The Offshore Pipeline Construction Industry: Activity Modeling and Cost Estimation in the United States Gulf of Mexico: Activity Modeling and Cost Estimation in the U.S Gulf of Mexico [1 ed.] 0128202882, 9780128202883

Table of contents :
Cover
The Offshore Pipeline Construction Industry
Copyright
Contents
List of Boxes
Executive Summary
Organization
Outline
Highlights
Data Sources
Units
References
Abbreviations and Acronyms
Units
Acknowledgments
Part 1: Gulf of Mexico Background
1 Offshore Overview
1.1 Gulf of Mexico
1.1.1 Origins
1.1.2 Shelf Versus Slope Features
1.1.3 State Versus Federal Waters
1.1.4 Salt and the Sigsbee Escarpment
1.2 Regulatory Structure
1.2.1 Oil and Gas Leasing
1.2.2 Regulatory Authorities
1.2.3 Fair Play, Safety, Liability, and Decommissioning
1.3 Production System Components
1.3.1 Wells
1.3.2 Structures
1.3.3 Pipelines
1.3.3.1 Class
1.3.3.2 Type and Coatings
1.3.3.3 Flow conditions
1.3.3.4 Dimension
1.3.3.5 API 5L base pipe
1.3.3.6 Grade
1.3.3.7 Design
1.3.3.8 Manufacturing
1.3.4 Subsea Systems
1.3.4.1 Umbilicals
1.3.4.2 Risers
1.4 Design Process
1.4.1 Conceptual Engineering
1.4.2 Preliminary Engineering
1.4.3 Detailed Engineering
References
2 Flow Assurance Issues
2.1 Flow Patterns
2.1.1 Reservoir to Well Bottom
2.1.2 Well Bottom to Wellhead
2.1.3 Flowline Flow
2.1.4 Export Pipeline Flow
2.1.5 Oil Phase Diagram
2.2 Design Issues
2.3 Hydrocarbon Components
2.3.1 Hydrates
2.3.2 Waxes
2.3.3 Asphaltenes
2.3.4 Resins
2.4 Hydrate Management Techniques
2.4.1 Depressurization
2.4.2 Insulation
2.4.3 Dehydration
2.4.4 Loop Arrangement
2.4.5 Continuous Chemical Injection
2.4.6 Heating
References
3 Field Development STRATEGIES
3.1 Systems Perspective
3.2 Conceptual Development
3.2.1 Reservoir Geometry
3.2.2 Hub Platforms
3.2.3 Flowline Architecture
3.3 Development Strategies
3.3.1 Field Architecture
3.3.2 Looped Flowlines
3.3.3 Floating Production Storage and Offloading Vessels
3.3.4 Direct Vertical Access Wells
3.3.5 Oil Versus Gas Systems
3.3.6 Reservoir Quality
3.4 Hub Classification
3.5 Hub Platforms
3.5.1 Process and Export Capacity
3.5.2 First-Generation Hubs
3.5.3 Second-Generation Hubs
3.5.4 Transportation Hubs
References
4 Deepwater hazards and chemosynthetic communities
4.1 Manmade Hazards
4.2 Geohazards
4.2.1 Slope Stability
4.2.2 Furrows
4.2.3 Mudslide Regions
4.2.4 Faults and Scarps
4.3 Chemosynthetic Communities
References
Part 2: Offshore Construction Service Industry
5 Pipeline Installation and Vessel Specifications
5.1 Installation Techniques
5.1.1 S-Lay System
5.1.2 J-Lay System
5.1.3 Reel-Lay Method
5.2 Vessel Specifications
5.2.1 Hull
5.2.2 Pipelay Equipment
5.2.3 Station Keeping
5.2.4 Water Depth
5.2.5 Work Stations
5.2.6 Tensioners
5.2.7 Power
5.2.8 Cranes
5.2.9 Accommodations
5.2.10 Other Capabilities
5.3 Classification and Registration
References
6 World Pipelay Fleet CIRCA 2020
6.1 Vessel Classification
6.1.1 Legacy Vessels
6.1.2 Low-Spec Barges
6.1.3 High-Spec Barges and Semis
6.1.4 High-Spec Vessels
6.1.5 Ultrahigh-Spec Vessels
6.2 World Pipelay Fleet
6.2.1 Data Source
6.2.2 Inventory Statistics
6.2.3 Class Comparison
6.2.4 Deepwater Vessels
6.3 Pipelay Vessels by Class
6.3.1 Low-Spec Barges
6.3.1.1 Super Chief
6.3.1.2 Castoro 12
6.3.2 High-Spec Barges and Semisubmersibles
6.3.2.1 Derrick Barge 27
6.3.2.2 Castoro Sei
6.3.3 High-Spec Vessels
6.3.3.1 North Ocean 105
6.3.3.2 Deep Blue
6.3.4 Ultrahigh-Spec Vessels
6.3.4.1 CastorOne
6.3.4.2 Solitaire
6.3.4.3 Pioneering Spirit
6.4 Vessel PRICE
6.4.1 Cost Components
6.4.2 Examples
References
7 Pipelay Contractors and Business Profiles
7.1 Pipelay Contractors
7.1.1 Identification
7.1.2 Companies
7.1.3 Company Objectives
7.1.4 Ownership
7.2 Business Profile
7.2.1 Business Segments
7.2.2 Fleet Composition
7.2.3 Fleet Capacity and Utilization
7.2.4 Geographic Diversity
7.2.5 Integration
7.2.6 Diversification
7.2.7 Revenue
7.2.8 Market Capitalization
7.2.9 Market Position
7.2.10 Market Structure
7.3 EPCI Contractors
7.3.1 Backlog
7.3.2 Contract Type
7.3.3 Contracting Strategy
References
8 Business Strategies and Risk Factors
8.1 Business Model
8.1.1 Cash Flows
8.1.2 Operations
8.1.3 Business Risk
8.2 Business Strategies
8.2.1 Integration
8.2.2 Growth Paths
8.2.3 Vessel Acquisitions
8.2.4 Vessel Sales
8.2.5 Alliances and Partnerships
8.2.6 Joint Ventures
8.2.7 Mergers and Acquisitions
8.3 Risk Factors
8.3.1 Factors Related to Business Operations
8.3.1.1 Oil and gas prices
8.3.1.2 Prospectivity
8.3.1.3 Weather
8.3.1.4 Capital intensity
8.3.1.5 New business lines
8.3.1.6 Joint ventures
8.3.1.7 International operations
8.3.1.8 Customer base
8.3.1.9 Marine operations
8.3.1.10 Regional development
8.3.1.11 Consolidation
8.3.1.12 Competition
8.3.1.13 New entrants
8.3.1.14 Vessel construction and upgrades
8.3.1.15 Overcapacity
8.3.1.16 Acquisition risks
8.3.1.17 Restricted markets
8.3.1.18 Contracting
8.3.1.19 Unconventional production
8.3.2 Factors Related to Financial Conditions
8.3.2.1 Reduced lending
8.3.2.2 Debt and funded debt levels
8.3.2.3 Letter of credit capacity
8.3.2.4 Foreign exchange risk
8.3.2.5 Counterparty risk
8.4 Corporate Snapshots
8.4.1 Public Firms
8.4.1.1 DOF Group
8.4.1.2 McDermott International
8.4.1.3 Saipem
8.4.1.4 Sapura Energy Berhad
8.4.1.5 Solstad Rederi
8.4.1.6 Subsea 7
8.4.1.7 Swiber Holdings
8.4.1.8 TechnipFMC
8.4.2 Private Firms
8.4.2.1 Allseas Group
8.4.2.2 Bisso Marine
8.4.2.3 Grup Servici Petroliere
8.4.2.4 Heerema Marine Contractors
8.4.2.5 Morrison, Oceanic Marine Contractors, Sea Trucks, Telford Offshore, Van Oord
8.4.3 State-Owned Firms
8.4.4 RECENT Departures
References
Part 3: Gulf of Mexico Construction and Decommissioning Costs
9 Offshore Pipeline Construction Cost Estimation
9.1 Cost Categories
9.1.1 Material
9.1.2 Construction
9.1.3 Engineering and Inspection
9.2 Cost Components
9.2.1 Material
9.2.1.1 Pipeline
9.2.1.2 Weight coating
9.2.1.3 Corrosion coating
9.2.1.4 Cathodic protection
9.2.1.5 Other equipment
9.2.2 Construction
9.2.2.1 Contract terms
9.2.2.2 Vessel day rates
9.2.2.3 Mobilization and demobilization
9.2.2.4 Transition zones
9.2.2.5 Lay method and rate
9.2.2.6 Burial
9.2.2.7 Pipeline crossings
9.2.2.8 Field joint coating
9.2.2.9 Riser and tie-in work
9.2.2.10 Survey
9.2.2.11 Commissioning and hydrotesting
9.2.3 Engineering and Inspection
9.2.3.1 Project management and engineering
9.2.3.2 Inspection
9.2.3.3 Repair
9.3 Construction Cost Estimation Examples
9.3.1 Nautilus
9.3.2 Discovery
References
10 Gulf of Mexico Pipeline Construction Cost
10.1 Data Sources
10.1.1 FERC Pipelines
10.1.2 Industry Publications
10.1.3 Press Releases
10.1.4 Data Quality and project scope
10.2 Data Processing
10.2.1 Categorization
10.2.2 Unit Cost
10.2.3 Inflation Adjustment
10.3 FERC Cost Evaluation
10.3.1 Data Source
10.3.2 Normalized Costs
10.3.3 Labor and Contract Services
10.3.4 Materials
10.3.5 Engineering
10.3.6 Time Trends
10.3.7 Estimated Versus Actual Costs
10.4 Industry Cost Evaluation
10.4.1 OTC/SPE Data
10.4.2 Press Release Data
10.4.3 Comparison
10.5 Limitations
References
11 Decommissioning Workflows and Cost Estimation
11.1 General Considerations
11.2 Onshore and Offshore Decommissioning Workflows
11.3 Cleaning
11.4 Cutting
11.5 Removal and Recovery
11.6 Disposal
11.7 Cost Factors
11.7.1 Project
11.7.2 Time
11.7.3 Location
11.8 Decommissioning Cost Estimation Examples
11.8.1 Shallow-Water Platform to Subsea Assembly
11.8.2 Shallow-Water Platform to Subsea Assembly
11.8.3 Shallow-Water Platform to Onshore Facility
11.8.4 Damaged Platform to Subsea Assembly
References
12 GULF OF MEXICO PIPELINE Decommissioning Cost
12.1 Data Source
12.1.1 Description
12.1.2 Exclusions
12.1.3 Normalization
12.2 Expectations
12.3 Cost Evaluation
12.4 Limitations
12.5 Deepwater Decommissioning Cost Algorithms
12.5.1 Requirements
12.5.2 Pipeline Decommissioning
12.5.2.1 Assumptions
12.5.2.2 Regression models
12.5.3 Umbilical, Flowline, and Riser Decommissioning
12.5.3.1 Assumptions
12.5.3.2 Regression model
12.5.4 Decommissioning Exposure
12.6 Estimation Uncertainty
References
Part 4: Networks, Statistics, and Correlations
13 Gulf of Mexico Pipeline Network Evolution
13.1 Description
13.2 Pipeline Network Stages
13.3 Pipeline Corridor Examples
13.4 Pipeline Network Characteristics
13.4.1 Structured Networks
13.4.2 Scale-Free Networks
13.4.3 Segmented Networks
13.5 Energy Requirements
References
14 Infrastructure Characteristics and Relationships
14.1 Pipeline Characteristics
14.1.1 Causal Relationships
14.1.2 Dimensional Variables
14.1.3 Complex Dependencies
14.1.4 Ownership Issues
14.1.5 Lumpy Volatile Data
14.2 Infrastructure Relations
14.2.1 Phenomenological Approach
14.2.2 Geometric Representation
14.2.3 Structure and Well Configurations
14.2.4 Deepwater Structures and Subsea Well Configurations
14.3 Data Categorization
14.3.1 Pipeline Attributes
14.3.2 Production Group
14.3.3 Water Depth Classes
14.3.4 Status Group
14.3.5 Data Limitations
References
15 Gulf of Mexico Pipeline Activity Statistics and Trends
15.1 Aggregate Statistics
15.1.1 Cumulative Installed
15.1.2 Cumulative Decommissioned
15.1.3 Active
15.1.4 Out-of-Service
15.2 Trends
15.2.1 Installed
15.2.2 Decommissioned
15.2.3 Active and Out-of-Service
References
16 Gulf of Mexico Pipeline Activity Correlations
16.1 Shallow Water Installation
16.1.1 Bulk Pipeline Versus Simple Structures
16.1.2 Export Pipeline and Fixed Platforms
16.2 Deepwater Installation
16.2.1 Bulk Pipeline Versus Subsea Wells
16.2.2 Bulk Pipeline Versus Subsea Wells and Deepwater Structures
16.2.3 Export Pipeline Versus Deepwater Structures
16.2.4 Export line Versus Deepwater Structures, Time Normalization
16.3 Shallow Water Decommissioning
16.3.1 Bulk Pipeline Versus Simple Structures
16.3.2 Export Pipeline Versus Fixed Platforms
16.4 Limitations
Reference
Appendix A Offshore Development Records CIRCA 2020
A.1 Deepest Water Depth
A.2 Deepest and Longest Wells
A.3 Largest Pipeline Networks
A.4 Northernmost and Southernmost Fields
A.5 Deepest Pipelines
A.6 Longest Pipelines
A.7 Longest and Deepest Tiebacks
A.8 Most Complex and Difficult Wells
A.9 Most Difficult Pipelines
A.10 Most Expensive Projects
A.11 Largest Production Vessel
A.12 Largest OFFSHORE FIELDS
A.13 Largest Offshore Producing Countries
References
Appendix B Worked Examples
B.1 Pipeline Routes
B.2 Mileage Bounds by Block Counts
B.3 Circuit Factor
B.4 Risers
B.5 Field Architecture
Appendix C Outer Continental Shelf Pipeline RegulatIONS and Tariff Rates
C.1 Economic Fair Play
C.1.1 Natural Gas
C.1.1.1 Gathering exception tests
C.1.1.2 Behind-the-plant test
C.1.1.3 Central point test
C.1.1.4 Primary function test
C.1.1.5 Modified primary function test
C.1.2 Oil
C.1.2.1 Interstate Commerce Act
C.1.2.2 Open Access and the Outer Continental Shelf Lands Act of 1953
C.1.2.3 Energy Policy Act of 1992
C.2 Pipeline Safety
C.2.1 Design and Construction
C.2.2 Outer Continental Shelf Regulatory Framework
C.2.3 Bond Requirements
C.2.4 Other Outer Continental Shelf Authorities
C.3 Pipeline Abandonment
C.3.1 Federal Energy Regulatory Commission Authority
C.3.1.1 Oil
C.3.1.2 Natural gas
C.3.1.3 Public Convenience and Necessity
C.3.2 BSEE/BOEM Authority
C.3.2.1 Outer Continental Shelf Decommissioning Regulations
C.3.2.2 Significant Sediment Resources Policy
C.4 Transportation and Gathering
C.4.1 Gathering and Transportation Fees
C.4.2 Tariff Rates
C.4.3 Cost of Service
C.4.4 Rate Schedules
References
Appendix D DEEPWATER Gulf of Mexico Pipeline MAPS
Index
Back Cover

Citation preview

The Offshore Pipeline Construction Industry Activity Modeling and Cost Estimation in the U.S. Gulf of Mexico

The Offshore Pipeline Construction Industry Activity Modeling and Cost Estimation in the U.S. Gulf of Mexico

Mark J. Kaiser Center for Energy Studies Louisiana State University Baton Rouge, LA, United States

Gulf Professional Publishing is an imprint of Elsevier 50 Hampshire Street, 5th Floor, Cambridge, MA 02139, United States The Boulevard, Langford Lane, Kidlington, Oxford, OX5 1GB, United Kingdom Copyright © 2020 Elsevier Inc. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the publisher. Details on how to seek permission, further information about the Publisher’s permissions policies and our arrangements with organizations such as the Copyright Clearance Center and the Copyright Licensing Agency, can be found at our website: www.elsevier.com/permissions. This book and the individual contributions contained in it are protected under copyright by the Publisher (other than as may be noted herein). Notices Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary. Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility. To the fullest extent of the law, neither the Publisher nor the authors, contributors, or editors, assume any liability for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions, or ideas contained in the material herein. British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress ISBN: 978-0-12-820288-3 For Information on all Gulf Professional Publishing publications visit our website at https://www.elsevier.com/books-and-journals

Publisher: Joe Hayton Senior Acquisitions Editor: Katie Hammon Editorial Project Manager: Aleksandra Packowska Production Project Manager: Sruthi Satheesh Cover Designer: Mark Roger Typeset by MPS Limited, Chennai, India

Contents List of Boxes......................................................................................................................................... ix Executive Summary.............................................................................................................................. xi Abbreviations and Acronyms ............................................................................................................ xvii Acknowledgments .............................................................................................................................. xxi

PART 1 GULF OF MEXICO BACKGROUND CHAPTER 1 Offshore Overview ................................................................................. 3 1.1 1.2 1.3 1.4

Gulf of Mexico........................................................................................................... 3 Regulatory Structure .................................................................................................. 9 Production System Components .............................................................................. 11 Design Process ......................................................................................................... 34 References................................................................................................................. 38

CHAPTER 2 Flow Assurance Issues ....................................................................... 39 2.1 2.2 2.3 2.4

Flow Patterns............................................................................................................ 39 Design Issues............................................................................................................ 41 Hydrocarbon Components........................................................................................ 44 Hydrate Management Techniques ........................................................................... 57 References................................................................................................................. 59

CHAPTER 3 Field Development Strategies............................................................. 61 3.1 3.2 3.3 3.4 3.5

Systems Perspective ................................................................................................. 61 Conceptual Development ......................................................................................... 64 Development Strategies............................................................................................ 67 Hub Classification .................................................................................................... 82 Hub Platforms .......................................................................................................... 85 References................................................................................................................. 91

CHAPTER 4 Deepwater Hazards and Chemosynthetic Communities .................... 93 4.1 Manmade Hazards.................................................................................................... 93 4.2 Geohazards ............................................................................................................... 93 4.3 Chemosynthetic Communities ............................................................................... 106 References............................................................................................................... 108

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PART 2 OFFSHORE CONSTRUCTION SERVICE INDUSTRY CHAPTER 5 Pipeline Installation and Vessel Specifications ............................. 113 5.1 Installation Techniques .......................................................................................... 113 5.2 Vessel Specifications.............................................................................................. 125 5.3 Classification and Registration .............................................................................. 136 References............................................................................................................... 139

CHAPTER 6 World Pipelay Fleet Circa 2020 ...................................................... 141 6.1 6.2 6.3 6.4

Vessel Classification .............................................................................................. 141 World Pipelay Fleet ............................................................................................... 143 Pipelay Vessels by Class........................................................................................ 149 Vessel Price ............................................................................................................ 156 References............................................................................................................... 159

CHAPTER 7 Pipelay Contractors and Business Profiles ..................................... 161 7.1 Pipelay Contractors ................................................................................................ 161 7.2 Business Profile...................................................................................................... 165 7.3 EPCI Contractors.................................................................................................... 174 References............................................................................................................... 182

CHAPTER 8 Business Strategies and Risk Factors ............................................. 185 8.1 8.2 8.3 8.4

Business Model ...................................................................................................... 185 Business Strategies ................................................................................................. 189 Risk Factors............................................................................................................ 194 Corporate Snapshots............................................................................................... 202 References............................................................................................................... 206

PART 3 GULF OF MEXICO CONSTRUCTION AND DECOMMISSIONING COSTS CHAPTER 9 Offshore Pipeline Construction Cost Estimation.............................. 209 9.1 Cost Categories ...................................................................................................... 209 9.2 Cost Components ................................................................................................... 213 9.3 Construction Cost Estimation Examples ............................................................... 219 References............................................................................................................... 227

Contents

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CHAPTER 10 Gulf of Mexico Pipeline Construction Cost...................................... 229 10.1 10.2 10.3 10.4 10.5

Data Sources........................................................................................................... 229 Data Processing ...................................................................................................... 233 FERC Cost Evaluation ........................................................................................... 236 Industry Cost Evaluation........................................................................................ 245 Limitations.............................................................................................................. 248 References............................................................................................................... 253

CHAPTER 11 Decommissioning Workflows and Cost Estimation ......................... 255 11.1 11.2 11.3 11.4 11.5 11.6 11.7 11.8

General Considerations .......................................................................................... 255 Onshore and Offshore Decommissioning Workflows........................................... 257 Cleaning.................................................................................................................. 258 Cutting .................................................................................................................... 264 Removal and Recovery .......................................................................................... 264 Disposal .................................................................................................................. 265 Cost Factors............................................................................................................ 266 Decommissioning Cost Estimation Examples....................................................... 269 References............................................................................................................... 275

CHAPTER 12 Gulf of Mexico Pipeline Decommissioning Cost.............................. 277 12.1 12.2 12.3 12.4 12.5 12.6

Data Source ............................................................................................................ 277 Expectations ........................................................................................................... 279 Cost Evaluation ...................................................................................................... 280 Limitations.............................................................................................................. 280 Deepwater Decommissioning Cost Algorithms .................................................... 283 Estimation Uncertainty........................................................................................... 286 References............................................................................................................... 289

PART 4 NETWORKS, STATISTICS, AND CORRELATIONS CHAPTER 13 Gulf of Mexico Pipeline Network Evolution ..................................... 293 13.1 13.2 13.3 13.4 13.5

