmen Lane, Ste 201Santa Maria, CA 93455

Tooraj MonsefCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802

Mick Mora (student)Santa Barbara City CollegeSanta Barbara, CA

Frank MorinLongitude 1231080 Stillwater CourtVentura, CA 93004

Mike MoropoulosSanta Barbara, CA

Paul Mount, II, ChiefMinerals Resources Mgmt. Div.Calif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802-4471

Andrew MoynaghBuilding and ConstructionTrades Council AFL-CIO415 Chapala StreetSanta Barbara, CA 93101

Tim MurphyMorton Associates, Inc.5973 Encina Road, Ste 100Goleta, CA 93117-2273

Steven MurrayDept. of Biological ScienceMH 282 P.O. Box 6850CalState FullertonFullerton, CA 92834-9480

Aiden Naughton (retired)Calif. State Lands Commission200 Oceangate, Ste 200Long Beach, CA 90802

Geir NilsenCommerical FishermanP.O. Box 1376Summerland, CA 93067

Mary NishimotoMarine Science InstituteUC Santa BarbaraSanta Barbara, CA 93106

Suzanne NobleWSPA,Coastal EnvironmentalCoordinator121 Gray Avenue, Ste 205Santa Barbara, CA 93101

Craig OgawaMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Dave OnoCalif. Dept. of Fish and Game530 E. Montecito St., Rm 104Santa Barbara, CA 93103-1207


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H. Mark PageMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Christina Palmer (student)Santa Barbara City CollegeSanta Barbara, CA

Lisa PalmerDavies Communications808 State StreetPaseo NuevoSanta Barbara, CA 93101

W.W. PalmquistUnited Anglers of SouthernCalif.716 Calle Palo ColoradoSanta Barbara, CA 93105

Dave PanzerMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Dave ParkerSenior BiologistCalif. Dept. of Fish and GameMarine Resources Division330 Golden Shore, Ste 50Long Beach, CA 90802

John Patton, DirectorSanta Barbara CountyDept. of Planning &Development123 East Anapamu StreetSanta Barbara, CA 93101

Eleanor PaulazzoGoleta, CA

Margaret Peavey (student)Santa Barbara City CollegeSanta Barbara, CA

Mike PeekTorch Operating Company500 N Kraemer Blvd, Bldg BBrea, CA 92821

John PeirsonArthur D. Little3916 State Street, Ste 2ASanta Barbara, CA 93109

Greg PelkaCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802-4471

Jim PennyCrowley MarinePier D, Berth 47Long Beach, CA 90802

Luis PerezSanta Barbara Co. Energy Div.1226 Anacapa StreetSanta Barbara, CA 93101

Larry PerkinsChevron575 Lennon Lane N2214Walnut Creek, CA 94598

Vincent Peteque (student)Santa Barbara City CollegeSanta Barbara, CA

Larry PhilipCalif. State Lands CommissionP.O. Box 1237Goleta, CA 93116-1237

Robert PhillipsMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Mark PiersonMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Dr. Fred PiltzMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Ron PitmanMarine Sciences900 Avenida SalvadorSan Clemente, CA 92672-2323

Tobe PloughConsultantP.O. Box 5731Santa Barbara, CA 93150

Patricia PortU.S. Dept. of the InteriorOffice of Environmental Policy& Compliance600 Harrison Street, Ste 515San Francisco, CA 94107-1376

Simon PoulterPadre Associates, Inc.5450 Telegraph Road, Ste 101Ventura, CA 93003

Peter PrasthoferODCPc/o E&P Forum25/28 Old Burlington StLondon, W1X 1LBEngland

Barbara PricePhillips Petroleum Company6330 W. Loop South, Rm 1473Bellaire, TX 77401

Tom RafticanUnited Anglers of SouthernCalif.716 Calle Palo ColoradoSanta Barbara, CA 93105

Peter RaimondiDepartment of BiologyUC Santa CruzSanta Cruz, CA 95064

Hamid RastegarAspen Environmental Group30423 Canwood Street, Ste218Agoura Hills, CA 91301

John ReedHeeremac Offshore Services17154 Butte Creek, Ste 200Houston, TX 77090

Dr. Lisle ReedMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010


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Villere ReggioMinerals Management Service1201 Elmwood ParkBoulevard, MS 5410New Orleans, LA 70123-2394

John RichardsMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

G. Ed RichardsonMinerals Management Service1201 Elmwood Park Blvd.,MS 5441New Orleans, LA 70123-2394

Peggy RivasMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

David RobinsonMEC Analytical Systems, Inc.2433 Impala DriveCarlsbad, CA 92008

J.B. RodieckTwatchman, Snyder & Byrd,Inc.13105 Northwest Freeway, Ste700Houston, TX 77040

Maggie RoeJ. Walter Thompson4 Embarcadero CenterSan Francisco, CA 94115

Eric RoggerUnited Anglers of SouthernCalif.24958 Malibu RoadMalibu, CA 90265

John RomeroMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Jacqueline RomoMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Albert RonyeczAdvance Technical Services116 Lancaster PlaceGoleta, CA 93117

Chris RoperAmerican Pacific Marine741 East Arcturus Ave.Oxnard, CA 93033

Brock RosenthalMecco California7709 Prospect PlaceLa Jolla, CA 92037

David RosenbergUC BerkeleyP.O. Box 148Morgan City, LA 70381

Bob RydgigP.O. Box 733Camarillo, CA 93011

Alicia SabryCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802

Manny SaenzMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Dwight SandersChief, Div. of Envir. Plan. &MgmtCalif. State Lands Commission100 Howe Avenue, 100-SouthSacramento, CA 95825

Greg SandersCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802-4331

Dale SaundersOffice of the State Fire MarshalDept. of Forestry & FireProtection1501 W. Cameron C-250West Covina, CA 91790

Jochen ScheneThyssen SteelGermany

Kim SchizasWynmark Inc.6500 Hollister Avenue, Ste 100Goleta, CA 93117

Russell SchmittMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Jennifer SchollAspen Environmental Group30423 Canwood Street, Ste218Agoura Hills, CA 91301

Greg SchrageUnocal2323 Knool DriveVentura, CA 93003

Phillip Schroeder,District SupervisorMinerals Management ServiceSanta Maria District Office222 W. Carmen Lane, Ste 201Santa Maria, CA 93455

Donna SchroederMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Richard SchubelU.S. Army Corps of Engineers911 Wilshire Blvd.Los Angeles, CA 90017

Alan ScottCalif. State Lands Commission100 Howe Avenue,Ste 100 SouthSacramento, CA 95825

Steven SeatPhillips Petroleum Company6330 W. Loop South, Rm 1473Bellaire, TX 77401

Nancy SettleVentura County Planning800 S. Victoria Avenue, L #1740Ventura, CA 93009


267

Keith SeydelMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Glenn ShackellMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Arvind ShahMinerals Management Service1201 Elmwood Park Blvd.New Orleans, LA 70123-2394

Allan ShareghiMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Shannon ShawMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Gary ShepherdPipeline Safety EngineerOffice of the State Fire MarshalDept. of Forestry & FireProtection1501 W. Cameron C-250West Covina, CA 91790

Kelly SiddiquiMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Paul SimonUnited Anglers of SouthernCalif.24958 Malibu RoadMalibu, CA 90265

Bob SmithMinerals Management Service381 Elden StreetHerndon, VA 20170

Charles SmithMinerals Management Service381 Elden StreetHerndon, VA 20170-4817

Eric SmithDept. of Political ScienceUniversity of CaliforniaSanta Barbara, CA 93106

John SmithMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Martyn SnapeOil States Micro-CuttingServices18501 Aldin WestfieldHouston, TX 77073

Ralph SnyderMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Rick SorrellU.S. Coast GuardMarine Safety Detachment111 Harbor WaySanta Barbara, CA 93109

Ed SpauldingThe Chevron CompaniesP.O. Box 1392Bakersfield, CA 93302

Mark SteffyLongitude 1231080 Stillwater CourtVentura, CA 93004

John StephensVantuna Research Group2550 Nightshade PlaceArroyo Grande, CA 93420

Dr. Theresa StevensU.S. Army Corps of Engineers2151 Alessandro Drive, Ste255Ventura, CA 93001

Alex StiemChevron USA, Inc.646 County Square DrVentura, CA 93003

Bill StolpDames & Moore2445 W. Shaw Avenue, Ste101Fresno, CA 93711

Marianne StrangeM.F. Strange & AssociatesP.O. Box 1484Santa Barbara, CA 93102

Melanie StrightMinerals Management Service381 Elden StreetHerndon, VA 20170

Mark Swearingen1015 Chino StreetSanta Barbara, CA 93101

Win SwintArroyo Burro Reef Company62 Canon View RoadMontecito, CA 93108

Ron TanSanta Barbara County APCD26 Castilian Dr B-23Goleta, CA 93117

Bill ThomasSquid Boat OperatorSanta Barbara, CA

Randy ThompsonOceaneering Intl., Inc.2055 N. Ventura AvenueVentura, CA 93001

Rosie ThompsonSAIC816 State Street, Ste 500Santa Barbara, CA 93101

Bill ThompsonCommercial Trawler, Owner-OperatorSanta Barbara, CA

Win ThorntonWinmar Consulting12020 West Little York, Ste200Houston, TX 77041


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Lyman ThorsteinsonU.S. Geological SurveyBiological Resources Division909 First Avenue, Ste 800Seattle, WA 98104