Description ............................................................................................................. 293 Pipeline Network Stages ........................................................................................ 298 Pipeline Corridor Examples ................................................................................... 302 Pipeline Network Characteristics........................................................................... 305 Energy Requirements ............................................................................................. 311 References............................................................................................................... 314

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CHAPTER 14 Infrastructure Characteristics and Relationships............................ 315 14.1 Pipeline Characteristics .......................................................................................... 315 14.2 Infrastructure Relations .......................................................................................... 317 14.3 Data Categorization................................................................................................ 320 References............................................................................................................... 327

CHAPTER 15 Gulf of Mexico Pipeline Activity Statistics and Trends .................. 329 15.1 Aggregate Statistics................................................................................................ 329 15.2 Trends ..................................................................................................................... 335 References............................................................................................................... 343

CHAPTER 16 Gulf of Mexico Pipeline Activity Correlations ................................. 345 16.1 16.2 16.3 16.4

Shallow Water Installation..................................................................................... 345 Deepwater Installation............................................................................................ 348 Shallow Water Decommissioning.......................................................................... 353 Limitations.............................................................................................................. 354 Reference ................................................................................................................ 357

APPENDIX A Offshore Development Records Circa 2020..................................... 359 APPENDIX B Worked Examples ............................................................................. 387 APPENDIX C Outer Continental Shelf Pipeline Regulations and Tariff Rates...... 409 APPENDIX D Deepwater Gulf of Mexico Pipeline Maps ....................................... 437 Index .................................................................................................................................................. 469

List of Boxes Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box Box

1.1 1.2 1.3 1.4 2.1 2.2 2.3 2.4 2.5 3.1 3.2 4.1 4.2 4.3 5.1 5.2 5.3 6.1 6.2 7.1 7.2 8.1 8.2 8.3 9.1 9.2 10.1 10.2 11.1 11.2 11.3 12.1 12.2 13.1 13.2 13.3 14.1 15.1 16.1 16.2

Lease Block Sizes and Boustrophedonic Numbering Cartoons and Their Limitations Flexible Pipeline Configuration Pipeline Strength and Modulus of Elasticity Hammerschmidt Equation Flowline Fishing and Cleanout Cost at Nansen Pigging at Azeri-Chirag-Gunashli (A Pig A Day Helps. . .) Wax Deposition Model Asphaltene Precipitation and de Boer Plots Finding the Best Location for the Na Kika Facility Three Pipeline Rules of Thumb Offshore Pipeline Route Selection Two Mooring Line Examples Azeri-Chirag-Gunashli Geohazards Root, Hot, Filler, and Cap Passes YouTube Videos Worth Watching! Pipe Fabrication Pioneering Spirit’s Debut, A Class Apart Six Degrees of Vessel Motions Global Offshore Capital Spending Snapshots Crude Oil Supply and Demand Amazing Grace on the Way? Gulf of Mexico Spoolbase Facilities A Few Words on Oil Markets and Crude Prices Castoro Sei Workflows Gas—Liquid Flow Regime Classification Norway’s Offshore Oil and Gas Pipeline Cost Gulf of Mexico Pipeline Project Press Releases Life Cycle Issues and End-of-Life Indicators Pig Type and Function Aggressive Pigs, Pig Trash, and Stuck Pigs Hypothetical Pipeline Removal Cost Deepwater Gulf of Mexico Decommissioning Market Size Estimates Deepwater Gulf of Mexico Pipeline Architecture Walking Energy Expenditure Calculation Oil Pipeline Energy Requirement Calculation Manufacturing Flexible Pipe More YouTube Videos Worth Watching! Pipeline Mileage Forecasting in Future Lease Sales How Many Barrels of Crude Oil Weigh a Metric Ton?

9 24 30 37 47 48 50 52 54 83 90 94 100 104 119 123 137 156 158 176 181 188 190 196 210 225 231 251 256 260 261 282 286 294 313 313 325 342 355 357

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List of Boxes

Box Box Box Box Box Box Box

A.1 A.2 A.3 A.3 C.1 C.2 C.3

Notable Arctic Offshore Developments Technical Challenges in Drilling Long Deep Wells Kashagan Starts to Deliver The Gorgon LNG Project Public Convenience and Necessity Triggers Heating Value Application Eugene Island Pipeline System Quality Bank Policy

367 372 378 382 416 420 432

Executive Summary Oil and gas production occurs offshore every continent except Antarctica, from the southernmost Vega Pleyade field at Tierra del Fuego, Argentina, to the northernmost Snohvit and Goliat fields offshore Norway in the Barents Sea. In 1978 operators first started producing in 1000 ft water depth and by 2020 wells were drilled in waters deeper than 11,000 ft. For the past twenty years, offshore production has contributed annually about one-third of the world’s oil production and a quarter of its gas supply. Offshore fields have been developed in many of the harshest and most difficult environments worldwide, and new technologies continue to unlock resources which were once uneconomical, or constrained by technical challenges, into viable projects. The development of offshore fields is a major undertaking and involves numerous technical requirements. The design, construction, and operation of offshore fields must meet stringent standards to ensure structural integrity, work force safety, and protection of the environment. Pipelines are the least expensive way of moving large volumes of liquids and gas, and are by far the safest, most reliable, and most environmentally friendly way to transport hydrocarbons. In the federal waters of the U.S. Gulf of Mexico, more pipeline has been installed than any other offshore region, and would circle the earth twice. The U.K. and Norwegian sectors of the North Sea also utilize a large oil and gas pipeline transportation network. The purpose of this book is to describe the offshore pipeline construction industry and to quantify the pipeline networks, construction and decommissioning cost, and activity trends in the U.S. Gulf of Mexico. The text is global in perspective, but much of the focus is on the Gulf of Mexico because of its competitive markets and high-quality publicly available data sources. Only a few engineering applications are touched upon in this discourse, however, and the reader seeking additional information on the technical aspects of pipeline design and construction are directed to the textbooks cited herein. This is a research monograph, meaning it is a focused and in-depth treatment of a particular topic, in this case the business, cost, and market structure of the offshore pipeline construction industry. One of the secondary purposes of this work is to document the key information required to understand the speed of change and relative importance of factors impacting the offshore pipeline sector.

ORGANIZATION This book is organized into four parts and each part consists of four chapters. Several boxes are sprinkled throughout each chapter to broaden the scope and context of discussion, and to highlight topics of wider significance. In Part 1, background information on offshore production systems, flow assurance, field development, and deepwater geohazards introduce terminology and engineering requirements for pipeline systems. In Part 2, the global fleet of pipelay vessels and contractors c.2020 are described, including their business models and industry risk factors. In Part 3, pipeline construction and

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Executive Summary

decommissioning cost estimation methods and Gulf of Mexico statistics and algorithms are presented, followed in Part 4 with an empirical evaluation of Gulf of Mexico pipeline networks, activity data, and correlations. Four appendices collect ancillary information on offshore development records c.2020 (Appendix A), worked examples (Appendix B), the Outer Continental Shelf regulatory framework and pipeline tariff rates (Appendix C), and pipeline maps for the deepwater fields discussed in the text (Appendix D).

OUTLINE Part 1. Gulf of Mexico Background Chapter 1. Offshore Overview Chapter 2. Flow Assurance Issues Chapter 3. Field Development Strategies Chapter 4. Deepwater Hazards and Chemosynthetic Communities Part 2. Offshore Construction Service Industry Chapter 5. Pipeline Installation and Vessel Specifications Chapter 6. World Pipelay Fleet Circa 2020 Chapter 7. Pipelay Contractors and Business Profiles Chapter 8. Business Strategies and Risk Factors Part 3. Gulf of Mexico Construction and Decommissioning Costs Chapter 9. Offshore Pipeline Construction Cost Estimation Chapter 10. Gulf of Mexico Pipeline Construction Cost Chapter 11. Decommissioning Workflows and Cost Estimation Chapter 12. Gulf of Mexico Pipeline Decommissioning Cost Part 4. Networks, Statistics, and Correlations Chapter 13. Gulf of Mexico Pipeline Network Evolution Chapter 14. Infrastructure Characteristics and Relationships Chapter 15. Gulf of Mexico Pipeline Activity Statistics and Trends Chapter 16. Gulf of Mexico Pipeline Activity Correlations Appendix Appendix Appendix Appendix

A. Offshore Development Records Circa 2020 B. Worked Examples C. Outer Continental Shelf Pipeline Regulations and Tariff Rates D. Deepwater Gulf of Mexico Pipeline Maps

HIGHLIGHTS In Part 1, background information on Gulf of Mexico production systems, flow assurance, field development strategies, and deepwater geohazards are described. The Gulf of Mexico setting and its main features are introduced in Chapter 1, along with the regulatory agencies, offshore components, and pipeline design considerations. National governments exercise control over petroleum resources

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by regulating operations related to exploration, production, design, construction, safety, and environmental protection, while companies allocate capital and create development plans according to expected returns, risk, strategic objectives, and other factors. In Chapter 2, the three main threats to deepwater flow assurance—wax, hydrates, and asphaltenes—are reviewed. In shallow water, flow assurance issues are generally not an issue because the shallower water depths and lower hydrostatic pressures are less conducive to flowline problems, but in deepwater, flow assurance is a central design issue throughout the life-cycle of the asset. Hydrate problems are nearly universal in deepwater subsea developments, while the extent of wax and asphaltene varies widely between projects. Numerous tradeoffs arise in subsea design as engineers attempt to mitigate and reduce the problems that may arise. In Chapter 3, offshore development strategies and operator preferences are discussed with emphasis on pipeline requirements. Projects highlight design features unique to each development and execution sequence. The purpose of every offshore pipeline is to transport fluid from one point to another, but differences in field location, reservoir characteristics, fluid composition, water depth, seafloor topography, ownership, and other factors means that design and route selection will exhibit complex dependencies. The control of project cost and schedule, and management of risk, are typically major challenges associated with deepwater developments, and hub platforms are arguably the most important structure class in the region to maintain commercial operations. In Chapter 4, deepwater geohazards and chemosynthetic communities in the Gulf of Mexico are examined. Unlike the shallow water, where the seafloor is flat and featureless and pipelines can be laid in straight lines to their destination, difficult topologies, steep gradients, and geohazards makes deepwater route selection complex and time consuming. In deepwater, geohazards are a major issue because the nature, extent, and effects of geohazards are not well understood nor easily quantified. A good strategy in routing is to avoid hazards but this is not always possible, and with every new restriction or avoidance area added, pipeline length increases, which increases development cost. In Part 2, the global offshore construction service industry and pipelay contractors are reviewed, including their business models and risk factors. Pipelay vessels range in complexity from traditional moored barges that lay pipe in shallow water to dynamically positioned ship-shaped vessels which can lay large diameter pipe in ultradeepwater and perform multiple activities. The industry has seen varying degrees of consolidation over the years and the largest contractors today are vertically integrated and diversified outside the upstream oil and gas sector. In Chapter 5, pipeline installation techniques are reviewed, and pipelay vessel characteristics and capabilities are summarized. In Chapter 6, the global pipelay vessel fleet c.2020 is classified and examples of each class are provided. The chapter concludes with a survey of pipelay vessel market prices. In Chapters 7 and 8, the contractors, business profiles, and risk factors encountered in the offshore pipeline construction market are examined. Large firms typically operate diverse vessel fleets in multiple regions around the world, with smaller firms operating in fewer regions with fewer vessels. During prolonged periods of low oil prices, demand for services are reduced, causing contractors to reorganize operations to maintain a competitive position, to form alliances and partnerships in search of opportunities, and to sell, stack, and dismantle less competitive vessels to reduce cost. One or more of these strategies may be pursued sequentially or simultaneously. A review of corporate strategies reveals the depth and breadth of the sector; operational and financial factors highlight the business risks.

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In Part 3, pipeline construction and decommissioning workflows, cost estimation procedures, and Gulf of Mexico cost statistics and algorithms are examined. Work decomposition methods are by far the most commonly applied technique in engineering cost estimation, and in Chapter 9, work decomposition methods are applied in pipeline construction cost estimation. Two projects are used to compare estimated and final construction cost. In Chapter 10, pipeline construction cost statistics in the Gulf of Mexico are evaluated. Although the Gulf of Mexico oil and gas industry is one of the most transparent markets in the world, reliable and representative cost data are still difficult to obtain across most sectors, and pipelines are no exception. Using data from FERC, industry publications and press releases, pipeline construction cost are assembled from 1980 to 2019. The average inflation-adjusted cost to construct and install FERC pipelines is estimated to be $3.3 million per mile, and industry publications yield an average pipeline cost of $3.1 million per mile. Data limitations are described. In Chapter 11, the workflows for pipeline decommissioning are reviewed. Historically, the vast majority of decommissioned pipeline in the Gulf of Mexico has been abandoned-in-place, which essentially involves cleaning the line by pigging or flushing, cutting the pipeline endpoints, and then plugging and burying each endpoint below the seabed or covering with a concrete mattress. The chapter concludes with a discussion of pipeline decommissioning cost factors and examples of decommissioning cost estimation. Pipelines under FERC regulation require disclosure on decommissioning cost and provide a unique data source for evaluation. In Chapter 12, decommissioning cost estimates for FERC gas export pipelines in the shallow water Gulf of Mexico between 1995 and 2019 are evaluated. The average inflation-adjusted pipeline decommissioning cost was $301,000 per mile and $47 per cubic foot, about one-tenth the cost of pipeline construction. Hurricane damaged and leaking pipelines are about three to four times more expensive to decommission than undamaged and nonleaking lines. Decommissioning cost algorithms and examples for deepwater Gulf of Mexico pipelines, risers, and umbilicals conclude the chapter. In Part 4, Gulf of Mexico pipeline activity data are reviewed and correlations developed to explain the trends observed. Pipeline infrastructure is best visualized using geographic information systems and maps, but spatial representations provide little insight into how attributes relate and interact over time. Quantification arises from the need to understand system relationships for forecasting and related purposes. As a prelude to the empirical analytics, the evolution of the Gulf of Mexico pipeline network and its structural characteristics are highlighted in Chapter 13. The Gulf of Mexico pipeline network is organized around critical nodes containing a high concentration of linkages or high-volume throughputs. A description of the scale-free structure of pipeline networks and its relation to other forms of transport concludes the chapter. In Chapter 14, geometric representations of offshore infrastructure are used to guide model development. Pipeline activity is causal in the sense that pipeline is installed to serve field development and is based directly on field architecture. To reliably quantify infrastructure relations system attributes need to be understood and properly selected. In Chapter 15, Gulf of Mexico pipelines are grouped into oil, gas, bulk oil, bulk gas, service and umbilical categories for shallow and deepwater installation and decommissioning activity. In Chapter 16, Gulf of Mexico pipeline activity is correlated with field attributes such as wells drilled and structures decommissioned, and ends with a critical discussion of the limitations of modeling.

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Four appendices assemble additional perspectives useful in pipeline studies. In Appendix A, a survey of drilling and development records c.2020 highlights industry capabilities and trends. In Appendix B, worked examples introduce basic pipeline design and development concepts for readers new to the field. Appendix C provides a quasi-legal review of the differences between oil and gas pipeline regulation in U.S. federal waters and examples of pipeline tariff rates and how they are determined. Pipeline system maps for all deepwater Gulf of Mexico fields described in the monograph are presented in Appendix D.

DATA SOURCES Structures were identified using the BOEM Platform Masters and Platform Structures databases (BOEM, 2020a,b). Pipeline data were evaluated from the BOEM Pipeline database (BOEM, 2020c). Wellbore data were assembled from the BOEM Well database (BOEM, 2020d). Pipeline construction cost data were collected from FERC public dockets and industry trade publications, including Oil and Gas Journal, Offshore Technology Conference and Society of Petroleum Engineers meetings, and press releases. Annual reports, financial statements, company websites, and Offshore Magazine were the primary data sources for company fleets, business profiles, and financial records. Owing to the breadth of the topics presented and the time required for evaluation, a variety of periods manifest and are encountered throughout the monograph. Data from operator activity and company financial statements (Parts 1, 2) were evaluated in August 2019. Pipeline construction and decommissioning cost data (Part 3) were evaluated through December 2019. Data for the installation and decommissioning trends and correlations (Part 4) were evaluated from February to April 2017 and updated selectively for 2019. World offshore records are circa 2019 20. Pipeline system maps depicted in the text were created in January 2020.

UNITS Both English and SI units are used throughout the text but usually not simultaneously. Conversion between units is performed using Table E.1. Table E.1 SI Metric Conversion Factors. ac 3 4.047E-01 5 ha cf/bbl 3 1.801E-01 5 m3/m3 141.5/(131.5 1  API) 5 g/cm3 bbl 3 1.589E-01 5 m3 ft 3 3.048E-01 5 m ft3 3 2.831E-02 5 m3 ( F 2 32)/1.8 5  C mi 3 1.609 5 km psi 3 6.894 5 kPa

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REFERENCES U.S. Department of the Interior. Bureau of Ocean Energy Management, 2020a. Data Center: Platform Masters. Available from: ,https://www.data.boem.gov/Main/HtmlPage.aspx?page 5 platformMasters.. U.S. Department of the Interior. Bureau of Ocean Energy Management, 2020b. Data Center: Platform Structures. Available from: ,https://www.data.boem.gov/Main/HtmlPage.aspx?page 5 platformStructures.. U.S. Department of the Interior. Bureau of Ocean Energy Management, 2020c. Data Center: Pipeline Information. Available from: ,https://www.data.boem.gov/Main/Pipeline.aspx.. U.S. Department of the Interior. Bureau of Ocean Energy and Management. 2020d. Data Center: Well Information. Available from: ,https://www.data.boem.gov/Main/Well.aspx..

Mark J. Kaiser Baton Rouge, Louisiana April 2020

Abbreviations and Acronyms AFUDC AHT AHTS AIME APE  API API API-RP ASTM BLS BOEM BSEE CFR CGOR CGR CSV C/WP DOI DOT DP DSAW DVA DWS EPC EPCI E&P ERD ERW EWS FBE FERC FP FPSO FPU FSHR G&A GOR HD HD/TVD HSBS HSV IADC ICA IMR

accumulated funds used during construction anchor handling tug anchor handling towing supply American Institute of Mining, Metallurgical, and Petroleum Engineers asphaltenes precipitation envelope API gravity American Petroleum Institute American Petroleum Institute—Recommended Practices American Society for Testing and Materials Bureau of Labor Statistics Bureau of Ocean Energy Management Bureau of Safety and Environmental Enforcement Code of Federal Regulations cumulative gas-oil ratio condensate-gas ratio construction service vessel caisson or well protector Department of Interior Department of Transportation dynamic positioning double submerged arc welding direct vertical access deepwater structure engineering procurement and construction engineering, procurement, construction, and installation exploration and production extended reach directional electrical resistance welding number of effective welding stations fusion bonded epoxy Federal Energy Regulatory Commission fixed platform floating production storage and offloading floating production unit free standing hybrid riser general and administrative expenses gas-oil ratio horizontal departure horizontal displacement to true vertical depth ratio high-spec barge and semisubmersible high-spec vessel International Association of Drilling Contractors Interstate Commerce Act inspection, maintenance, repair

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ISO ISOPE LDHI LNG LOA LPG L-SAW LSB MAOP MD MEG MeOH MMS MODU MPSV NACE NDE NGA NGPA NTL NWS OCS OCSLA OD OGJ OMC OTC PE PIP PLEM PLET PSV PVT ROV ROW RTA RUE SARA SAW SCR SEMI SG SN SPAR SPE S-SAW SURF TFL

Abbreviations and Acronyms

International Standards Organization International Society of Offshore and Polar Engineers low dose hydrate inhibitor liquefied natural gas length overall liquefied petroleum gas longitudinal submerged arc welding low-spec barge minimum acceptable operating pressure measured depth monoethylene glycol methanol Minerals Management Service mobile offshore drilling unit multipurpose support vessel National Association of Corrosion Engineers nondestructive evaluation Natural Gas Act of 1938 Natural Gas Policy Act of 1978 Notice to lessee number of welding stations Outer Continental Shelf Outer Continental Shelf Lands Act of 1953 outer diameter Oil and Gas Journal Offshore Mediterranean Conference Offshore Technology Conference polyethylene pipe-in-pipe pipeline end manifold pipeline end termination platform supply vessel pressure volume temperature remotely operated vehicle right of way resin-to-asphaltene ratio right of use and easement saturates, aromatics, resins, and asphaltenes submerged arc welding steel catenary riser semisubmersible specific gravity schedule number surface piercing articulating riser Society of Petroleum Engineers spiral submerged arc welding subsea equipment, umbilicals, risers, flowlines through-flowline

Abbreviations and Acronyms

TLP TTR TVD TVDSS UHSV WAT

tension leg platform top tensioned riser true vertical depth total vertical depth subsea ultrahigh-spec vessel wax appearance temperature

UNITS ac bbl boe boepd bopd bpd bwpd B Btu cf cfpd Dth DWT ft gal ha kg kip kJ ksi lb L m mg mi mt M MM mtpa nm psi t th T

acre barrel barrel oil equivalent barrels oil equivalent per day barrels oil per day barrels per day barrels water per day billion British thermal unit cubic feet cubic feet per day decatherm dead weight ton foot gallon hectare kilogram thousand pounds kilojoule thousand pounds per square inch pound liter meter milligram mile metric tonne thousand million million tonne per annum nautical mile pounds per square inch tons therm trillion

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Acknowledgments This work was prepared on behalf of the U.S. Department of the Interior, Bureau of Ocean Energy Management and has not been technically reviewed by the BOEM. The opinions, findings, conclusion, or recommendations expressed in this book are those of the author, and do not necessarily reflect the views of the BOEM. Funding for this research was provided in part through the U.S. Department of the Interior, BOEM, under BOEM Contract M14AC00024.

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OFFSHORE OVERVIEW

1

Oil and gas production occurs offshore every continent except Antarctica, from the southernmost gas condensate field Vega Pleyade located offshore Tierra del Fuego, Argentina, to the northernmost Snohvit and Goliat fields offshore Norway in the Barents Sea. Circa 2020, offshore production was responsible for about a third of global oil production and about a quarter of the world’s natural gas supply. The purpose of this chapter is to introduce the Gulf of Mexico setting, regulatory authorities, and production system components used in offshore oil and gas development. Pipeline classes, types, grade, composition and manufacturing techniques are highlighted. The chapter ends with a high-level summary of the pipeline design workflow.

1.1 GULF OF MEXICO 1.1.1 ORIGINS The Gulf of Mexico basin formed approximately 200 to 160 million years ago during the Mesozoic era with the breakup of Pangea and associated tectonic movements (Salvador, 1987; Snedden and Galloway, 2019). Two large carbonate platforms, the Yucatan Peninsula and Campeche Bank on the west and the Florida Platform on the east, surround the region. Both platforms support wide and shallow submerged shelves with sedimentary layers that continue several miles beneath the seafloor and are a rich source of oil and gas deposits (Fig. 1.1). The deepest portion of the Gulf of Mexico is called the Sigsbee Deep, a flat region that lies in the western portion at a depth between 12,300 and 14,400 ft. Charles Dwight Sigsbee was the commanding officer of the steamer George S. Blake which discovered the feature in 1873
75 during mapping of the basin (Fig. 1.2).

1.1.2 SHELF VERSUS SLOPE FEATURES The continental shelf is made from sediment that is collected along the coast by rivers and gravity carrying it to the oceans, and the more sediment carried to the coast, the bigger and wider the continental shelf becomes over time. Continental shelves represent a continuation of the continental landmass and extend outward to the continental slope. Worldwide, the continental shelf region varies widely from place to place, depending on whether there is an active subduction zone. Where plate boundaries coincide with the edges (margins) of the continent, shelves are narrow such as around the Pacific Ocean. Where continental margins have no active subduction zone and the oceanic crust is fused to the continental crust, sediment can collect and continental shelves are wide. The entire Atlantic Ocean is The Offshore Pipeline Construction Industry. DOI: https://doi.org/10.1016/B978-0-12-820288-3.00001-9 © 2020 Elsevier Inc. All rights reserved.

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FIGURE 1.1 Shelf, slope, and abyssal plain features of the Gulf of Mexico. From NOAA.

FIGURE 1.2 Gulf of Mexico features mapped by the steamer George S. Blake under the command of Charles Sigsbee c.1880.

1.1 GULF OF MEXICO

5

surrounded by passive margins and wide continental shelves (Garrison and Ellis, 2018). Continental shelves are part of the continental landmass during glacial periods and are inundated during interglacial periods. The Gulf of Mexico continental shelf has an average gradient of about 1 in 500 and ranges from 600 to 1000 ft water depth, while the gradient of the continental slope increases to about 1 in 20 and extends up to about 9000 ft water depth (Fig. 1.3). The seafloor of the Gulf of Mexico shelf is flat and featureless, but in deepwater is more severe and complex. In Alaminos Canyon and Perdido Canyon, for example, the presence of large bodies of salt in the sediment have deformed the seabed creating several seafloor mounds (diapers), peaks, and canyons that are clearly visible (Fig. 1.4). As the oil and gas industry has progressed from operations on the shelf onto the slope and beyond into ultradeep water, the variety and complexity of geohazard issues has grown. On the shelf, the presence of shallow gas was the main marine geohazard risk encountered, but in deeper water several new geohazard issues arise, such as shallow water flow, chemosynthetic communities, hydrates, and slope instability. The surface of the shelf is generally smooth with low relief irregularities resulting from the presence of relict stream and shoreline deposits, scarps formed by active growth faults, and mounds produced by salt and shale diapirism. On the slope and rise, seafloor topography includes areas of possible landsliding and faulting, mud seeps, undulations, and rocky outcrops. Irregular rocky seafloor with sharp relief of tens of feet, fault scarps up to 300 ft high, and areas of possible landslide

FIGURE 1.3 Bathymetry of the Northern Gulf of Mexico and Sigsbee Escarpment. From NOAA.

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FIGURE 1.4 High-resolution bathymetry map of Perdido Canyon and Alaminos Canyon. From NOAA.

contribute to the difficult conditions on the slope and pose additional challenges for infrastructure location. Rugged topography on the flank of domes suggests failures in the geologically recent past.

1.1.3 STATE VERSUS FEDERAL WATERS In the early years of offshore oil and gas production, California, Texas, Louisiana and the federal government all claimed control over lands below the low tide mark. States challenged a 1945 proclamation made by President Truman that granted authority over the subsoil of the US continental shelf to the federal government and prompted the Department of Justice to file suits against them. The legal disputes ended when the Supreme Court ruled in favor of the federal government, against California in 1947, and against Louisiana and Texas in 1950. In May 1953, Congress passed two pieces of legislation that put an end to the debate over federal and state jurisdiction. The Submerged Lands Act validated all state leases that had been awarded prior to the issuance of the Supreme Court’s decision against California, Texas, and Louisiana and assigned to the states all land within 3 nautical miles (nm) of their shores1. For Texas and the west 1 A nautical (or geographical) mile is a unit of distance based on the length of a minute of arc of a great circle of the earth, defined to be 1852 m (1.15 statute miles), or about 6076 ft. A statute mile is equal to 5280 ft. A marine league is equal to three nautical miles, or about 18,288 ft. Recall that a kilometer is defined as 1/10,000 of the distance from the North Pole to the equator via Paris.

1.1 GULF OF MEXICO

7

coast of Florida, the distance was 3 marine leagues (9 nm). The Outer Continental Shelf Lands Act (OCSLA) codified federal control of the US continental shelf and placed all offshore lands beyond the 3 nm limit under federal jurisdiction and gave the US Department of Interior the authority to issue leases for development (Vann, 2018).

1.1.4 SALT AND THE SIGSBEE ESCARPMENT Evaporite deposits play an important role in the depositional and structural history of the Gulf of Mexico, and is one of the primary reasons for its high prospectivity as a hydrocarbon basin. In the Jurassic period, several marine incursions were followed by minor uplift causing the seas to dry out and evaporite deposition to occur multiple times. Traps are created and destroyed by salt movement, and to understand the structural environment of the region salt evolution is key (Jackson and Hudec, 2017). Hydrocarbon maturation and charge are strongly influenced by salt. The salt canopy in the Gulf of Mexico extends for hundreds of kilometers with thickness locally of as much as 3 to 6 mi. Salt is weaker and less dense than other rock types, and over geologic times moves and flows through the rock along lines of weakness. These movements result in complex formations and have an important effect on the maturity of hydrocarbons and the geologic

FIGURE 1.5 Generalized salt features in a cross section across the Gulf of Mexico. From NOAA.

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structures that trap deposits (Fig. 1.5). In the early years after oil was first discovered, for instance, it was well known that drilling around the flanks of salt domes were good places to discover oil and gas because they created traps for hydrocarbon deposits. Since salt has high thermal conductivity, it retards the maturation of subsalt source rocks while accelerating that of hydrocarbons above the strata. As salt deforms over geologic time it creates faulting, scarps, and other potential geohazards that need to be understood and quantified to determine development risk. Geohazards are a major source of risk in deepwater because their nature, extent, and effects are neither well known nor reliably quantified. Below the slope break, the escarpment dips at steep angles (5
25 degrees), and near the base of the escarpment, major slump activity is observed out to several miles, clear evidence of numerous past failures that would have devastating consequences for any infrastructure in the debris flow (Fig. 1.6). The Sigsbee Escarpment is a major geomorphological feature of the Gulf of Mexico seafloor, basically an underwater mountain about 2000 ft in height at its tallest and extending for several hundred miles across the central and eastern region. The escarpment and associated canyons were caused by deformation of underlying salt deposits pushing downslope by sediment loading and erosion during periods of low sea level in the past.

FIGURE 1.6 Submarine slides and slump areas along the Sigsbee Escarpment near the Atlantis development. From NOAA.

1.2 REGULATORY STRUCTURE

9

1.2 REGULATORY STRUCTURE 1.2.1 OIL AND GAS LEASING In the Gulf of Mexico, leases for exploration and production on the OCS are obtained via auction and the payment of a bonus bid and are subject to rent during the primary term and royalty during production. Section 8 of the OCSLA stipulated that OCS tracts be auctioned by competitive, sealed bidding based on a cash bonus bid with a fixed royalty on oil and gas production paid to the government of not less than 12.5%. Lease areas could not exceed 5760 acres (3 mi 3 3 mi) and primary periods were specified for at least 5 years (Box 1.1). From 1954
82, areas for leasing were nominated by oil and gas companies and lease terms were for 5 years and the royalty rate was 1/6 (16.67%). In 1982 the Reagan administration announced a new area-wide leasing program that made available all unleased and available blocks in a planned area or program area. Under area-wide leasing, primary terms were extended to 8 and 10 years depending on water depth, and royalty rates on tracts greater than 400 m were lowered to 1/8 (12.5%). Various modifications of the lease terms and conditions have been made over the years with changing economic and political conditions. Historically, area-wide sales in the Central and Western Gulf of Mexico occurred in March and August each year but starting with lease sale 249 in 2017 the Western and Central planning areas were combined into two combined sales each year.

BOX 1.1 LEASE BLOCK SIZES AND BOUSTROPHEDONIC NUMBERING The Earth’s surface is approximately spherical and is divided into 360 degrees and each degree is subdivided into 60 minutes and each minute into 60 seconds. Latitude is measured in degrees, minutes, and seconds from the equator; longitude is measured in degrees, minutes, and seconds from the prime meridian that runs through Greenwich, England. In the World Geodetic System, one latitude second at the equator at sea level measures 30.715 m, one latitude minute is 1843 m, and one latitude degree is 110.57 km. The circles of longitude are called meridians, and because they meet at the geographic poles, the west-east width of a second decreases as latitude increases. At the equator at sea level, one longitudinal second measures 30.92 m, one longitudinal minute is 1855 m, and one longitudinal degree is 111.31 km, which differ slightly from the latitude mensuration because of the ellipsoidal nature of the Earth’s surface. A mesh of 1 degree of latitude by 1 degree of longitude at the equator describes an area of 12,307.25 km2. Moving north and south away from the equator, the area subtended by the mesh will become smaller and decrease rapidly near the poles. In the Gulf of Mexico, area blocks measure 3 mi 3 3 mi, or roughly 23 km2, approximately 3 minutes in each direction. The UK section of the North Sea awards offshore licenses that are 12 minutes west
east and 10 minutes north
south, with areas roughly 10 times as large at 250 km2. Norway uses blocks 20 minutes east
west by 15 minutes north
south that are 500 km2. In the Gulf of Mexico, UK and other European jurisdictions, the contract area is rather small by international standards, where contract areas often consist of many 5-minute blocks 10, 100, and even 500 times larger. Across most of North America, section numberings use a boustrophedon pattern (Greek for “as the ox plows”). In oil and gas leases in state and shallow waters of the Gulf of Mexico, lease blocks in protraction area are numbered beginning in the northeast corner proceeding west to east alternatively; in deepwater, the numbering pattern always increases eastward.

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1.2.2 REGULATORY AUTHORITIES The Bureau of Ocean Energy Management (BOEM), the Bureau of Safety and Environmental Enforcement (BSEE), and the Federal Energy Regulatory Commission (FERC) are the primary authorities that regulate pipelines on the outer continental shelf. BSEE and BOEM are branches within the US Department of Interior. FERC regulates pipelines that serve a transportation role and enforces the provisions of the Natural Gas Act relating to the transportation of natural gas in interstate commerce. In determining its jurisdiction, FERC distinguishes those lines that serve a transportation function from those that serve one of production, gathering, or aggregating. FERC regulates the former but not the later. BSEE provides oversight on lease activity and helps ensure that operations are performed in a safe and workmanlike manner and that equipment and work areas are maintained in a safe condition. BSEE is authorized to regulate exploration, development, and production operations on the OCS from drilling through decommissioning. BSEE regulations cover materials and structures, production safety systems, platform and structure design, maintenance and fabrication. BOEM oversees all oil and gas leasing activities on the OCS, including granting the Right of Use and Easement over lands where developers do not have a lease for the construction of facilities attached to the seabed. BOEM also administers three programs to ensure that decommissioning obligations and potential oil spills are covered: general bonding, supplemental bonding, and the Oil Spill Financial Requirements.

1.2.3 FAIR PLAY, SAFETY, LIABILITY, AND DECOMMISSIONING Government authorities regulate oil and gas pipelines on the OCS to address economic fair play, pipeline safety, liability, and decommissioning. Economic fair play issues relate to the pricing of transport services and open and nondiscriminatory access. Pipeline safety concerns relate to pipeline design, construction, and operation, while liability and decommissioning involve both operational and financial responsibility issues. The pipeline’s reach and who it serves are the main factors that determine regulatory authority. If a pipeline serves only a single party and does not put product into interstate commerce, it may avoid extensive federal regulation. On the other hand, if a pipeline serves a larger population and/or engages in interstate commerce, it will likely be subject to significant regulatory oversight. Determining regulatory jurisdiction over natural gas pipelines on the OCS frequently turns upon application of the “gathering exception” (Appendix C). This is the legal test applied to determine whether a natural gas pipeline “transports” gas in the open market or merely “gathers” gas for subsequent transport to the marketplace. As a rule, natural gas pipelines used for transportation are more highly regulated, while gathering lines escape extensive oversight. In many cases, the distinction between gathering and transportation is ambiguous, and legal definitions cannot provide a precise characterization of the networks and operational characteristics. In contrast to natural gas, jurisdiction over oil pipelines on the OCS depends less on a specific legal test and more upon which general category is being regulated. The various laws affecting oil pipelines depend more upon their statutory mandate rather than any single physical distinction. Pipeline design, construction, and safety on the OCS are issues over which both the US Department of Transportation and the US Department of Interior have been granted jurisdiction. Given

1.3 PRODUCTION SYSTEM COMPONENTS

11

the jurisdictional overlap, both agencies have worked closely to avoid administrative redundancies. Bonding requirements and abandonment of pipeline service are issues that receive significant regulatory attention, both from an economic as well as a safety and liability standpoint. There are significant differences between oil and natural gas pipelines and FERC’s regulatory framework.

1.3 PRODUCTION SYSTEM COMPONENTS From the reservoir, fluids travel up through the production tubing and into a wellhead before making its way to a processing platform (Fig. 1.7). Normally, flowlines refer to the pipelines carrying hydrocarbon streams from a subsea wellhead to the riser foot of the processing facility. These lines are also commonly referred to as infield flowlines since they occur within the field development. The pipelines that exit the processing facility carrying processed and separated oil and gas are called export (or transportation) pipelines. Flowlines are used to transfer fluids between platforms, manifolds and satellite wells, and water injection and chemical injection flowline, are a special class.

FIGURE 1.7 Schematic of offshore production system components and infrastructure. From Guo, B., Song, S., Ghalambor, A., Ranlin, T. 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

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1.3.1 WELLS Wells are the central feature of all oil and gas developments, onshore and offshore, except in oil sands mining operations. Wellheads may be located on the platform or at the mudline, and similarly, the trees which sit atop the wellhead may be above or below the waterline. Dry tree wells refer to trees above the waterline, whereas wet tree wells have trees located on the seafloor. Dry tree wells are accessible via a platform rig, whereas wet tree wells require a mobile offshore drilling unit for interventions. Wet wells are controlled using umbilicals from a nearby platform and route their production to the host via flowlines and up a riser. Direct vertical access wells are a special type of subsea well where the wellhead and tree is on the seafloor but is accessible from a platform rig overhead. Below the mudline, a well path is constructed to connect the target with the surface location (Fig. 1.8). The location of the target is placed in the reservoir to optimize production if the purpose of the well is to recover oil and gas. Normally, the optimal wellbore trajectory should result in minimum drilling and completion cost at an acceptable risk. Faults are avoided whenever possible. The location of the surface location is determined by seabed topology, avoidance of shallow water hazards, future development plans, and related considerations. The number of wells required in development is a key design consideration.

FIGURE 1.8 Hibernia field fault map and well trajectories from a gravity-based structure offshore Newfoundland, Canada. From Elsborg, C.C., Power, A.K., Schuberth, P.C. 2005. Hibernia record well breaks extended reach drilling and completion envelope. In: SPE/IADC 92347, SPE/IADC Drilling Conference and Exhibition, Amsterdam, February 23
25.

1.3 PRODUCTION SYSTEM COMPONENTS

EXAMPLE: MEDUSA FIELD COMPARTMENTALIZATION The Medusa field is located in Mississippi Canyon in 2200 ft water depth over blocks MC 538 and 582 (Fig. 1.9). (a) The T4b reservoir is one of the three major productive intervals and occurs at a depth of about 13,000 ft TVDSS (total vertical depth subsea) east of a salt weld that bisects the field (Lach et al., 2005). Using the exploration and development well trajectories shown in Fig. 1.10, shade the approximate field outline. (b) How many faults within the T4b sands are depicted and what are the implications for development?

FIGURE 1.9 Structural map of the R4b sand formation in the Medusa field. From BOEM.

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CHAPTER 1 OFFSHORE OVERVIEW

FIGURE 1.10 Exploration and development wells drilled on Green Canyon blocks 538/582 in the Medusa field. From BOEM.

Solution (a) The approximate outline of the field can be drawn using the endpoints of the wells depicted. Connecting these end points provides a rough outline of the field, and when combined with reservoir pay zones volumetric reserves can be estimated. (b) Seven faults are depicted of various length and width within the R4b reservoir. Faults often restrict flow and compartmentalize the sands, and thus, reservoirs that are faulted and with poor communication with other reservoirs will require more wellbores than better connected sands.

1.3 PRODUCTION SYSTEM COMPONENTS

15

EXAMPLE: MEDUSA WELL STATISTICS The discovery well in the Medusa field MC 582-1 reached 15,621 ft TVDSS and measured depth 16,950 ft in September 1999 (Fig. 1.11).

FIGURE 1.11 Days versus depth plot for the discovery well in the Medusa field, MC 582#1 and sidetracks. From Chhajlani, R., Zheng, Z., Mayfield, D., MacArthur, B. 2002. Utilization of geomechanics for Medusa field development, deepwater Gulf of Mexico. In: SPE 77779, SPE Technology Conference and Exhibition, Dallas, TX, September 29
October 2.

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a. Is measured depth always greater than vertical depth? How far below the mudline is the formation? b. Why are wells sidetracked and bypassed? How many boreholes were drilled in the campaign and what naming convention is applied? c. How much total borehole was drilled? Estimate the horizontal offset for each well. d. Estimate the total vertical depth of MC582-1 using the measured depth and horizontal departure and compare with the reported 15,621 ft TVDSS. e. About what percentage of drilling days was spent drilling ahead? f. The time scale is not explicitly labeled. What scale might be reasonable? Why was the scale not included? Solution a. Measured depth is measured along the wellbore, while TVD is measured straight down. Thus, MD is always greater than TVD except in perfectly straight vertical wells. For offshore wells, the datum is usually the waterline or rig floor, and MD and TVD include water depth, so the values appear consistent with standard usage. Since water depth is 2200 ft, the discovery formation is approximately 13,421 ft below the mudline. b. During exploration, wells are plugged back and sidetracked to delineate sands, and wells are bypassed when problems arise in the borehole during drilling. Sidetrack wells are distinguished from the original borehole and are numbered separately and require separate permits to drill. Three sidetracks were drilled from the original borehole along with one bypass well. Wells are named based on their bottom hole lease location and are usually numbered sequentially in the order drilled. c. The measured depth is computed for each well by reviewing the depth plot. For example, MC 538-1 was drilled from about 6000 to 9000 ft MD, so 3000 ft of the hole was drilled along the wellbore. The MC538-1 bypass well was drilled from about 6000 to 12,000 ft MD, or 6000 ft MD total. HD denotes horizontal departure. Well

MD (ft)

HD (ft)

MC 582-1 MC 538-1 MC 538-1 BP-1 MC 582-1 ST-1 MC 582-1 ST-2

17,000 3000 6000 8000 1000

4000

6000 6000

Total borehole drilled during the drilling campaign is about 35,000 ft. pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi d. TVD  MD2 2 HD2 5 ð17; 000Þ2 2 ð4000Þ2 5 16; 523 ft. e. Drilling time describes the proportion of total time spent drilling and can be approximated by measuring the ratio of the “flat time” on the drilling curve to the total time: Drilling time 5

Flat time  56% Total time

f. On average, it usually takes about 3 months to drill a deepwater Gulf of Mexico well, so the units of the scale probably relate to one week or 10 days. Operators rarely provide information that allows drilling performance or cost statistics to be inferred.

1.3 PRODUCTION SYSTEM COMPONENTS

17

FIGURE 1.12 Extended reach well types. Adapted from Bennetzen, B., Fuller, J., Isevcan, E., Krepp, T., Meehan, R., Mohammed, N., 2010. Extended-reach wells. Oilfield Rev. 22 (3), 4
15.