Guillermo TorresUniversidad Autonoma de BajaCaliforniaFacultad de Ciencias MarinasKM 103 CarreteraTijuana-EnsenadaEnsenada, Baja California,MexicoCP 22880

John L. TrahanVentura County Fish andGame1078 Peninsula StreetVentura, CA 93001

Ron TripeCalif. State Lands CommissionP.O. Box 1237Goleta, CA 93116-1237

Rishi TyagiMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

David C. TylerExxon Co., USAP.O. Box 2180Houston, TX 77252-2180

Tom UmenhoferSierra Pacific Environmental5951 Encina Road, Ste 206Goleta, CA 93117

Duane VanderPlayenRincon Consultants790 E. Santa Clara StreetVentura, CA 93001

Eugenie Van SchotenLeague of Women Voters2430 Bayside Pl.Arroyo Grande, CA 93420

Diane VavrekChevron1163 Main Street, Ste CMorro Bay, CA 93442

Lynnette VescoMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Marina VoskanianCalif. State Lands Commission200 Oceangate, 12th FloorLong Beach, CA 90802

Kirk WalkerCalif. State Lands Commission100 Howe Avenue,Ste 100 SouthSacramento, CA 95825

Maureen WalkerChief, Office of Ocean AffairsU.S. Department of State2201 C Street, NW., Rm 5805Washington, DC 20520

Sara WanCalifornia Coastal Commission22350 Carbon MesaMalibu, CA 90265

Libe WashburnDepartment of GeographyUC Santa BarbaraSanta Barbara, CA 93106

Tim WatsonAmoco (U.K.) ExplorationAmoco HouseWestgateLondon, W5 1XLUnited Kingdom

Chris WeakleySanta Barbara, CA

Matt Weidmann (student)Santa Barbara City CollegeSanta Barbara, CA

Julie WelchRincon Consultants790 E. Santa Clara StreetVentura, CA 93001

Tiffany WelchU.S. Army Corps of EngineersVentura Reg. Field Office2151 Alessandro Drive., Ste255Ventura, CA 93001

Bill WelshDames & Moore5383 Hollister Ave #120Santa Barbara, CA 93111

Fred WhiteMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Nancy WilhelmsenCamarillo, CA

Richard WilhelmsenMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Al WillardSupervising EngineerCalif. State Lands CommissionMinerals Resources Mgmt. Div.200 Oceangate, 12th FloorLong Beach, CA 90802-4331

Richard WilliamsSave Our Shellfishc/o Bob Evans Designs715 KimballSanta Barbara, CA 93103

Bonnie WilliamsonMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Ken WilsonCalif. Dept. of Fish and GameOil Spill Prevention &ResponseSanta Barbara, CA

James WisemanUC Berkeley2119 Russell Street, Apt. ABerkeley, CA 94705-1048


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Elverlene Wms-FlattsMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Rochelle Wms-HooksMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Steve WolfsonMinerals Management Service770 Paseo CamarilloCamarillo, CA 93010

Issac WoodSanta Barbara City College(student)Santa Barbara, CA

Debbie WoodsUC BerkeleyInstitute of Industrial Relations2521 Channing Way, #5555Berkeley, CA 94720-5555

Paul Z. WrightGet Oil Out914 Anacapa StSanta Barbara, CA 93101

Kristin ZabaronickMarine Science InstituteUniversity of CaliforniaSanta Barbara, CA 93106

Kerby ZozulaVentura County APCD669 County Square Dr., 2ndFloorVentura, CA 93003

Louis ZylstraAmerican Pacific Marine14841 Yorba Street, Ste 101Tustin, CA 92780

DECOMMISSIONING AND REMOVAL OF OIL AND GAS FACILITIES ... · W.S. (Bill) Griffin, Jr., Phillips...

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Transcript of DECOMMISSIONING AND REMOVAL OF OIL AND GAS FACILITIES ... · W.S. (Bill) Griffin, Jr., Phillips...