The well path design is considered simultaneously with the casing, completion program, wellbore stability, cuttings transport, and any anticipated hole problems (Bourgoyne et al., 1991; Mitchell and Miska, 2011). Wells designed to be confined to a vertical plane are referred to as 2D wells and any well not located in a vertical plane is defined as a 3D well. 2D wells are often recommended whenever feasible due to the complexity and risk of 3D wells (Azar and Samuel, 2007). There are three basic 2D directional well profiles: build and hold (slant), catenary, and S-turn (Fig. 1.12). A build and hold profile consist of a vertical part, build section, and a tangent section (Bennetzen et al., 2010). The slant profile is drilled at a constant angle once the tangent angle has been established from the kickoff point. The catenary profile is a variation of the slant profile that begins with a lower build rate that accelerates as the wellbore angle increases. S-shaped well profiles are characterized by a high angle tangent section before dropping angle as it enters the target. 3D well profiles are created by adding one or more azimuth turns in well construction. 3D wells are designed for a variety of geological and engineering reasons such as to avoid faults and difficult to drill subsurface formations (e.g., salt domes), as well as to avoid intersecting other wells.

1.3.2 STRUCTURES In shallow water, designs are relatively simple. If the field is large enough, a fixed platform is installed, and development wells are drilled and completed from the platform which also usually processes the production for export. For smaller reservoirs, a simple structure is installed around wellbores drilled from a jackup and production is directed back to a host platform for processing.

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CHAPTER 1 OFFSHORE OVERVIEW

In deepwater, multiple host and subsea layout configurations are possible and are compared relative to their cost, risk, and trade-offs. Wet wells are used for marginal developments or in conjunction with a stand-alone facility. There are a variety of deepwater structure types used worldwide that include floating production storage and offloading vessels (FPSOs), by far the most common, semisubmersibles (semis), surface piercing articulating risers (spars), tension leg platforms (TLPs), and their varieties. All of the main system types are used in the Gulf of Mexico (Fig. 1.13).

FIGURE 1.13 Deepwater floating types in the Gulf of Mexico. From Chevron, Shell, BOEM.

1.3 PRODUCTION SYSTEM COMPONENTS

19

The primary purpose of a structure is to hold the equipment used to process production into separate oil and gas streams for transportation. There are usually two export pipelines for oil and gas, but in some cases, there may be just one export pipeline exiting a structure, while in other cases, especially for hub platforms, several export lines may depart if production from other facilities is being routed across the structure. The number of flowlines and pipelines that board and depart a structure depend on whether subsea wells are used and if the structure serves as a pipeline junction or processing host.

EXAMPLE: COGNAC Cognac was the first platform in the Gulf of Mexico installed in water deeper than 1000 ft (Fig. 1.14). From 1978 to 1981, a total of 61 wells were drilled and cased from the platform and 38 wells were completed. First production occurred in 1979 (Gur et al., 2009).

FIGURE 1.14 Cognac platform in Mississippi Canyon block 194 in 1025 ft water depth. From BOEM.

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CHAPTER 1 OFFSHORE OVERVIEW

Oil production began early in development and flowed along with gas in a 12-in two-phase export pipeline to Shell’s East Bay process facility in South Pass 27, approximately 27 mi away (Fig. 1.15). In 1981 a second 16-in pipeline was installed to transport gas production separately, and the 12-in line reverted to single-phase crude oil transportation (Fig. 1.16). For a view of the local neighborhood c.2020, see Appendix D (Figure D.8).

FIGURE 1.15 Location of Cognac’s initial two-phase export pipeline. From BOEM.

1.3 PRODUCTION SYSTEM COMPONENTS

21

FIGURE 1.16 Cognac’s oil and gas export pipeline c.2020. Data from BOEM.

1.3.3 PIPELINES A pipeline is, in principle, a very simple structure, normally made from steel with the sole purpose of delivering fluid from one point to another. Most steel pipelines are 40 ft (12 m) long segments, referred to as joints. The joint must be straight, the hole must be round, and the diameter and thickness of the pipe must be able to withstand all the forces acting upon it during installation and over its design life.

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CHAPTER 1 OFFSHORE OVERVIEW

1.3.3.1 Class Offshore pipelines are distinguished according to their degree of processing and type of fluid flow. Export pipelines refer to lines that transport processed oil and gas streams to shore. Pipelines associated with delivering (unprocessed) raw fluids from subsea wellheads or another structure to a host facility for processing are referred to as infield flowlines or simply flowlines. Export lines are also commonly referred to as sales quality or transmission pipeline. Infield flowlines are also called gathering lines and are part of SURF (subsea equipment, umbilicals, risers, flowlines) systems.

EXAMPLE: JOLLIET FLOWLINE MILEAGE Estimate the flowline distance from the Jolliet TLP in Green Canyon block 184 to the Central Processing Platform in GC 52 shown in Fig. 1.17. What do you notice about the pipeline route as it traverses its path? Compare the schematic to the pipeline routed created using BOEM data in Fig 1.18 and comment on the limitations of schematics.

FIGURE 1.17 Pipelines from the Jolliet tension leg platform to processing platform in Green Canyon block 52. From BOEM.

1.3 PRODUCTION SYSTEM COMPONENTS

FIGURE 1.18 Jolliet’s oil and gas export pipeline c.2020. Data from BOEM.

Solution Lease blocks in the OCS are usually 3-mi square in size unless clipped by another boundary. After setting up an equivalence scale with a ruler, measure the path and estimate mileage. The flowline route is measured at approximately 11 mi, and the straight-line distance is about 9 mi. The pipeline route traverses the water depth contours at right angles, which is heads-on along the shortest route uphill. Contour lines which are close together represent steep grades. Rocky outcrops, salt mounds, and other obstacles will impact local routing. North in the schematic is to the left and compares favorably with the c.2020 configuration. Schematics cannot accurately define infrastructure location and must be provided with position coordinates in engineering studies (Box 1.2).

23

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CHAPTER 1 OFFSHORE OVERVIEW

BOX 1.2 CARTOONS AND THEIR LIMITATIONS One great tool to visualize infrastructure requirements in field development is to draw a cartoon depicting the system architecture. Schematics are the principal means of describing offshore infrastructure, but of course, they are inherently inaccurate since the thickness of a line or a point representing a pipeline or structure may represent tens of meters on the ground even on quite large-scale maps. This means that maps cannot be used to accurately define infrastructure without position coordinates. Maps usually specify its scale as a ratio or fraction, or as a simple graph. The ratio scale is a dimensionless number, and in some maps, a fraction may be used, but both forms have the same meaning. Theoretically, the comparison is between the length of a line measured on the chart and the distance represented on the surface of the earth. A scale of 1/250,000 or 1:250,000 indicates that a length of 1 cm on the chart represents a distance of 250,000 cm (2500 m) on the surface of the earth. The scale of a map or photograph varies from point to point due to displacement caused by tilt and relief on the surface of the earth. Normally, survey works up to 100 square miles can be treated as planar, assuming the curvature and spherical shape of the earth, as well as the relief of the seabed, are negligible. The choice of scale has a direct bearing on the accuracy with which a position can be determined. For the Gulf of Mexico where 3 mile square blocks are the natural unit, if 1 in 5 3 mi, then the scale would be 1:190,000. If 1 in 5 1 mi, the ratio is 1:63,360; if 1 in 5 3000 ft, the ratio is 1:36,000. The range of suitable scales will normally be from 1:50,000 to 1:250,000 for offshore delimitation. The plotting errors in the determination related to the various scales are approximately 10 m for 1:50,000 scale and 40 m for a 1:200,000 scale. In many cases, field schematics refer to initial development plans and are intended to represent the key features under consideration; they are not intended to represent all elements or to be an exact description of the development. Therefore old schematics will not accurately depict current configurations, since new wells are frequently drilled and sidetracked, subsea infrastructure may be tied back to the facility later, flowlines from the platform may be installed to support gas delivery off lease, etc. In some cases, fields may not have been developed according to the plan shown in the schematic, so reader beware. Schematics are an approximate representation that illustrates the primary features at the time of development. In the US Gulf of Mexico, field schematics are secondary data sources, but in many offshore basins around the world, they are often the only publicly available data.

1.3.3.2 Type and Coatings Pipelines may be rigid steel, flexible line, or pipe-in-pipe (PIP) systems (Fig. 1.19). All types are used in offshore applications, but rigid steel and flexible lines are by far the most common in terms of miles laid. Rigid pipe is the least expensive and considered the most reliable for long-term service. Traditional pipe is composed of a simple steel tube wrapped in an anticorrosion coating and possibly covered with a polymer concrete. Flexible pipe is composed of multiple layers of wound steel interspersed with extruded plastic coatings. PIP consists of an insulated and sometimes electrically heated pipe placed inside of an outer pipe. There are several different coating systems used, but for offshore applications three-layer polypropylene is one of the most common. Polypropylene systems consists of an epoxy primer and a grafted copolymer adhesive to bond the epoxy primer with a topcoat. Flexible pipe is often used for smaller diameter, short distance flowlines, as jumpers from marine wellheads and well manifolds to rigid flowlines, and as risers. The main characteristic of the flexible pipe is its ability to bend. This characteristic is achieved by using several layers of different materials in fabrication. Steel armor layers with high stiffness provide strength and polymer layers with low stiffness provide fluid integrity. These layers can slip past each other when under the influence of external and internal loads.

1.3 PRODUCTION SYSTEM COMPONENTS

25

FIGURE 1.19 Steel pipe with concrete coating, flexible pipe, and pipe-in-pipe. From Technip

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CHAPTER 1 OFFSHORE OVERVIEW

1.3.3.3 Flow conditions Pipeline fluid flow is generally categorized based on the fluid phase condition as: • • •

single-phase, two-phase, and three-phase.

The pipelines after separation equipment, such as export pipelines, generally flow single-phase hydrocarbon fluid, and single phases are also present in gas or water injection pipeline, chemical service such as methanol and glycol lines, and are the dominant mode in black oil and dry gas reservoirs. A typical production flowline consists of water, oil, and gas, but oil and released gas, and gas and produced oil (condensate), are also common. The hydraulic theory underlying single-phase flow is old and well understood, and analytic models are used with confidence. Multiphase flow is significantly more complex, but simulation and empirical models have improved considerably over the past decades and are applied with acceptable engineering accuracy (Bai and Bai, 2019).

1.3.3.4 Dimension Pipelines are described by their diameter and wall thickness (American Petroleum Institute, 2009). Nominal pipe size (NPS) is numerically close to the pipe outside diameter in inches, and schedule number (SN) describes wall thickness using a dimensionless measure. NPS represents a value in-between the inner diameter and outer diameter (OD) of the pipe. By convention, NPS 12 and smaller have an outside diameter greater than their NPS, whereas NPS 14 and larger have an outside diameter exactly equal to their NPS (McAllister, 2014). For example, NPS 2 size pipe is 2.375 in OD, whereas NPS 16 pipe is 16 in OD. The rules are archaic but logical. The outside diameter of each pipe is standardized, and thus, the inner diameter will change with pipe schedule number, approximated by the equation SN 5 1000P/S, where P is the service pressure (psi) and S is the allowable stress (psi). Schedule number SN is a dimensionless designation of wall thickness, varying from 5 to 160 in increments: 5, 10, 20, 30, 40, 60, 80, 100, 120, 140, 160. The higher the number, the thicker and heavier the pipe. For example, NPS 12 SN 30 has an outside diameter of 12.75 in and an inside diameter of 12.09 in, where NPS 12 SN 100 has an inside diameter of 11.064 in. The higher the schedule, the greater the thickness.

1.3.3.5 API 5L base pipe In the United States, oil and gas pipelines are constructed using pipe materials conforming to API Specification 5L, Line Pipe (API 5L) standards (American Petroleum Institute, 2019). API 5L provides requirements for the manufacture of seamless and welded pipes and consists of historical, scientifically validated criteria. Specification 5L is not a “how to” instructional manual or recipe, rather a set of boundary limits and performance characteristics that the finished product must meet. In its 46th edition, effective May 1, 2019, API 5L was over 150 pages long with more than 40 tables and 12 Appendices. API 5L covers line pipe grades from A25 to 120, diameter from ½ to 84 in, and wall thickness up to 2 in. There are two product specification levels: PSL 1 and PSL 2. PSL 1 is a standard quality level

1.3 PRODUCTION SYSTEM COMPONENTS

27

and PSL 2 applies tighter controls on chemical composition, mechanical properties, and quality. PSL 2 has mandatory requirements for carbon equivalent, notch toughness, maximum yield strength, and maximum tensile strength. Specification 5L also has annexes for supplemental requirements for fracture control in gas pipelines, sour service, and offshore service.

1.3.3.6 Grade Steel is an iron-based alloy that contains up to 2 percent carbon. Steel used in offshore pipeline is a low carbon
manganese alloy specified by a large number of characteristics that include chemical composition, mechanical properties, surface condition, grain size, hardenability, tolerances, and production process. Yield strength is a fundamental feature and defined as the maximum stress the material can experience without failure. Strength is measured in units of force per area as thousand pounds per square inch (ksi) or Newtons per square meter (N/m2). The two-digit number following the “X” indicates the minimum yield strength (in ksi) of pipe produced to this grade. The addition of alloying elements like carbon, manganese, silicon, niobium, vanadium, and titanium strengthens the steel; however, the addition of alloying elements may reduce the weldability and other parameters (Table 1.1). The carbon and manganese contents are the primary elements that determine weldability. Corrosion resistance is another important specification and elements such as chromium and nickel are used to improve corrosive properties (Table 1.2). The precise mixture of alloys in the steel will depend on the pipe manufacturer and the specifications of the project including wall thickness, strength required, and the corrosive characteristics and temperature of the fluid (Palmer and King, 2008).

Table 1.1 Impacts of Alloys on Mechanical and Corrosive Properties of Steel Alloy

Effect on Steel Mechanical and Corrosive Properties

Aluminum Carbon

Used to refine grain size. Increases hardness and weld toughness. Added as a deoxidizer. Increases tensile strength and hardness but reduces toughness and weldability. Increases corrosion. Increases tensile strength and hardness. Decreases weldability. Improves corrosion resistance. Improves sour cracking resistance for pH .4.5. Adversely affects surface quality. Increases tensile strength, hardness, and abrasion resistance. Decreases porosity and cracking. Forms sulfides that may cause hydrogen cracking. Increases hardenability, wear resistance, toughness, high temperature strength. Increases tensile strength and toughness at low temperatures and improves corrosion resistance. Improves weld strength. Increases strength but reduces low-temperature toughness. Improves strength, hardenability, corrosion resistance. Reduces ductility and toughness. Increases tensile strength but reduces toughness. Added as a deoxidizer to kill the steel. Increases porosity, brittleness, and cracking. Impairs surface quality and weldability. Increases tensile strength, hardenability, and wear resistance. May reduce toughness. Increases tensile strength, hardenability and wear resistance.

Chromium Copper Manganese Molybdenum Nickel Nitrogen Phosphorus Silicon Sulfur Titanium Vanadium

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CHAPTER 1 OFFSHORE OVERVIEW

Table 1.2 Chemical Composition for API 5L PSL 1 Welded Pipe, Wall Thickness # 25.0 mm Mass Fraction, % Based on Heat and Product Analysesa

Grade

B X42 X52 X60 X65 X70

C maxb

Mn maxb

P max

S max

V max

Nb max

Ti max

0.26 0.26 0.26 0.26e 0.26e 0.26e

1.2 1.3 1.4 1.40e 1.45e 1.65e

0.30 0.30 0.30 0.30 0.30 0.30

0.30 0.30 0.30 0.30 0.30 0.30

c,d d d f f f

c,d d d f f f

d d d f f f

Cu # 0.5046%; Ni # 0.5046%; Cr # 0.5046%; and Mo # 0.15%. For each reduction of 0.01% below the specified max concentration for carbon, an increase of 0.05% above the specified max concentration for Mn is permissible, up to a max of 1.65% for grades $ B, but # X52; up to a max of 1.75% for grades . X52, but , X70; and up to a maximum of 2.00% for X70. c Unless otherwise agreed Nb 1 V # 0.06%. d Nb 1 V 1 Ti # 0.15%. e Unless otherwise agreed. f Unless otherwise agreed, Nb 1 V 1 Ti # 0.15%. a b

There has been interest in developing higher strength steels for offshore projects (Okaguchi et al., 2004) and X80 pipeline is increasingly used. By increasing the strength of the pipeline, the cost on a unit weight basis will increase, but the diameter and wall thickness of the pipeline may decrease, decreasing the total weight of pipe needed and reducing material and welding costs since less filler material is used. Increasing pipe strength comes at the cost of weldability and reel capability and for these reasons, adoption of higher strength steels has been slow.

1.3.3.7 Design After selecting pipeline diameter based on throughput requirements, selection of wall thickness and coating follows (Bai and Bai, 2019; Guo et al., 2014; Menon, 2011). Conventional pipeline design is generally dominated by the need to withstand the internal pressure in the line. High pressures mean that products can be passed down the line at a higher flow rate, generating greater revenue for the operation. For deepwater pipelines, the need to prevent hydrostatic collapse due to external water pressure plays an important role, especially during installation, and may be a design limitation. Design engineers determine wall thickness based on the outer diameter of the pipe, the specified minimum yield strength of the steel, the pipeline design operating pressure, external hydrostatic pressure from the water depth, and the need for enough pipeline weight for stability on the seabed (Nogueira and McKeehan, 2005; Palmer and King, 2008). Wall thickness must be adequate to prevent internal pressure containment (burst) during operation and hydrotest, collapse due to external pressure, local buckling due to bending and external pressure, and buckle propagation and its arrest. Typically, the wall thickness will range from 4% to 6% of the outside diameter of the pipe; for an 18-in (457 mm) line, for example, wall thickness usually ranges from 18 to 27 mm.

1.3 PRODUCTION SYSTEM COMPONENTS

29

1.3.3.8 Manufacturing Mills produce two types of line pipe, seamless and welded (Fig. 1.20). Seamless pipe is formed from a cylindrical bar of steel. The bar is heated to a high temperature and then a probe is inserted to create a hole through the cylinder. The cylinder is then transferred to rollers which size the cylinder to the specified diameter and wall thickness. A few mills can produce seamless pipe up to 24-in in diameter. For small diameter pipe, seamless pipe is common but unit costs are high and availability is usually limited. As pipe diameter increases, welded pipes are more economical. In welded pipe, welding is used to close the seam after forming a steel plate or coil into a cylindrical shape. The mill uses ultrasonic and/or radiological inspection methods to ensure the quality of the weld seam and initiates pressure tests on each joint of pipe to levels that exceed the proposed operating pressure. Welded pipe is classified based on how it is formed and the type of welding technique used. Submerged arc weld (SAW) pipe uses filler metal in welding, whereas electric resistance welded/ electric fusion welding (ERW/EFW) are no-filler metal processes. SAW is further classified into longitudinal (or straight) welding (L-SAW) and S-SAW means spiral (or helical) weld tube. Normally, medium diameter straight L-SAW has a single seam, and large diameter L-SAW uses a double seam. ERW pipe is manufactured using electric current to heat the steel to a point at which the edges melt together to form a bond. This manufacturing process was introduced in the 1920s and utilized low-frequency alternating current to heat the edges, but was found to be vulnerable to seam

FIGURE 1.20 Pipe classification by manufacturing process.

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CHAPTER 1 OFFSHORE OVERVIEW

corrosion and inadequate bonding. Today, high-frequency alternating current is used, also known as contact welding. EFW pipe refers to a process that uses an electron beam to direct kinetic energy to melt the workpiece to form the weld. PIPs are manufactured using two pipes separated by insulation and are used to maintain the temperature of the fluids to prevent the formation of hydrates, reduce wax deposition, or to reduce the pressure drop by reducing the viscosity of heavy crudes (Cochran, 2003). Rigid flowlines are manufactured from carbon steel or a high-performance steel alloy, with additional coatings providing corrosion protection and insulation. Flexible flowlines have the same applications as rigid flowlines but are manufactured differently, using composite layers of steel wire and polymer sheathing that provide high flexibility (Box 1.3). A typical 8-in diameter flexible pipe, for example, can be safely bent to a radius of two meters or less. This flexibility is important for risers and flowlines laid on uneven seabeds and permits spooling on a reel or carousel in installation. The preference for using a rigid or flexible flowline is driven by design requirements, installation constraints, cost, schedule, and other factors.

BOX 1.3 FLEXIBLE PIPELINE CONFIGURATION A flexible pipe is a configurable product made up of several independent layers tailored to each development (Fig. 1.21). Flexible pipes are used for risers, flowlines, and jumpers in offshore operations, but because the unit cost is much more expensive than a carbon steel pipe, its use is often limited to special applications and small quantities (Tuohy et al., 2001). Flexible pipe is manufactured by wrapping several intertwining layers of stainless steel and special polymers. The helically wound steel wires give the pipe its high-pressure resistance and bending characteristics, and since the steel wires are not in direct contact with the conveyed fluid, they do not require the same corrosion resistance as steel pipe. Variation in the choice of materials, the number and order of layers, and manufacturing process depends on the conditions and operating environment. The components of an unbonded flexible pipe are as follows: Carcass. The carcass forms the innermost layer and is the conduit for fluid transport. It is commonly made of a stainless steel flat strip that is spirally wound and formed into an interlocking profile. The main function of the carcass is to prevent pipe collapse due to hydrostatic pressure in the annulus. Internal polymer sheath. The internal polymer sheath provides a barrier to maintain the bore fluid integrity. Common materials used include Polyamide-11 (Rilsan), high-density polyethylene, cross-linked polyethylene, and PVDF. Pressure armor. The pressure armor, as its name implies, is wound around the internal polymer sheath for protection and is made of interlocking wires or wire strips. Its role is to withstand the hoop stress in the pipe wall caused by the fluid pressure. Tensile armor. The tensile armor layers are used to resist tensile loads, to support the weight of all the pipe layers, and to transfer the load through the end fitting to the structure. The tensile armor layers are cross-wound in pairs and in high tension applications, say in a deepwater riser, may require the use of four tensile armor layers. External polymer sheath. The main function of the external sheath is as a barrier against seawater and is often made of the same materials as the internal polymer sheath. External sheaths also provide protection against clashing with other objects during installation. Other layers. Antifriction and antiwear tape are wound around the armor layers to reduce friction and wear of the wire layers when they rub past each other as the pipe flexes from external loads. Antiwear tapes are used to ensure that the armor layers maintain their wound shape and prevent the wires from twisting out of their configuration, a phenomenon called birdcaging that is a result of hydrostatic pressure causing axial compression in the pipe. Additional layers of material with low thermal conductivity can be applied to obtain specific thermal insulation properties. (Continued )

1.3 PRODUCTION SYSTEM COMPONENTS

BOX 1.3 (CONTINUED)

FIGURE 1.21 Generalized cross section of an unbonded flexible pipe. From Bai, Y., Bai, Q. 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA.

31

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1.3.4 SUBSEA SYSTEMS 1.3.4.1 Umbilicals Umbilical lines provide chemicals, control, and power to wet wells (Fig. 1.22). Strictly speaking, umbilicals are usually not considered pipeline because their main purpose is to provide power and

Outer sheath Inner sheath Electric cable (power/signal)

3-Phase HV cables

Fiber-optic cable

25cr super duplexhydraulic control, injection of service chemicals and hydrate inhibitors Dual layer armour package

Steel tube

Fiber-optic cable

Electrical cable Binding tape Polymer filler

Outer sheath

FIGURE 1.22 Umbilical cross sections showing electric and fiber optic cable and chemical lines. From Offshoretechnology.com.

1.3 PRODUCTION SYSTEM COMPONENTS

33

control via electrohydraulic signals, but many umbilicals also contain tubes for chemical delivery so they may also serve a fluid transport function. Separate tubes within the umbilical are usually used for each chemical. Umbilicals normally include steel tubes and/or thermoplastic hose fluid conduits to provide hydraulic control and chemical injection service; low voltage electrical power and communications provided via signal cables, fiber optic cables and power conductors; medium voltage electrical power conductors; chemical injection lines for use in corrosion inhibition and prevention of wax and scale build-up; large bore center tubes for bulk chemical injection or gas lift functions. Because of the diversity of umbilical functions, they are custom designed and fabricated for each offshore project. Umbilicals are fabricated in single continuous length according to industry standards and codes. Fabrication is complex and utilizes a rotating turntable equipped with several spools or bobbins. The spools contain the pipes, cables, hoses, and filler material in long, continuous lengths. As the turntable rotates, the spools are paid out and the pipes, cables, and hoses are braided together. A steel armor may be added over the braid to meet pressure requirements and a polymer is then extruded over the braid to ensure circularity.

1.3.4.2 Risers Risers are the fluid transfer system linking the seabed and the deck of the facility and are associated with drilling, production, and import/export pipelines (Fig. 1.23). Production and water/gas injection risers connect the surface equipment to the wellheads at the seabed, export risers connect the equipment that processes fluids to seabed pipelines, either transiting to or from the facility, and drilling risers are used to hold the drill string and serve as a conduit for drilling fluids between the surface and the wellhead. Risers are different than the pipelines and flowlines that reside on the seabed and are subject to a range of changing forces. Ocean currents, water pressure, vessel motion, and wave actions are the primary forces that risers encounter over their lifetimes, and therefore, must be designed to minimize fatigue damage. Riser design is one of the most complex aspects of deepwater production systems and structure motions and offsets have a major influence on configurations (Bai and Bai, 2019). Risers attached to fixed platforms are considerably different than risers attached to floating structures. There are three types of risers: rigid risers that include steel catenary risers (SCRs) and top tensioned risers (TTRs), flexible risers, and hybrid risers that combine elements of rigid and flexible risers. The choice between flexible pipe and rigid risers involves trade-offs in cost and reliability. SCRs were initially used as export lines on fixed platforms, attached to the outside of the structure, vertical at the top end and horizontal at the lower end. In this arrangement, the riser forms an extension of the flowline that is hung from the platform in a catenary shape. In deepwater, SCRs are freehanging with no intermediate buoys or floating devices. SCRs are sensitive to waves and currents, and vortex-induced vibration suppression devices such as helical stakes and fairings are used to reduce vibrations. SCRs are the most common riser type for export lines and wet trees. TTRs are long circular cylinders used to link the seabed tree to a floating platform and are designed to provide direct access to wellheads on the platform. TTRs are held in tension at the surface and allow the riser to move axially or stroke relative to the platform. The risers often appear in a group arranged in a rectangular or circular array. TTRs are commonly used on TLPs and spar dry tree platforms.

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CHAPTER 1 OFFSHORE OVERVIEW

FIGURE 1.23 Sideview of the mooring system, risers, and umbilicals at a floating structure. From BOEM.

Flexible risers use flexible pipe in their configuration and have been deployed in a variety of developments depending on water depth and environment. Hybrid risers consist of a vertical bundle of steel pipes supported by external buoyancy. Jumpers connect the top of the riser and the vessel and are used to accommodate the differences in relative motion.

1.4 DESIGN PROCESS The design process for each type of offshore pipeline is generally the same and is only described conceptually in this concluding section. For more detailed treatments, good places to start are Bai and Bai (2019) and Guo et al. (2014). For succinct authoritative accounts, see also Nogueira and McKeehan (2005) and Stevens and May (2007). For onshore applications, which has some similarities with offshore, see McAllister (2014) and Menon (2011). The design of subsea pipelines is usually performed in three stages: • • •

conceptual engineering, preliminary engineering, and detailed engineering.

The objective and scope of each stage depend upon the operator, size of the project, and schedule. The design process to optimize the pipeline parameters is iterative and summarized in Figs. 1.24 and 1.25.

1.4 DESIGN PROCESS

35

Design requirements

Requirement to transport product

Operator specific requirements

Codes, standards and specifications

Process requirements

Wall thickness selection

Optimized design

Design analysis

Material grade selection

Route selection

Pipeline protection

Pipeline installation

Fail requirements

Pipeline stress analysis

Fail requirements

Optimum flowline ID, WT, material grade, and coating

FIGURE 1.24 Offshore pipeline design process. From Bai, Y., Bai, Q. 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA.

36

CHAPTER 1 OFFSHORE OVERVIEW

Design requirements

Wall thickness selection

Material grade selection –Cathodic protection –Suitability to product

Route selection –Minimize pipeline length –Minimize pipeline spans –Minimize number of bends –Maximum corridor width

Pipeline protection –Concrete coating –Trenching/burying –Rockdumping –Mattressess/structures

Pipeline protection –Hoop stress –Longitudinal (equivalent) stress –Span analysis and vortex shedding –Stability analysis –Expansion analysis (and TIE-INS) –Buckling analysis –Crossing analysis

Pipeline installation analysis –Hoop stress –Longitudinal (equivalent) stress –Span analysis and vortex shedding –Stability analysis –Expansion analysis (and TIE-INS) –Buckling analysis –Crossing analysis

Fail requirements

Fail requirements

Fail requirements

Optimal design

FIGURE 1.25 Offshore pipeline design stages. From Bai, Y., Bai, Q., 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA.

1.4 DESIGN PROCESS

37

1.4.1 CONCEPTUAL ENGINEERING In conceptual engineering, the objective is to establish the technical feasibility and constraints associated with the system design and construction. Basic cost and scheduling expenses are performed, information requirements identified for preliminary engineering, and interfaces with other systems established.

1.4.2 PRELIMINARY ENGINEERING The objective of preliminary engineering is to define the system concept and prepare regulatory and contractual applications. The level of engineering is sometimes specified as sufficient to let as an engineering, procurement, construction, and installation tender.

1.4.3 DETAILED ENGINEERING In detailed engineering, the pipeline route is optimized, flow regions for horizontal and upward vertical gas
liquid flow are determined, the wall thickness and coating is selected, pipeline grade and corrosion coating is chosen, code requirements are confirmed and validated, and specifications are detailed adequate for requisition and certification.

BOX 1.4 PIPELINE STRENGTH AND MODULUS OF ELASTICITY Pipelines are subject to forces called loads during installation and operation and experience stress. Stress is defined as the force to which it is subject divided by the area of the pipeline. The strength of a material is simply the maximum stress the material can experience without failure. Strength is measured in units of force per area as thousand pounds per square inch (ksi) or Newtons per square meter (N/m2). Tensile strength is the maximum pulling stress a piece of material can withstand without failing. Compressive strength is the maximum pushing stress a material can withstand without failure. During installation, pipelines are subject to bending loads and both tensile and compressive stress. Materials lengthen when pulled, and the percentage a material changes in length, when subjected to a pulling load, is referred to strain. The relation of tensile strength and strain is empirically determined through a tensile test in which a test specimen is mounted in a test machine and pulled by applying increasing loads (stresses) while the percentage change in the length of the specimen is recorded, resulting in a stress
strain diagram (Fig. 1.26).

FIGURE 1.26 Stress
strain diagrams characterize material properties.

38

CHAPTER 1 OFFSHORE OVERVIEW

REFERENCES American Petroleum Institute, 2009. Design, Construction, Operation and Maintenance of Offshore Hydrocarbon Pipelines (Limit State Design). API-RP 1111. American Petroleum Institute, Washington, DC. American Petroleum Institute, 2019. Specification for Line Pipe, 46th ed. American Petroleum Institute, Washington, DC. Azar, J.J., Samuel, G.R., 2007. Drilling Engineering. PennWell, Tulsa, OK. Bai, Y., Bai, Q., 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA. Bennetzen, B., Fuller, J., Isevcan, E., Krepp, T., Meehan, R., Mohammed, N., et al., 2010. Extended-reach wells. Oilfield Rev. 22 (3), 4
15. Bourgoyne, A.T., Millheim, K.K., Chenevert, M.E., Young, F.S., 1991. Applied Drilling Engineering. Society of Petroleum Engineers, Richardson, TX. Cochran, S., 2003. Hydrate control and remediation best practices in deepwater oil developments. In: OTC 15255. Offshore Technology Conference, Houston, TX, May 5
8. Garrison, T.S., Ellis, R., 2018. Essentials of Oceanography, eighth ed. Cengage Learning, Boston, MA. Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX. Gur, T., Choi, J.W., Soyoz, S., Abadie, R.J., Barrios, A., 2009. Assessment of platform Cognac using instrumentation data. In: OTC 20132. Offshore Technology Conference, Houston, TX, May 4
7. Jackson, M.P.A., Hudec, M.R., 2017. Salt Tectonics: Principles and Practices. Cambridge University Press, Cambridge. Lach, J., McMillen, K., Archer, R., Holland, J., DePauw, R., Ludvigsen, B.E., 2005. Integration of geologic and dynamic models for history matching, Medusa field. In: SPE 95930. SPE Technology Conference and Exhibition, Dallas, TX, October 9
12. McAllister, E.W., 2014. Pipeline Rules of Thumb Handbook, eighth ed. Gulf Professional Publishing, Waltham, MA. Menon, E.S., 2011. Pipeline Planning and Construction Field Manual, Gulf Professional Publishing, Waltham, MA. Mitchell, R.F., Miska, S.Z., 2011. Fundamentals of Drilling Engineering. Society of Petroleum Engineers, Richardson, TX. Nogueira, A.C., McKeehan, D.S., 2005. Design and construction of offshore pipeline. In: Chakrabrarti, S. (Ed.), Handbook of Offshore Engineering. Elsevier, Kidlington, Oxford, pp. 891
937. Okaguchi, S., Makino, H., Hamada, M., Yamamoto, A., Ikeda, T., Takeuchi, I., et al., 2004. Development and mechanical properties of X120 line pipe. Int. J. Offshore Polar Eng. 14 (1), 29
35. Palmer, A.C., King, R.A., 2008. Subsea Pipeline Engineering. PennWell, Tulsa, OK. Salvador, A., 1987. Late Triassic-Jurassic paleogeography and origin of Gulf of Mexico basin. Am. Assoc. Pet. Geologists Bull. (11), 1
14. Snedden, J.W., Galloway, W.E., 2019. The Gulf of Mexico Sedimentary Basin: Depositional Evaluation and Petroleum Applications, Cambridge University Press. Cambridge. Stevens, R.S., May, D., 2007. Piping and pipelines. In: Arnold, K.E. (Ed.), Facilities and Construction Engineering, Vol III. Petroleum Engineering Handbook. Society of Petroleum Engineers, Richardson, TX, pp. 318
394. Tuohy, J., Loper, C., Wang, D., 2001. Offloading systems for deepwater developments: Unbonded flexible pipe technology is a viable solution. In: OTC 13205. Offshore Technology Conference, Houston, TX, April 30
May 3. Vann, A., 2018. Offshore oil and gas development: legal framework. RL33404. Congressional Research Service. Washington, D.C.

CHAPTER

FLOW ASSURANCE ISSUES

2

One of the most important design issues for offshore pipelines in deepwater are the operational hazards associated with multiphase fluid transportation. These issues usually do not arise in shallow water where water temperatures are higher and hydrostatic pressures are lower, and so a new engineering discipline was essentially created when operators started to develop deepwater fields. Wax, hydrates, and asphaltenes are the three main threats to flow assurance. Hydrate problems are nearly universal in deepwater production, while the extent of wax and asphaltene varies widely between projects. Hydrate blockages are most common in gas and gas condensate systems but can also occur in oil systems. Subsea systems are designed to foresee the problems that may arise during all stages of production over its lifetime, but prognostications are uncertain and unanticipated issues may arise that were not considered in the design. Flow assurance is a major design consideration for subsea wells.

2.1 FLOW PATTERNS During production, oil and gas flows from the reservoir to the processing facilities and then onward to their sales destination through different channels and restriction points beginning at the rock pores, through well perforations and tubing, production chokes, valves, and pipelines on the ocean floor to topsides equipment for processing, before returning to the seafloor via pipeline or to a shuttle tanker.

2.1.1 RESERVOIR TO WELL BOTTOM Hydrocarbon fluids flow through a porous media, the reservoir, to the well perforations. Fluids close to the perforation flow first, followed by more distant fluids which take greater time to transit the spaces between the rocks which hold the hydrocarbons. Operations are designed to produce for as long as possible above critical reservoir pressures referred to as the bubble point and dew point pressures, since at these thresholds additional (usually unwanted) changes occur in the reservoir that negatively impact production. For oil reservoirs, if the reservoir pressure falls below bubble point, the multiphase flow will reduce well productivity by reducing oil relative permeabilities. In gas reservoirs, when reservoir pressure falls below critical dew point, condensates will drop out in the reservoir, reducing flow paths and production rates, leaving behind hydrocarbons that are not producible.

The Offshore Pipeline Construction Industry. DOI: https://doi.org/10.1016/B978-0-12-820288-3.00002-0 © 2020 Elsevier Inc. All rights reserved.

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40

CHAPTER 2 FLOW ASSURANCE ISSUES

2.1.2 WELL BOTTOM TO WELLHEAD Tubing conducts the wellbore fluids to the wellhead and tree. Trees at the mudline are called wet trees and trees above the waterline are called dry trees. Wellheads may be on the seafloor or located on the platform. Large tubing strings allow large initial production but may create liquid loading and high well abandonment pressure late in the field life and may need to be replaced. For dry tree wells, production fluids transit the water column protected by conductor pipe or production riser. For wet tree wells, flowlines transport production to platform facilities and a riser brings the fluids to the host, sometimes aided with gas lift at the base of the riser.

2.1.3 FLOWLINE FLOW Flowlines usually move uphill to their destination, but downhill movement can be accommodated with additional engineering. Fluids from multiple wells may be commingled to reduce the number of flowlines and risers, but commingling fluids can present problems if fluid chemistries change during production. Flowlines may be insulated, buried, heated, or uninsulated depending on multiphase flow transport and phase equilibrium of the fluids along the well path. Flowlines are sized to ease operational difficulties for the life of the well, and fluid chemistry, well pressures, and subsea conditions will determine if chemical injection is required to mitigate the onset of hydrates, asphaltenes, paraffins, scale, or corrosion. Heat management is a primary design variable. When oil, gas, and water are flowing simultaneously inside a deepwater pipeline, several problems may arise: • • • • •

Water and hydrocarbon fluids can form hydrates and block the pipeline. Wax and asphaltene can deposit on the wall of the pipeline and reduce and/or block flow. Corrosion may occur if water cuts are high and/or impurities exist in the hydrocarbon fluids. Scales may form due to pressure and temperature changes along the pipeline or from incompatible crude mixing. Slugging may occur and cause operational problems.

Engineers are tasked with designing pipeline systems to safely and economically transport well production to downstream processing facilities. They need to identify, quantify, and mitigate the flow risk and ensure pipelines remain operational during all stages of operation (start-up, normal operations, shutdown, re-start-up, and production) for the life of the field (Amin et al., 2005). Along the flow path, the produced fluids pressures and temperatures decrease, which will change the phase equilibrium and flow behavior of the fluids. Problems may occur at any time. Wax, asphaltenes, hydrates, scale, corrosion, and sand production need to be understood and managed throughout the life cycle of production for successful operations.

2.1.4 EXPORT PIPELINE FLOW On a production platform, hydrocarbon fluids are separated into gas, oil, and water phases to meet pipeline export specifications on vapor pressure, water vapor, heating value, and other properties, and regulatory conditions on water discharge. This greatly facilitates reliable flow in the downstream systems. Raw fluids are separated into oil and gas streams, dehydrated, processed, and temperature controlled before injection into the export oil and export gas lines. The export lines usually connect with existing pipeline infrastructure and may require compression and pumping along its route. Condensate production may be reinjected into gas export lines. Drying the gas to pipeline specification effectively eliminates hydrate formation.

2.2 DESIGN ISSUES

41

FIGURE 2.1 Schematic of an oil phase diagram from reservoir to flowline. Modified from Amin, A., Riding, M., Shepler, R., Smedstad, E., Ratulowski, J., 2005. Subsea development from pore to process. Oilfield Rev. Spring 2005 17 (1), 4
17.

2.1.5 OIL PHASE DIAGRAM Depending on the design and operation of an offshore project, one or more phase boundaries may be crossed. A schematic of an oil phase diagram shows the possibilities as the oil follows a path along a steadily decreasing temperature and pressure as it moves from the reservoir into the wellhead and flowline (Fig. 2.1). Temperature and pressure drops may cause asphaltenes to separate from solution when the oil crosses the upper edge of the asphaltenes precipitation envelope (upper APE). Wax begins to form as the oil falls below the wax appearance temperature (WAT) line, and then the hydrate range is entered before crossing the bubble point line. Below the bubble point, lighter hydrocarbons evolve in the reservoir as gas to form a two-phase fluid before reaching the flowline. Once in the flowline, the oil is transported to the host where temperature gradients in the ocean impact fluid flow.

2.2 DESIGN ISSUES The primary flow assurance issues for subsea systems are hydrate, wax, asphaltene, scale, and corrosion. Each of these components may occur at different places and at different times during the life cycle of production, and therefore, anticipating their occurrence and designing systems to mitigate, reduce, or remediate is the key element of flow assurance strategies. Hydrate, wax, and asphaltenes are the main threats and may arise downhole in the production tubing of the well, at the wellhead or manifold on the seabed, in the connecting jumpers or

42

CHAPTER 2 FLOW ASSURANCE ISSUES

flowlines, at the riser at the base of the host, and in the equipment and piping topsides. They may occur early or late in life and during different operating states from normal production, shutdown, start-up, and remediation. Start-up/warm-up and shutdown/cooldown are transient conditions where flowing temperatures change and may enter regions of hydrate risk and wax appearance. Systems must be robust and flexible to handle dynamic and changing conditions. Early in production, flow rates and temperatures are high, but later in life, flow rates and temperatures will decline. If systems are not designed for these changing conditions operational problems may occur. Early in production, fluid quality (viscosity, gas-oil ratio, water cut) is similar to the fluid samples obtained during well testing, but later in life, as reservoir pressures decline, fluid quality changes which may cause operational problems if unable to manage. In subsea production system design, a whole system modeling approach is used to define the hardware requirements and operating strategies (Arciero, 2017; Bomba et al., 2018; Kaczmarski and Lorimer, 2001). To optimize the system design, software models for each component are used to understand the tradeoffs that result from balancing steady-state and transient operations with flow assurance management: • •

•

•

Steady-state thermal and hydraulic conditions Transient operations • Warm-up • Cooldown • Blowdown • Hot oil heating Flow assurance management and remediation • Hydrate prediction and inhibition • Wax deposition • Asphaltene deposition • Scale prediction • Corrosion internal • Erosion Corrosion

The flow assurance work process begins with the development of a thorough understanding of the fluid and reservoir properties (Ellison et al., 2000; Joshi et al., 2017). A typical suite of analyses may include generation of hydrate stability curves, cloud point and pour point measurement, wax deposition patterns, asphaltene stability testing, and scale analysis based on water samples. Results of fluid and reservoir analyses are combined with thermal-hydraulic modeling of the system to assess the flow assurance risks. The formation processes for the solids of concern (e.g., hydrates, wax, asphaltenes, and scale) are all driven by a combination of temperature and pressure, hence the need for accurate thermal-hydraulic modeling of system performance in steady-state operations and during transient operations such as start-up and shutdown. Corrosion, erosion, slugging, and emulsion formation are often included in the flow assurance analysis since they are also driven by a combination of temperature and pressure, flow rate, and flow regime. The results of the flow assurance work process are expressed in the form of flow assurance strategies that combine elements of the system design, system operational strategy, and chemical treating requirements. Strategies vary greatly among projects because each development has a

2.2 DESIGN ISSUES

43

different set of driving factors of cost, project life, reliability targets, and environmental restraints. As a result, flow assurance must be integrated into the overall subsea systems engineering effort, not only to ensure that the analyses are performed at the correct time and desired accuracy, but also to integrate flow assurance with equipment selection and development of operational guidelines in a way that optimizes the project. EXAMPLE: FLOW ASSURANCE STRATEGY AT STONES Stones is a phased development that began producing in September 2016 from two subsea wells tied back to an FPSO in the Walker Ridge area in 9576 ft water depth. The development consists of a turret moored FSPO with a disconnectable buoy, which allows the FPSO to weather vane in normal operating conditions and be released in the event of a tropical storm or hurricane. Full field development includes six additional wells from two connected drill centers, and a subsea boosting system. With reservoirs located at depths of more than 29,000 ft, subsea boosting was identified in the original development plan as a means to enhance recovery due to rapidly decreasing reservoir pressures (Hagland et al., 2019). The project is characterized by high-pressure high-temperature reservoirs with low permeability, as well as by fluids with low gas-oil ratio, lower API grade and higher viscosity than typical Gulf of Mexico oil (Hoffman et al., 2017). Major flow assurance risks at Stones are mitigated as shown in Table 2.1. Table 2.1 Flow Assurance Strategies at the Stones Development Risk

Operation

Wellbore

Tree/Jumpers

Flowline/Risers

Hydrates

Production ( . 5 kbpd/FL) Unplanned shutdown Planned shutdown Cold start-up Production ( . 8 kbpd/FL) Production (,8 kbpd/FL) Unplanned shutdown Planned shutdown Cold start-up Asphaltenes (remediation) Scale (production) Corrosion (production) Erosion (production) Emulsion (production)

None MeOH bullheading MeOH bullheading Overrun hydrates None None None None None None SI inhibition None None None

None MeOH flush MeOH flush Inject MeOH None None None None None None None None None None

None Dead oil Dead oil Hot oiling None Hot oiling None None Hot oiling None None CI inhibition None None

Wax

Other

From Hoffman, J., Clausing, K., Robinson, S., Subramanian, P., Zummo, A. 2017. The Stones project: subsea, umbilical, riser and flowline systems. In: OTC 27569. Offshore Technology Conference. Houston, TX, May 1
4.

44

CHAPTER 2 FLOW ASSURANCE ISSUES

• • • •

Wax is mitigated by insulation, commingled hot oil, and paraffin inhibitor injection. Corrosion is mitigated by corrosion-resistant alloys and inhibitor injection. Hydrates are mitigated by heat retention and dead oil displacement for shutdowns. Scale is mitigated by downhole scale inhibitor injection and backup injection at the tree.

Emulsion and viscosity were deemed low to medium risks. Slugging, pour point, erosion, and asphaltenes precipitation/deposition were deemed low risks. Due to a lack of good fluid sample, a conservative approach was employed for hydrate and scale management.

Pipelines that transport crude may become fouled with organic scale, and the paraffins, asphaltenes, and naphthenates contained within the oil may precipitate and adhere to the pipeline walls. Corrosion may occur underneath these organic deposits. Pipelines that transport gaseous products may form organic-scale deposits from the condensed hydrocarbon fluids. If moisture is present in a sour environment, sulfide scales may form. More complicated issues may arise from mercury, arsenic, zinc, or other scales (Wylde and Slayer, 2010). Scales can be compacted and adhere to the walls of the pipeline, necessitating the addition of surfactant-based chemicals to assist in the breakup, softening, and transportation of these deposits (Cordell and Vanzant, 2003).

2.3 HYDROCARBON COMPONENTS Hydrocarbons have different physical and chemical characteristics that give rise to different flow characteristics. Understanding the properties of the fluids is necessary to design a successful flow assurance strategy.

2.3.1 HYDRATES Hydrates are ice-like solids classed as clathrates, sometimes referred to as “dirty snow” (Fig. 2.2), which form when water and light hydrocarbons or other small compounds are present together at low temperatures and high pressures (Cochran, 2003). In the Gulf of Mexico, annual surface seawater temperatures vary from 70 F to 85 F. Temperatures decrease rapidly with water depth and seasonal effects become less pronounced so that at 1000 ft temperatures vary from about 50 F to 55 F (Fig. 2.3). At 3000 ft, temperatures reach 40 F. Ambient temperatures near the seabed are well within the hydrate formation region at typical operating pressures for both oil and gas systems, and thus hydrates are a significant issue for all flowline designs in deepwater. In hydrates, a gas molecule is trapped within a hydrogen-bonded cage of water molecules (Fig. 2.4). Many different gases can form hydrates provided the molecules are small enough to fit within the cavity of the cage. High molecular weight gases are typically too large to form hydrates, but methane, ethane, propane, and butane, as well as N2, CO2, and H2S are small enough to fit inside. The crystalline structure of gas hydrate crystals depends on gas composition, pressure, and temperature.

FIGURE 2.2 Hydrates (top) and wax (bottom) removal in pipeline. 100 90

Temperature (°F)

80 70 60 50 40 30

0

1000

2000 Water depth (ft)

3000

4000

FIGURE 2.3 Seawater temperatures in the Gulf of Mexico across all seasons. From Bai, Y., Bai, Q., 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA.

46

CHAPTER 2 FLOW ASSURANCE ISSUES

FIGURE 2.4 Cartoon showing the molecular representation of cages for gas hydrates. From MIDAS, https://www.eu-midas.net/science/gas-hydrates.

FIGURE 2.5 Conceptual schematic of hydrate plug formation in pipeline for oil dominated system. From Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

Natural gas hydrates are composed primarily of water and, therefore, have many physical properties similar to ice. A conceptual schematic of hydrate plug formation in the pipeline for an oil dominated system is shown in Fig. 2.5. Hydrate formation and dissociation curves are used to define pressure/temperature relationships in which hydrates form and dissociate (Fig. 2.6). The curves can be generated by laboratory experiments or thermodynamic software. To the right of the dissociation curve, hydrates do not form and operating in this region is safe from hydrate blockage. To the left of the hydrate formation curve, hydrates are thermodynamically stable and have the potential to form. The hydrate dissociation curve may be shifted toward lower temperatures by adding a hydrate inhibitor such as methanol, glycols or sodium chloride (Box 2.1). Control of hydrates relies on keeping the system conditions out of the region in which hydrates are stable.

FIGURE 2.6 Hydrate stability curve for a typical Gulf of Mexico gas condensate. From Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

BOX 2.1 HAMMERSCHMIDT EQUATION The hydrate dissociation curve may be shifted toward lower temperatures by adding a hydrate inhibitor such as methanol, glycols, or sodium chloride. Hammerschmidt suggested a simple formula to estimate the temperature shift of the hydrate formation curve: ΔT 5

KW ; Mð100 2 WÞ

where ΔT is the temperature shift ( C); K is a constant depending on the inhibitor, for example, K is equal to 2335 for MeOH, 2700 for MEG, and 5400 for TEG; W is the concentration of the inhibitor in weight percent in the aqueous phase; and M is the ratio of the molecular weight of the inhibitor to the molecular weight of water. For a 20% weight fraction, Fig. 2.7 shows the effect of typical thermodynamic inhibitors on hydrate formation. Methanol has a higher temperature shift than that of glycols, but volumes are often limited by pipeline export specifications, whereas MEG has lower volatility and may be recycled. Salt is a very effective hydrate inhibitor on a weight basis which may be contributed in part by produced water and brine.

FIGURE 2.7 Gas hydrate curves with different amount of methanol inhibition. From Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

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CHAPTER 2 FLOW ASSURANCE ISSUES

Hydrates require certain conditions to form, namely: • • •

high pressure and low temperature; a gas component; and water in sufficient amount.

Therefore, prevention of hydrates attempts to reduce or prevent one or more of these conditions via: • • • • •

water removal; insulation or heating to maintain a temperature high enough to operate within the hydrate-free zone; operate at sufficiently low pressure; use thermodynamic hydrate inhibitors such as methanol or monoethylene glycol (MEG); use low-dose hydrate inhibitors (LDHI) such as kinetic hydrate inhibitors (KHI) or antiagglomerates (AAs).

Thermodynamic inhibitors suppress the point at which hydrates form much like antifreeze for water ice, while KHIs interfere with the kinetics of hydrate formation and AAs allow hydrates to form but only as a slush-like transportable material. KHIs bond with the hydrate cage and slow crystal growth. The more severe the hydrate problem the more inhibitor is required, and production facilities can reach a limit rate of methanol treatment due to storage and injection constraints (Kopps et al., 2007). In recent years, LDHIs have been the most prominent advance in hydrate inhibitors. For gas systems, the typical approach for hydrate control has been to rely on continuous dosing with glycol or methanol. MEG may be recovered and recycled more easily than methanol but cost two to three times more per unit volume ($2.5/gal vs $1/gal). Typically, methanol systems start out cheaper, but with longer field life becomes more expensive. Methanol treatment rates for hydrate control are on the order of one barrel of methanol per barrel of produced water. LDHI may be able to accomplish the same take at 1% dosage rates. For oil systems, insulation that maintain temperatures above the hydrate formation temperature during steady state allow hydrates to be controlled with minimum usage of glycol or methanol (Box 2.2). During shutdowns and start-ups, the system drops below the hydrate temperature and additional operational steps are required such as pressure relief (blowdown) or removal of wet fluids by pigging during shutdown, and circulation of hot oil and methanol dosing during start-up.

BOX 2.2 FLOWLINE FISHING AND CLEANOUT COST AT NANSEN The Nansen spar resides in 3670 ft water depth in the East Breaks protraction area in the Gulf of Mexico. A twin spar structure, Boomvang, lies a few miles to its east. In the North Nansen field, three subsea wells comprise a loop system with 6-in insulated production flowlines, 6-in flexible risers, and 4-in umbilical lines (Fig. 2.8). In 2005, three years after first production, several umbilical lines became plugged, preventing chemical injection to prohibit hydrate and paraffin buildup. In December 2008, the operator decided to separate the flow of Wells 1 and 2 to optimize production between the flowlines. By flowing Well 2 with Well 3 up the B1 flowline, the high volumes of gas from Well 3 would help Well 2 flow at a more stable rate. This was accomplished, but when Well 2 was switched to the other flowline, its methanol content was no longer available to Well 1. During a choke failure on Well 1, the well was shut in for 2 days, and obstruction was observed in the flowline during start-up. The methods used in the past to disassociate and depressurize the hydrates were not successful, requiring mechanical intervention. A coiled tubing (CT) intervention was selected for the cleanout (Ford et al., 2011). (Continued )

2.3 HYDROCARBON COMPONENTS

49

BOX 2.2 (CONTINUED) PLEM B2 EB 602 No. 9 Manifold

4.89-in NW Nansen main umbilical 15781 ft 6-in East flowline 9782 ft insulated

6-in Flowline B2 9779 ft insulated

Well 1 6-in Flowline B1 9512 ft insulated Umbilical and flowline crossings ×9

Well 2

PLEM B1

Well 3

4-in Nansen main umbilical BU 18840 ft 6-in Flex risers 5600 ft

6-in Flex risers 5048 ft insulated

Nansen spar

FIGURE 2.8 North Nansen field subloop system. From Ford, J.D., McDaniel, R., Barbee, G.P., 2011. HWO/Snubbing unit used effectively for subsea flowline fishing and cleanout at Nansen spar. In: SPE 143248. SPE/ICoTA Coil Tubing and Well Intervention Conference & Exhibition, Woodlands, TX, April 5
8.

The operator believed that hydrates caused the primary blockage in the flowline, but large amounts of paraffin had also become deposited on the walls of the flowlines and riser. During the cleanout, the CT became stuck 6244 ft into the flowline, and since it could not be freed, was cut at the surface. The operator estimated 36 total days to complete the job with 8 days for weather downtime and other contingencies. The total spread cost was estimated at $110,000 per day, and $4 million was budgeted for the operation. Rig up totaled 8 days, with 4 days due to weather-related downtime. The CT fishing operations required 16 days with 1-day downtime. The flowline cleanout took 16 days with 1-day downtime. Rig down totaled 3 days. The CT was cut and retrieved in two stages, which added working days above the operator’s estimate, and there were also unexpected problems encountered with rubber components and hoses in the equipment circulating 180 F diesel continuously. The contractor was able to secure a work boat for a lower price than anticipated, however, offsetting the longer work times and finished below budget at $3.3 million.

50

CHAPTER 2 FLOW ASSURANCE ISSUES

2.3.2 WAXES Waxes are complex mixtures of solid hydrocarbons, usually long-chain normal paraffins, but isoparaffins and naphthenes are also present with carbon chain lengths ranging from C18 to C75 and beyond, that freeze out when the temperature is lower than the cloud point of the crude (Speight, 1998). Waxes precipitate from petroleum fluid as the temperature falls below the WAT and deposit on the well tubing, pipeline or vessel (Fig. 2.2). If not under control, wax deposits may block the flow path completely. The formation of wax crystals depends mostly on temperature change. Pressure and crude composition also affect wax formation but to a lesser extent. The temperature at which crude oil develops a cloudy appearance due to its wax (paraffin) content precipitating out is called the WAT or cloud point. The pour point is defined as the lowest temperature crude oil flows. At the pour point, the fluid still pours under gravity, but at the next lowest temperature measurement (3 C lower), the fluid has gelled and does not pour. Both WAT and pour point are important design characteristics in subsea systems. If ambient and fluid temperatures are always above the pour point, no pour point strategy is required. In environments and operations where the ambient or fluid temperature is at or below the pour point, an operational strategy is required to maintain the flow ability of the fluid. Most operators rely upon pigging for control of wax deposition supplemented with inhibitors to reduce the deposition rate (Box 2.3). As system offsets increase, however, the cost of a dual flowline system is substantial, and the time required for round-trip pigging increases. Subsea pig launchers can be employed with a single line but incur the cost of intervention vessels. Wax deposition can be prevented, delayed, or minimized using paraffin inhibitors such as crystal modifiers or dispersants. The former are chemicals that interact with the growing wax crystallization while dispersants prevent the wax nuclei from agglomerating on the pipe surface by disrupting its crystal growth.

BOX 2.3 PIGGING AT AZERI-CHIRAG-GUNASHLI (A PIG A DAY HELPS. . .) The supergiant Azeri-Chirag-Gunashli oil field lies in the Azerbaijani sector of the south Caspian Sea (for additional background see Box 4.2). Partially stabilized oil is exported to Sangachal onshore oil terminal via two 30-in diameter pipelines with a separate oil export pipeline for Chirag (Stevenson et al., 2015). Most of the pipeline is at a water depth less than 50 m (Fig. 2.9), where the ambient temperature varies seasonally from 10 C to 25 C, exceeding 15 C from May through October. In deeper water, from 50 to 200 m, the temperature range narrows to 6 C 6 3 C. At 200 m, the temperature is 6 C year-round. The Azeri-Chirag-Gunashli crude has a high waxing tendency in the east part of the field and most wax was expected to occur in the first 20 km of the line where the thermal gradient was highest. Daily pigging is required to control the thickness of the deposited wax and maintain the hydraulic capacity of the lines. At the start of operations, it became difficult to maintain regular pigging because of issues related to the pig launchers, and the extended interval between pigging led to two significant upsets (Fig. 2.10). A remedial pigging program employed hydraulic modeling to infer the volume of wax from measured differential pressure, and a wax modeling approach was used to predict wax volume using fluid properties, pressure, and temperature profiles in the pipeline (Aslanov et al., 2019). (Continued )

BOX 2.3 (CONTINUED)

FIGURE 2.9 Topography of the export pipeline from Central Azeri platform to Sangachal, Azerbaijan. Adapted from Stevenson, C.J., Davies, S.R., Gasanov, I., Hawkins, P., Demiroglu, M., Marwood, A.P., 2015. Development and execution of a wax remediation pigging program for a subsea oil export pipeline. In: OTC 25889. Offshore Technology Conference, Houston, TX, May 4
7.

FIGURE 2.10 Operators manually removing wax from the pig receiver during the first wax incident. From Stevenson, C.J., Davies, S.R., Gasanov, I., Hawkins, P. Demiroglu, M., Marwood, A.P., 2015. Development and execution of a wax remediation pigging program for a subsea oil export pipeline. In: OTC 25889. Offshore Technology Conference, Houston, TX, May 4
7.

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CHAPTER 2 FLOW ASSURANCE ISSUES

In contrast to hydrates, wax deposits slowly and can be controlled by controlling the system temperature and temperature differential at the pipe wall (Box 2.4). Cloud points for deepwater Gulf of Mexico crude oils generally range from 80 F to 100 F, and if the system is operated at a temperature 10 F to 20 F above the cloud point, wax will not deposit. In marine wellbores and trees, this can usually be achieved, but it is not possible to operate at such high temperatures in flowlines. During late life, reservoir temperatures will have also dropped, and host arrival temperature may be below the cloud point leading to significant deposition (Fig. 2.11).

BOX 2.4 WAX DEPOSITION MODEL The ability to predict the rate of wax deposition is important in subsea design because it determines the wax buildup rate and pigging frequency needed in operations. When crude oil is flowing in an offshore pipeline, the temperature at the center of the pipe is hottest and the inside wall is coldest, creating a radial temperature gradient that will produce a concentration gradient of wax that is highest at the pipe wall. Mass transfer of wax from the crude at the center of the pipe to the pipe wall occurs by molecular diffusion. Wax mass transfer is described by Fick’s law of molecular diffusion: dm dC 5 ρDm A ; dt dr where m is the mass of the wax deposit on the pipe wall (kg), t is the time (s), ρ is the density of solid wax (kg/m3), Dm is the molecular diffusion coefficient (m2/s), A is the deposition area (m2), C is the wax concentration (%), and r is the radial position (m). The diffusion coefficient is often expressed as an inverse function of oil viscosity, D 5 K/υ, where υ is the dynamic viscosity and K is adjusted to match experimental data (Bai and Bai, 2019). The radial concentration gradient is calculated by applying the chain rule, dC @C dT 5 dr @T dr

Pressure

and using the wax concentration predicted by a thermodynamic model for a range of temperatures. Wax deposition models require the prediction of cloud point temperature and the rate of deposition on the pipe wall. Cloud point temperature is accurately predicted using thermodynamic models and laboratory methods. The rate of wax deposition depends on a thermodynamic model for wax in oil and a diffusion rate model, neither of which provide satisfactory results at the present time.

Wax formation

se pha d gle n i flui S oir v r e Res

Bubble point Tw o-p

has

e has t le p poin g n d Si u lo Oc ST No wax

e

Temperature

FIGURE 2.11 Typical wax forming regions as a function of reservoir temperature and pressure. From Bai, Y., Bai, Q., 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA.

2.3 HYDROCARBON COMPONENTS

53

FIGURE 2.12 Asphaltene molecular structures.

2.3.3 ASPHALTENES Asphaltenes are dark-colored, friable and infusible hydrocarbon solids sometimes called the “cholesterol” of petroleum. Asphaltenes originate from the complex molecules found in plants and animals which have only been partially broken down over geologic time (Kaiser et al., 2020; Speight, 1998). Asphaltenes carry the bulk of the inorganic components of crude oil, including sulfur and nitrogen, and metals such as nickel and vanadium. Defined as the fraction of crude which precipitates upon the addition of an excess of n-alkane, the diversity of asphaltene production issues arise from the variety of oil types and production conditions. Asphaltenes are represented by the polynuclear aromatic layers with folded alkane chains, creating a solid structure known as a micelle. Some rings may be nonaromatic but many are fused and share at least one side (Fig. 2.12). The tendency of asphaltenes to precipitate from a given crude is broadly related to the molecular weight, aromaticity, and polarity of the asphaltenes. In general, asphaltenes cause few operational problems since most asphaltic crude oils have stable asphaltenes. Asphaltenes only become a problem when they are unstable (Wang et al., 2003). Asphaltene stability is a function of the ratio of asphaltenes and saturates (unfavorable components) to stabilizing factors such as aromatics and resins (favorable components). Pressure is the factor with the largest impact on asphaltene stability. Asphaltenes may also be destabilized by certain types of completion fluids, acids in workovers, and blending crude oils. Asphaltenes are common in heavy viscous crude and are usually controlled using inhibitors before destabilization and flocculation occurs (Jamaluddin et al., 2002, Tavakkoli et al., 2016). After destabilization remediation is much more difficult to control (Mullins et al., 2007). Asphaltene deposition tends to occur above the bubble point, concentrating the hazard to the wellbore and wellbore formation, and occasionally to the wellhead or flowline. Below the bubble point, asphaltene solids tend to redissolve but the process can be slow and incomplete. Chemical treatment is the most common and effective method for control but much of the underlying chemistry remains uncertain. Prescreening criteria to evaluate the potential for asphaltenes formation include the use of the de Boer plot and subsea safety valve analysis (Box 2.5).

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CHAPTER 2 FLOW ASSURANCE ISSUES

The de Boer plot evaluates the loss of asphaltenes solubility as a reservoir fluid sample is depressurized and indicates regions that are likely, uncertain, and unlikely to precipitate asphaltenes. In the resin-to-asphaltene (RTA) ratio plot, statistical rules are used to evaluate the ratio required to keep the asphaltenes stable. For RTA , 1.5, asphaltenes are expected to be unstable during expansion of oil, RTA . 2.5 indicate the stable region, and 1.5 , RTA , 2.5 is the transition zone.

BOX 2.5 ASPHALTENE PRECIPITATION AND DE BOER PLOTS Asphaltenes are defined as those compounds in oil that are insoluble in n-pentane or n-hexane but are soluble in toluene or benzene. Unlike waxes, asphaltenes are brittle and hard and will not melt, but they tend to flocculate and deposit like waxes inside well tubing and flowlines with changes in pressure, temperature, and crude composition. When the reservoir pressure is above the bubble point of the crude, the fluid composition is constant, and the solubility of asphaltenes is due to the pressure decline. Below the bubble point, gases evolve from the crude and oil density increases, and during this period asphaltene solubility is impacted by changes in oil composition. Asphaltene solubility is minimum at the bubble point, which is generally the area of greatest concern for asphaltene instability (Fig. 2.13).

FIGURE 2.13 Pressure dependence of asphaltene solubility in crude oil. From Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

In 1995 de Boer published a simple method for screening crude oils on their tendency for asphaltene precipitation (De Boer et al., 1995). An asphaltene supersaturation plot, now called the de Boer plot, graphs the reservoir pressure minus the bubble point pressure on the y-axis, and the in situ crude density on the x-axis (Fig. 2.14). For a given crude and reservoir conditions, the figure allows the risk level of asphaltene precipitation during production to be quickly assessed. (Continued )

2.3 HYDROCARBON COMPONENTS

55

BOX 2.5 (CONTINUED)

FIGURE 2.14 de Boer crude oil asphaltene supersaturation plot. From Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

Another ratio in common use is the colloidal instability index (CII), defined as the ratio of the unfavorable components in the oil to asphaltene stability to the favorable components: CII 5

S 1 As R 1 Ar

where S, As, R, and Ar are the percentages of saturates, asphaltenes, resins, and aromatics, respectively. If CII . 1, the unfavorable components dominate and asphaltenes are likely to be unstable. In Haghshenas et al. (2016), models were developed to correlate the onset of asphaltene precipitation with the refractive index of dead crude oil.

2.3.4 RESINS Resins are polar molecules that are insoluble in liquid propane but are soluble in n-heptane. Resin molecules surround the asphaltene clusters and suspend them in crude oil and are believed to be responsible for dissolving and stabilizing the solid asphaltene molecules in petroleum (Mullins et al., 2007).

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CHAPTER 2 FLOW ASSURANCE ISSUES

FIGURE 2.15 Crude oil is separated into saturates, aromatics, resins and asphaltenes fractions for characterization.

SARA analysis is a chemical procedure that describes the percentage of crude oil as the fractions saturates, aromatics, resins, and asphaltenes (Fig. 2.15). Saturates contain the saturated aliphatic components (linear, branched, and cyclic) with an H/C ratio of nearly two. Aromatics contain one or more polarizable aromatic rings usually with no more than three rings total. Resins and asphaltenes contain polar substituents with asphaltenes being insoluble in excess of n-alkanes and resins being soluble. The SAR fraction of SARA is usually referred to as maltenes. Different methods used in SARA analysis will lead to different results, so the procedures applied need to be described when reporting results.

EXAMPLE: SARA ANALYSIS FOR HEAVY CRUDES Typical SARA component range for light crude is 60
75 wt% saturates, 20
25 wt% aromatics, 4
14 wt% resins, and 0.1
0.2 wt% asphaltenes (Tavakkoli et al., 2016). In heavily degraded oils, there is usually a shortage of resins and aromatics and a surplus of asphaltenes. Extra-heavy oils may contain $ 40 wt% resins and asphaltenes content (Table 2.2). Normal crude with API gravity greater than 20 API typically has high saturates content and much less than 20 wt% resins and asphaltenes.

2.4 HYDRATE MANAGEMENT TECHNIQUES

57

Table 2.2 Heavy Crude Oils and Their Properties API Sulfur (%)

Boscan

Belridge

Green Canyon

Hondo

Atkinson

10.9 5.5

13.6 1.0

19.5 1.9

19.6 4.3

22.9 1.88

8.83 3 106 4.85 3 105

9.26 3 104 1.26 3 104

514 177

3507 735

790 164

25 35 22 18

28 39 30 3

38 40 14 8

33 31 24 12

44 30 17 9

117 1320

70 86

29 106

75 196

49 112

Viscosity (cSt) 0 C 15 C SARS (wt%) Saturates Aromatics Resins Asphaltenes Metals (ppm) Ni Vn

2.4 HYDRATE MANAGEMENT TECHNIQUES As described in Section 2.3.1, hydrates of hydrocarbon require four conditions to form and be stable: high pressure, low temperature, water, and gases. To control hydrate formation and stability, one or more of these conditions need to be controlled. Hydrate management is often used in conjunction with wax management, and the solutions for gas and oil systems depend on site-specific conditions and operator preferences. Each approach has different capital requirements and operating expenses.

2.4.1 DEPRESSURIZATION Pressure control is a common method to remain outside the hydrate formation region during shutdown. If the fluids are at a pressure lower than the hydrate stability pressure, hydrates would not be stable. If hydrates form in the production system, depressurization to below the hydrate stability pressure would dissociate the restriction (Makogon and Makogon, 2016). Chemical injection of MEG or methanol is required during the restart phase while the pressure in the line increases. Down sloping geometry at the riser base or a low gas to liquid ratio will complicate the operation if the riser remains in the hydrate zone. In deepwater, the hydrostatic pressure of liquids in the riser may be sufficiently high to maintain hydrate stability at the mudline even if the topsides facility pressure is reduced to atmospheric pressure. In this case, chemical injection may be required inside the riser or at the wellbore or pumps may be employed.

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CHAPTER 2 FLOW ASSURANCE ISSUES

2.4.2 INSULATION The objective of insulation is to prevent the produced fluids temperature from dropping below the hydrate and/or wax appearance temperature by limiting heat exchange with the environment. For short tie-backs and high temperature no insulation may be needed, but during shutdown, the temperature is maintained only for a limited time before entering the hydrate/wax region. In degraded production conditions (e.g., mature production) or low-quality fluids (e.g., viscous), problems may develop. Burial is an option if the seabed can be trenched. Pipe-in-pipe and active heating will improve temperature performance but at a significant increase in capital and operating expense.

2.4.3 DEHYDRATION Dehydration reduces the amount of water for hydrates, and is performed topsides on offshore facilities on all oil and gas export streams for flow assurance. Subsea dehydration technologies are not yet mature or commercial.

2.4.4 LOOP ARRANGEMENT If depressurization with chemical injection cannot protect against hydrates formation, a loop arrangement that displaces the live hydrocarbons with dead crude (or diesel) may be employed. Dead crude (also called nonshrinkage oil) refers to crude oil where most of the associated gas and high vapor pressure components have been removed. In some cases, a service line with dead crude in-place or stored aboard the facility may be used. Loops provide operational flexibility and allow round-trip pigging from topsides, but capital expenditures are high, especially as distances increase.

2.4.5 CONTINUOUS CHEMICAL INJECTION Continuous chemical injection of MEG or methanol act by decreasing the hydrate formation conditions to lower temperatures and higher pressures. Chemical methods of hydrate control require less upfront capital expenditures but have high operating costs during the life of the field because most chemicals cannot be recycled or reused. If the quantity of water to be inhibited is large, the amount and expense of chemical usage is usually unrealistic, and therefore continuous injection is often used in conjunction with other methods. For lean gas fields, continuous chemical injection is common.

2.4.6 HEATING Direct electrical heating and active heated flowline bundles use hot water circulation and electric wires to heat the pipeline above the wax and hydrate appearance temperatures. Heated pipe technologies have been used to reach longer tie-back distances and greater water depth, but they are not common because of their expense and additional operational complexity.

REFERENCES

59

REFERENCES Amin, A., Riding, M., Shepler, R., Smedstad, E., Ratulowski, J., 2005. Subsea development from pore to process. Oilfield Rev. Spring 2005 17 (1), 4
17. Arciero, B., 2017. Optimization of flow assurance applications through life-of-field: an integrated approach to production engineering and chemical management across Gulf of Mexico deepwater assets. In: OTC 27560. Offshore Technology Conference, Houston, TX, May 1
4. Aslanov, H., Novruzov, A., Harun, A., 2019. Managing wax-deposition risks in the oil subsea pipelines by integrating wax modeling and pigging performance. In: SPE 194506. SPE Production & Operations. Bai, Y., Bai, Q., 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA. Bomba J., Chin D., Kak A., Meng W., 2018. Flow assurance engineering in deepwater offshore
past, present, and future. In: OTC 28704. Offshore Technology Conference, Houston, TX, April 30
May 3. Cochran, S., 2003. Hydrate control and remediation best practices in deepwater oil developments. In: OTC 15255. Offshore Technology Conference, Houston, TX, May 5
8. Cordell, J., Vanzant, H., 2003. Pipeline Pigging Handbook. Clarion Technical Publishers, Houston, TX. De Boer, R.B., Leerlooyer, K., Eigner, M.R.P., van Bergen, A.R.D., 1995. Screening of crude oils for asphalt precipitation: theory, practice, and the selection of inhibitors. SPE Proc. Facil 10 (1), 55
61. Ford, J.D., McDaniel, R., Barbee, G.P., 2011. HWO/Snubbing unit used effectively for subsea flowline fishing and cleanout at Nansen spar. In: SPE 143248. SPE/ICoTA Coil Tubing and Well Intervention Conference and Exhibition, Woodlands, TX, April 5
8. Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX. Haghshenas, M., Balashanmugam, S., Gonzalez, D., Pietrobon, M., 2016. Prediction of asphaltene onset pressure from dead oil stability. In: OTC 27569. Offshore Technology Conference, Houston, TX, May 2
5. Hagland, A.S., Skaar, J.C., 2019. Stones
the world’s first 15 ksi ultra-deepwater subsea pump. In: OTC 29537. Offshore Technology Conference, Houston, TX, May 6
9. Hoffman, J., Clausing, K., Robinson, S., Subramanian, P., Zummo, A., 2017. The Stones project: subsea, umbilical, riser and flowline systems. In: OTC 27569. Offshore Technology Conference, Houston, TX, May 1
4. Jamaluddin, A.K.M., Nighswander, J., Joshi, N., Calder, D., Ross, B., 2002. Asphaltenes characterization: a key to deepwater development. In: SPE 77936. SPE Asia Pacific Oil and Gas Conference and Exhibition, Melbourne, October 8
10. Joshi, N.B., Li, Q., Champion, N., Kapadia, K., 2017. The relevance of chemistry in deepwater design and operations. In: OTC 27879. Offshore Technology Conference, Houston, TX, May 1
4. Kaczmarski, A.A., Lorimer, S.E., 2001. Emergence of flow assurance as a technical discipline specific to deepwater: technical challenges and integration into subsea systems engineering. In: OTC 13123. Offshore Technology Conference, Houston, TX, April 30
May 3. Kaiser, M.J., de Klerk, A., Gary, J.E., Handwerk, G.E., 2020. Petroleum Refining: Technology, Economics, and Markets, sixth ed. CRC Press, Boca Raton, FL. Kopps, R., Venkatesan, R., Creek, J., Montesi, A., 2007. Flow assurance challenges in deepwater gas developments. In: SPE 109670. SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, October 30
November 1. Makogon, Y.F., Makogon, T.Y., 2016. Chapter 15: Natural gas hydrates. In: Riazi, M.R. (Ed.), Exploration and Production of Petroleum and Natural Gas. ASTM International Manual, Mayfield, PA. Mullins, O.C., Sheu, E.Y., Hammami, A., Marshall, A.G., 2007. Asphaltene, Heavy Oils and Petroleomics. Springer Academic Press, New York.

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Speight, J.G., 1998. The Chemistry and Technology of Petroleum, third ed. Marcel Dekker, Inc., New York. Stevenson, C.J., Davies, S.R., Gasanov, I., Hawkins, P., Demiroglu, M., Marwood, A.P., 2015. Development and execution of a wax remediation pigging program for a subsea oil export pipeline. In: OTC 25889. Offshore Technology Conference, Houston, TX, May 4
7. Tavakkoli, M., Boggara, M., Garcia-Bermudes, M., Vargas, F.M., 2016. Asphaltene deposition: Impact on oil production, experimental methods, and mitigation strategies. In: Riazi, M.R. (Ed.), Exploration and Production of Petroleum and Natural Gas. ASTM International Manual, Mayfield, PA. Ellison, B.T., Gallagher, C.T., Frostman, L.M., Lorimer, S.E., 2000. The physical chemistry of wax, hydrates, and asphaltene. In: OTC 11963. Offshore Technology Conference, Houston, TX, May 1
4. Wang, J.X., Buckley, J.S., Burke, N.A., Creek, J.L., 2003 Anticipating asphaltene problems offshore
a practical approach. In: OTC 15254. Offshore Technology Conference, Houston, TX, May 5
8. Wylde, J.J., Slayer, J.L., 2010. Development, testing, and field application of a heavy-oil pipeline-cleaning chemical: a cradle-to-grave case history. SPE Projects, Facilities & Construction. March 22
30.

CHAPTER

FIELD DEVELOPMENT STRATEGIES

3

The development of offshore fields is a major undertaking and involves numerous technical challenges. The design, construction, and operation of offshore fields must meet stringent standards to ensure structural integrity, workforce safety, and protection of the environment. Pipeline requirements are closely associated with development strategy and operator preferences because the choices made in development have a direct impact on system architecture and construction activity. Only built projects are observed, however, and design tradeoffs encountered are usually not reported although in some cases can be inferred vis-a-vis the final development. The purpose of this chapter is to illustrate some of the factors that impact pipeline construction through a review of offshore oil and gas developments in the Gulf of Mexico. Hub platforms are arguably the most important structure class for commercial ventures because they provide transportation services and connection points into the existing pipeline networks which reduces capital spending and accelerates schedule.

3.1 SYSTEMS PERSPECTIVE Many different types of surface systems and subsea system designs are used in offshore oil and gas development, and the selection process depends on many different factors, the importance of which varies among projects and operator preferences. Field developments are subject to economic, engineering, technical, and regulatory requirements that are site, time, and location dependent. Engineers are responsible for designing reliable and safe systems while identifying the risk and tradeoffs involved in cost, safety, schedule, operations, and environment. The purpose of every offshore oil and gas pipeline is to transport fluid from one point to another, but differences in field location, water depth, development strategy, time of sanction, seafloor topography, ownership, and other factors mean that route selection and installed mileage will have complex site, time, and location dependencies. The stages of conceptual development, the processes involved, and the philosophies adopted have been described throughout the literature for many years. A good starting point are the papers by Dekker and Reid (2014) and Reid and Dekker (2014), and the references cited therein. Here, the focus is on pipelines and how pipelines enter the development selection. Offshore developments occur in a variety of water depths and environments with numerous subsurface conditions. The ability to understand the relationships between these requirements

The Offshore Pipeline Construction Industry. DOI: https://doi.org/10.1016/B978-0-12-820288-3.00003-2 © 2020 Elsevier Inc. All rights reserved.

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CHAPTER 3 FIELD DEVELOPMENT STRATEGIES

and the different types of systems is key to successful development. Different development systems fit specific requirements better than others, so a systems approach is generally required to successfully integrate subsurface and surface conditions. All systems, including well delivery, subsea systems, flowlines, structural systems, facilities, export, and operations, must be considered simultaneously. Tradeoffs are often fuzzy and include differences that arise from decisions regarding capital expenditures versus operational expenditures; standardization versus improvement; proven technology versus innovative technology; and minimum capacity versus future capacity.

EXAMPLE: TRADEOFFS IN THE WHO DAT DEVELOPMENT Two drill centers located in Mississippi Canyon 503 are being used to produce the Who Dat development (Fig. 3.1). A semisubmersible production unit that does not host a drilling rig was located on an adjacent lease downslope in deeper water in MC 547 (Simms et al., 2012). One of the MC 503 producing wells near the southwest corner bottoms on the MC 547 lease, and the export lines from the production unit are owned by third parties. a. Describe possible reasons why the operator chose to locate the semisubmersible so far away from the drill centers. b. How does the destination and ownership of the export lines enter in decision making? c. Quantify the flowline and umbilical cost savings if the semisubmersible was located midway between the two drill centers. Solution a. MC 547 is held by production by one of the MC 503 producing wells that bottom on the lease, so the production facility was not located to hold the lease for the operator. Since the semisubmersible does not host a drilling rig, it is not expected to participate in drilling or workover operations at its current location. Future drilling on MC 547 or in the vicinity of the host may have been a consideration in the selection of the host location, or other concerns not immediately obvious may play a role. b. Export destination, local terrain, and ease of installation may have been played a role in the facility siting decision. Since the operator does not own the export lines, the increased cost of a longer line will only enter the evaluation as an incremental (most likely negligible) increase in tariff rates charged by the transportation provider. c. If the semisubmersible was located midway between the two drill centers on MC 503, flowline distances to the facility would be smaller, and the flowline mileage would be reduced about 1.1 mi for each flowline, for total flowline mileage of 4.5 mi and umbilical mileage 2.2 mi, saving about $20 million if installed pipeline and umbilical cost $3 million per mile.

3.1 SYSTEMS PERSPECTIVE

63

FIGURE 3.1 Who Dat field layout and subsea manifolds in the Mississippi Canyon area. From BOEM.

64

CHAPTER 3 FIELD DEVELOPMENT STRATEGIES

3.2 CONCEPTUAL DEVELOPMENT 3.2.1 RESERVOIR GEOMETRY Reservoir sand distribution (pay zones) and the quality of the reservoirs impact field development in terms of wells required, flow rates, artificial lift requirements, equipment rating, and related elements. If the pay zones are visualized collectively as a rectangular box, then the geometry, size, and location of the box relative to the seabed and the composition and quality of the rock in the box will determine the number and type of wells required in development. If the reservoir rock is faulted creating isolated reservoirs or otherwise lacks communication with other zones, underlies salt, or has significant shale streaks, more wells will be required to access the targets compared to sands without faulting. If the box is vertically long and compact—think high-rise office building like One World Trade Center—with stacked sands, multiple zones, and small areal extent, then most targets within the box can be reached from one central position above the field using deviated wellbores and wells that are completed within multiple sands. Dry tree wells are usually the preferred least expensive option. Deviated wellbores are standard in offshore development and can be drilled from a central location up to 3
5 mi laterally, so for wells drilled from a platform, there is a zone three to five miles in radius centered at the platform that can be reached. For targets outside this distance, wet (subsea) wells will be required or another platform will need to be installed. If the reservoir is wider than it is thick and relatively shallow below the mud line—think shoebox or an aircraft manufacturing facility—or for noncontiguous reservoirs, it will be difficult to reach all the targets from one location, even with highly deviated wells. High-angle directional wells from one or more platforms and subsea wells will be adopted. Outside the 3
5 mi reach from a platform, if there is a target to be drilled or a reservoir to be developed, then either another platform needs to be installed or a MODU (mobile offshore drilling unit) is required to perform the drilling and the field tied back to the existing infrastructure.

EXAMPLE: POMPANO DEVELOPMENT In the Pompano development, a fixed platform was installed in 1290 ft water depth in Viosca Knoll block 989, and a subsea cluster was drilled in Mississippi Canyon block 28 about 4.5 miles away with production routed back to the VK 989 platform (Fig. 3.2). The longest reach development well drilled at the VK 989 platform is slightly greater than 3 mi as the reader can verify from the schematic, recalling that lease blocks are 3 mi square. All Phase II wells in MC 28 are subsea and tied back to the main facility (Willson et al., 2003). The longest reach Phase II well is about 1.5 mi horizontal offset. Field outlines in green and pink are the areal projection of oil and gas reservoirs.

3.2 CONCEPTUAL DEVELOPMENT

FIGURE 3.2 Pompano reservoirs and development well trajectories. From BOEM.

65

66

CHAPTER 3 FIELD DEVELOPMENT STRATEGIES

3.2.2 HUB PLATFORMS If a platform serves as a hub or pipeline junction, it will likely have more than two export lines departing the structure. Oil and gas export lines are sized for the maximum total well flow rates expected from the development, but if a tieback field (unanticipated or third party) is hosted at a later date, new export pipelines will be required if equipment capacity at the structure is exceeded. After production peaks, there will be spare pipeline (and equipment) capacity available that can be used for developing nearby fields as tiebacks, and therefore development timing is a determining factor. Export pipeline capacity is closely related to nameplate equipment capacity. It is common to install new export pipelines to hub platforms to handle streams from different fields and owners.

EXAMPLE: ENCHILADA APARTMENT COMPLEX LEASE ARRANGEMENT The Enchilada Garden Banks 128 platform in 193 m water depth is an example of a project justified as a stand-alone development, but it was recognized early in the decision cycle as having strategic value to the operator as a pipeline and processing hub supporting regional deepwater and subsea development (Smith and Pilney, 2003). Enchilada uses a unique lessor and lessee arrangement like an apartment complex where the operator (Shell) acts as the superintendent. Tenants gain rights to space by virtue of their capital investment, and the superintendent provides operating and maintenance services. Unlike a conventional development, in which each party pays a set working interest, surface expenses are allocated to the tenants depending on what the expense was and where it occurred.

3.2.3 FLOWLINE ARCHITECTURE Pipeline design is governed by throughput, installation, and site requirements and specified by industry practice and regulation. If one or more subsea wells are required to drain the target, for instance, the wells may be flowed individually back to the host, as shown in configuration SS1 in Fig. 3.3 (Beltrami and Hansen, 2016). Alternatively, the well fluids may be commingled, and a daisy-chain configuration used (SS2), or a loop system adopted to provide pigging capability (SS7) for oil-dominated systems. Wells may be drilled from a central template (SS3 and SS5), or production may be commingled at a manifold and sent back to the host via a single (SS4) or dual flowline (SS6). Subsea configurations are often designed fit for purpose, and complex tradeoffs exist between capital spending and operational flexibility (Bai and Bai, 2019).

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FIGURE 3.3 Subsea architecture illustrating radial, daisy-chain, loop, and hybrid configurations. Modified from Beltrami, F., Hansen, K., 2016. Truly sustainable building blocks for deepwater field development: the need for strategies re-definition in a persistently low oil price scenario? In: SPE 181707. SPE Annual Technical Conference and Exhibition, Dubai, UAE, September 26
28.

3.3 DEVELOPMENT STRATEGIES 3.3.1 FIELD ARCHITECTURE The world’s longest oil well subsea tieback c.2020 was the Penguin field in the North Sea at 43 mi, and the longest gas well tieback was the Tamar field in the Mediterranean Sea at 93 mi (see Fig. A.12 for world records c.2020). Gas is easier to flow longer distances and has less flow assurance issues because gas is less dense, less viscous, and has lower friction compared with pumping oil. Changes in pressure and temperature along the flowlines are important design considerations, and if production from multiple wells is commingled, there may be significant chemical interactions between the fluids, which must be understood.

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EXAMPLE: AUGER Auger was Shell’s first tension leg platform (TLP) in the Gulf of Mexico. Initial development consisted of 10 dry tree wells and first oil was achieved in April 1994. By mid-2000 field production was about half of equipment capacity, and remaining development and recompletion opportunities at the platform were not adequate to offset production decline (Brock, 2000). To keep the facility full, a decision was made to transform Auger into an infrastructure hub serving as a subsea tieback host for Shell fields and third-party production. In 1999 Macaroni was developed as a subsea tieback, and in late 2001 the Serrano and Oregano fields were brought online (Fig. 3.4). Cardamom was drilled from the TLP using extended reach wells. Third-party tiebacks Llano and Habanero northwest of Auger were integrated into the system in 2002. Macaroni uses a dual 6/10-in flowline system that uses methanol for hydrate inhibition. Both Serrano and Oregano use single 6/10-in electrically heated pipe-in-pipe flowline systems for oil and gas delivery. Habanero and Llano flow assurance strategies required the use of hydrate inhibitors.

FIGURE 3.4 Auger TLP subsea tiebacks Macaroni, Oregano, and Serrano c.2000. From BOEM.

Auger oil and gas export lines provide access to multiple markets via existing shallow water gathering systems at Garden Banks 128 (Enchilada) and Vermillion 397 platforms (Fig. 3.5). The 12-in oil line, owned and operated by Shell Pipeline Company LP, is routed to Shell’s Enchilada platform at GB 128 where oil can be delivered into multiple pipelines accessing different onshore market locations. One of the gas lines owned by Shell terminates at Enchilada and delivers into the Garden Banks Gas Pipeline System. The second gas line terminates at VR 397 and delivers to the ANR pipeline system (Kopp and Barry, 1994).

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FIGURE 3.5 Auger oil and gas export pipelines c.2020. Data from BOEM.

3.3.2 LOOPED FLOWLINES The most common flowline configurations for subsea development are dual flowlines, single flowlines, and single flowline combined with a service line (Kaiser, 2017). Dual flowlines are standard for oil wells to allow round-trip pigging, but single flowlines with a service line are sometimes employed. Single flowlines are common in gas systems. Looped systems preserve round-trip pigging and reduce flowline costs but are less flexible and increase system and operational complexity. Operators attempt to balance capital spending against potentially higher life-cycle operating costs when evaluating flowline designs.

EXAMPLE: CANYON EXPRESS The Canyon Express project involved a commingled tieback of three gas fields owned and operated by different companies through a jointly owned flowline tieback to a third-party host platform. The size of the individual fields (each about 50 MMboe) and distance from existing infrastructure did not justify a stand-alone development for any of the fields, but when combined into one development, allowed the sharing of costs and risks that led to project sanction (Rijkens et al., 2003).

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The three fields (King’s Peak, Aconcagua, and Camden Hills) are located in several Mississippi Canyon and DeSoto Canyon blocks in 6200
7200 ft water depth, and a new platform on the shelf called Canyon Station owned and operated by a third party (Williams) was installed at Main Pass 261 in 300 ft water depth (Nielsen et al., 2001). The subsea system was divided into a common system and infield systems (Fig. 3.6). The common system includes the 12-in flowlines with appendices and risers, the main umbilical and methanol line, and equipment on the host platform. The common system is owned jointly. A single multiplexed electrohydraulic control umbilical connects the platform to the three fields in a daisy-chain configuration, and a separate umbilical supplies methanol and injection chemicals. Approximately 100 mi of umbilical was installed.

FIGURE 3.6 Schematic of Canyon Express flowline and umbilical configuration. From Nielsen, V.B.J., Piedras, J., Stimatz, G.P., Webb, T.R., 2001. Aconcagua, Camden Hills, and King’s Peak fields, Gulf of Mexico employ intelligent completion technology in unique field development scenario. In: SPE 71675. SPE Annual Technical Conference and Exhibition, New Orleans, LA, September 30
October 3.

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3.3.3 FLOATING PRODUCTION STORAGE AND OFFLOADING VESSELS Floating production storage and offloading vessels are used primarily in wet tree developments and do not employ oil export lines because oil is stored in the hull of the FPSO vessel and picked up periodically by shuttle tankers. If the produced gas is reinjected back into the reservoir, gas export lines will not be required, but this is not a common strategy in the Gulf of Mexico, where all gas beyond the needs of the facility is exported to shore.

EXAMPLE: STONES The Stones project is located in the Walker Ridge area approximately 200 mi due south of New Orleans in 9576 ft water depth (Fig. 3.7). The location is remote from both shore and existing infrastructure, and the seafloor in the area consists of rough terrain with the Sigsbee Escarpment traversing the field. The play is characterized by deep, hot, high-pressure reservoirs with low permeability, low gas-oil ratio, fluids with low API gravity, and higher viscosity than typical Gulf of Mexico oil.

FIGURE 3.7 Stones development is located in the Walker Ridge protraction area. From Shell, BOEM.

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A leased FPSO with a disconnectable turret and design capacity of 60,000 bopd, 30,000 bwpd, and 15 MMcfpd was employed (Fig. 3.8). The FPSO was selected in part to avoid the expense of laying a long oil line in extreme water depths (Lohr and Pena, 2017). The production facility and gas export pipeline are the deepest in the industry c.2020. Oil offtake is via shuttle tankers.

FIGURE 3.8 Turritelli FPSO in the Stones development. From SBM Offshore.

Phase 1 development consists of eight producing wells from two daisy-chained drill centers with subsea tiebacks to a production manifold (Fig. 3.9). Completions are commingled as part of the flow assurance strategy. Artificial lift systems consisting of a subsea artificial lift manifold were installed two years after first production.

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FIGURE 3.9 Stones development near the base of the Sigsbee Escarpment. From Lohr, C., Pena, M., 2017. Stones development: a pioneering management philosophy for enhancing project performance and safety. In: OTC 27674. Offshore Technology Conference, Houston, TX, May 1
4.

3.3.4 DIRECT VERTICAL ACCESS WELLS Direct vertical access (DVA) wells are a special type of wet well, where the tree is located on the seafloor, but rig access is available from the structure. DVA wells are used to reduce platform weight and have the benefit of platform access, but unlike other wet wells which are farther offset from the structure, there is very little flowline or umbilical requirements, and flow assurance issues are like dry tree wells. DVA wells were first used in 1994 at Auger and have been used at other Gulf of Mexico developments such as Perdido. EXAMPLE: PERDIDO DVA WELLS The Perdido project is an ultra-deepwater development of the Great White, Silver Tip, and Tobago fields 6 mi north of the border with Mexico in the remote and isolated Alaminos Canyon (Riley, 2016). A truss spar moored in AC 875 in 7817 ft water depth was selected for development (Fig. 3.10).

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FIGURE 3.10 Perdido field development cartoon. From BOEM.

Twenty-two DVA wells under the spar and an additional 12 satellite wells were used in the first phase of development (Fig. 3.11). Great White includes 21 initial producers and 9 water injection wells, and Tobago and Silvertip each have two initial producers which are tied back to the facility (Fig. 3.12). All production is comingled on the seafloor, with the gas production separated from liquids and liquids pumped to the host (Ju et al., 2010). Separation occurs subsea with gas flowing separately from the oil in an outer chamber of the riser, and the liquid is pumped up through an inner chamber. Oil and gas export lines depart the facility from the southwest due to geohazards before heading north (see also Fig. D.23).

FIGURE 3.11 Schematic of direct vertical access well cluster underneath Perdido.

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FIGURE 3.12 Perdido infield flowlines and export oil and gas pipelines c.2020. Data from BOEM.

3.3.5 OIL VERSUS GAS SYSTEMS Wells are classified as oil or gas depending on the relative contribution of gas and oil described by the producing gas-oil ratio (GOR) or cumulative gas-oil ratio (CGOR). Producing GORs are commonly used to classify wells as primarily oil or primarily gas, or a cumulative measure may be used, defined as the gas production measured in cubic feet to oil production measured in barrels. A threshold of 10,000 cf/bbl is often used to delineate oil producers (CGOR , 10,000 cf/bbl) from gas producers (CGOR . 10,000 cf/bbl), but thresholds as low as 5000 cf/bbl may also be used. The higher the value of the threshold applied, the drier the gas, and the lower the value the blacker and thicker the oil. Black oil reservoirs are normally defined as CGOR , 2000 cf/bbl (McCain, 1990). Condensate-gas ratio (CGR) delineates gas systems and condensate yields and is described in barrels condensate to million cubic feet of gas. Gas wells with a condensate yield less than 2
4 bbl/MMcf are considered dry; wells with condensate yield greater than 30 bbl/MMcf are considered rich. Rich gas systems are more valuable in terms of their production value, but they also present additional challenges in transport because there are limits to two-phase pipeline operations.

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The flowline design challenges and typical engineered solutions for dry gas, oil, and intermediate systems are as follows: •

•

•

Dry gas systems (CGOR . 50,000 cf/bbl). Hydrates are usually the dominant concern. Continuous inhibition with methanol or monoethylene glycol is a common and robust solution. The systems can be operated on a once-through basis (normal approach with methanol) or the inhibitor can be reclaimed (normal approach with glycol). Oil systems (CGOR , 10,000 cf/bbl). Both hydrates and paraffins are an issue. Lines are usually insulated to retain heat and remain outside of the hydrate and paraffin deposition regions during normal steady-state operations. A common approach in the Gulf of Mexico during start-ups and shutdowns is to apply inhibition chemicals, depressurization (blowdown), and fluid displacement (Pattee and Kopp, 2000). Wax is removed by regular pigging. Intermediate systems (10,000 cf/bbl , CGOR , 50,000 cf/bbl). Intermediate oil
gas systems consist of high fractions of liquid hydrocarbons and/or water in gas. Design solutions are site specific, but hydrates are usually the main threat. EXAMPLE: MENSA GAS SYSTEM The Mensa reserves were deposited in a single thick turbidite reservoir. The initial development consisted of three subsea wells directionally drilled from a cluster area on Mississippi Canyon block 687 to bottom-hole locations on adjacent blocks (Fig. 3.13). The reservoir structure is nearly flat and characterized by a high degree of structural complexity, marked by fault compartmentalization, and lateral stratigraphic variation (Razi and Bilinski, 2012). In total, six wells were drilled in the field, and in 2018 the field stopped producing.

FIGURE 3.13 Mensa field location map in the Mississippi Canyon area.

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A single large flowline was selected over a dual flowline because the cost of two smaller lines would have been prohibitively high and prevented commercial development. The use of glycol for continuous hydrate inhibition was selected over a methanol solution to avoid the high cost of methanol usage and resupply logistics. The flowline design precluded the need for pigging. Each well is connected to a subsea manifold 5 mi away on MC 685 (Fig. 3.14). The manifold, in turn, is connected by a single jumper and 63-mi 12-in flowline to Shell’s West Delta 143 platform in shallow water, by far the longest gas tieback in the Gulf of Mexico at the time. Mensa production is dry gas with very low condensate (1.6 bbl/MMcf) that allowed the long tieback distance without significant liquid buildup and pressure drop. A glycol dehydration system was installed on WD 143 for processing and provided the controls and chemicals for the umbilical.

FIGURE 3.14 Mensa subsea production system. From Shell, BOEM.

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EXAMPLE: TROIKA OIL SYSTEM The Troika development is located in the Green Canyon area in about 820 m water depth and includes the four-block unit GC 200, 201, 244, and 245. The two leading candidate systems for development were a subsea tieback to Bullwinkle located 22.5 km away in 410 m water depth on GC 65 and a floating production system with a drilling rig (Bednar, 1998). The subsea tieback was selected because it provided the operator the most cost-effective solution based on present value and accelerated development timing. Troika used an eight-slot subsea manifold dual flowline system with five initial wells (Fig. 3.15). Bullwinkle production facilities were upgraded to 200,000 bopd from a prior capacity of 55,000 bopd to handle Troika’s expected 80,000 bopd flowrate (Berger and McMullen, 2001). Each flowline was designed with a maximum flow rate of 60,000 bopd. Dedicated high-pressure separators for each flowline were installed on Bullwinkle, and new export pipelines were also required to handle the additional production streams (Fig. 3.16).

FIGURE 3.15 Troika subsea system layout and tieback to host platform Bullwinkle.

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FIGURE 3.16 Bullwinkle subsea flowline architecture c.2020. Data from BOEM.

Two pipe-in-pipe production flowlines connect the manifold to the Bullwinkle platform and provide round-trip pigging capability. A fundamental design requirement of the flowlines is to provide insulation to minimize paraffin deposits and to provide reaction time for hydrate prevention following an unplanned shut-in. As such, the flowlines were constructed with a 10-in production pipe encased in open cell foam in a 24-in carrier pipe pressurized with nitrogen. Two dedicated multiplexed electrohydraulic control umbilicals provide the communication and chemical links between the platform and the subsea system. The function of the umbilical is to provide high- and low-pressure hydraulic fluid for all the actuated valves on the manifold and subsea trees, methanol to all the subsea trees and both flowlines, and chemicals (paraffin and corrosion inhibitors) to both flowlines.

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3.3.6 RESERVOIR QUALITY In deepwater, oil wells with low GORs and high viscosity will need help to flow in long tiebacks, and if the fluids contain a high level of wax, water, or asphaltenes, additional precautions need to be taken. Gas wells present less restrictions unless liquids content is large. Well fluids change over the life cycle of production with declining reservoir pressure, and changing GORs, produced water and brine chemistry require flexible operational strategies. Solids from reservoir fines, asphaltenes, scale, and products of corrosion must all be understood (i.e., quantified) over the life cycle of individual wells for successful operations.

EXAMPLE: JACK/ST MALO AND JULIA The Jack and Saint Malo fields were discovered by Chevron in 2004 and 2003 in the Lower Tertiary Trend in about 7000 ft of water in the Walker Ridge area (Fig. 3.7). The fields are located within 25 mi of each other and were codeveloped with subsea completions flowing back to a semisubmersible located between the fields (Fig. 3.17). The semi also serves as host for the Julia field located a few miles south. Development was sanctioned in 2010, and first production was achieved in 2014.

FIGURE 3.17 Jack and Saint Malo stage one field layout. From Shell, BOEM.

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In the first stage of development, four wells were drilled into Jack and six into St. Malo. The wells at Jack are tied to one subsea manifold, whereas the wells at St. Malo are tied into two daisy-chained manifolds to facilitate future tiebacks. Three pumps on the seabed are located downstream of the manifolds to boost the fluids to the semisubmersible through individual 10-in flowlines and is one of the first developments in the Gulf of Mexico to employ subsea processing. One power and control umbilical were laid to each of the two fields supplying the pump systems with electrical power, communication, control fluid, and barrier fluid. Crude oil is transported about 140 mi to the Shell-operated Green Canyon 19 platform (Boxer). The pipeline is 24-in diameter and is the first large diameter, ultradeep pipeline in the Walker Ridge area (Fig. 3.18). The oil export pipeline was designed, built, and installed by Amberjack Pipeline Company, LLC, a joint venture between Chevron Pipeline Company and Shell Pipeline Company.

FIGURE 3.18 Jack/St. Malo subsea flowlines and oil and gas export pipelines c.2020. Data from BOEM.

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Gas is transported 150 mi to the southern extension of Enbridge’s Walker Ridge Natural Gas Gathering System, which also serves the Stones and Big Foot projects. Gas is transported from WR 718 to a Ship Shoal 332 shelf platform and then onward to shore on Enbridge’s Nautilus pipeline. Since Jack/St. Malo is powered by natural gas, the export pipeline is bidirectional, providing import gas for startup operations, and later in the field life when produced gas becomes insufficient to meet fuel needs.

3.4 HUB CLASSIFICATION There is no standard definition of a hub platform, but they are generally recognized as central points for the gathering, redistribution, and transportation of oil and gas (Huff and Heijermans, 2003). Three hub types are defined, based on configuration and whether the platform is primarily serving in a field development role, primarily in transportation services, or for both development and transportation functions (Fig. 3.19). Three hub classes are identified: I. structures that process production from one or more platforms or subsea wells; II. structures that serve as a receiving station for processed products and export; and III. structures that process production from one or more platforms and/or subsea wells and receive processed products for export. Hub class III is a composite of hub classes I and II because it performs both functions. All hub platforms have one or more pipelines entering and exiting; otherwise, they could not serve as a transit point for production. Processed product flows through export lines referred to as oil and gas regardless of whether it enters or exits a structure, whereas unprocessed (raw) product enters or exits a structure through flowlines (also referred to as bulk lines). Structures may serve as a central point to gather and process production in field development or as host to tieback fields or other structures without full processing capacity. Historically, platforms were sometimes referred to as hubs when they acted as a central station to receive and process (raw) production from several drilling platforms in a field. Today this connotation still applies to facilities that develop multiple fields. Optimization models that minimize total pipeline distance can sometimes be used to determine the best hub location to accommodate multiple fields (Box 3.1), but when several design conditions

FIGURE 3.19 Hub platform classification.

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play a role in development, these models are too simplistic to be useful. In subsea gas developments, for example, integrated field recovery models are commonly applied that use sophisticated simulations connecting the reservoir and production tubing pressures through the surface facility.

BOX 3.1 FINDING THE BEST LOCATION FOR THE NA KIKA FACILITY Problem In the Na Kika project, five subsea fields (Kepler, Ariel, Herschel, Fourier, and East Anstey) were used in development (Fig. 3.20). Determine the host location by minimizing the total squared distance between the five fields. Next, add the Coulomb field to your model, and determine the optimal location. Does your answer make sense? What is the motivation in selecting total squared distance as an objective function and what decision variables are unknown? Will a different reference frame change the optional location?

FIGURE 3.20 Na Kika host location and developed fields in the Mississippi Canyon area. From Shell, BOEM.

Solution Let (x, y) denote the location of the host to be determined and (ai, bi) the center location of the fields where the flowlines are assumed to start. The distance between points (x, y) and (ai, bi) is given by the square-root function: qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi di 5 dððx; yÞ; ðai ; bi ÞÞ 5 ðx2ai Þ2 1 ðy2bi Þ2 ;

(Continued )

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BOX 3.1 (CONTINUED) and so, the objective function for the problem is given by f ðx; yÞ 5

5 X i51

di2 5

5 X

ðx2ai Þ2 1 ðy2bi Þ2 :

i51

The objective function represents the total squared distance between the host and the five fields, with (x, y) unknown and (ai, bi) given for i = 1,2,. . ., 5. To minimize a two-dimensional function, set the gradients equal to zero and solve the resultant system of equations: !   5 5 X X @f @f ; 5 rf ðx; yÞ 5 2ðx 2 ai Þ; 2ðy 2 bi Þ 5 ð0; 0Þ @x @y i51 i51 The system of equations is linear and easy to solve due to the choice of the objective function. The solution to the optimization problem is given by P  P ai bi ; ; ðx ; y Þ 5 5 5 the average of the central coordinates of the individual fields. This point coincides incidentally with the center of gravity of a uniform mass distribution of points and thus has a simple physical interpretation as the “balance” point of a system of uniform masses. The value in the denominator arises from the number of fields under evaluation. If the origin of the coordinate system is selected two blocks west and one block south of the octopus head in the southwest corner of the block in Fig. 3.20, the approximate center locations of each field are as follows: Field

Center

Kepler Ariel Herschel Fourier E. Anstey

(21.5, 3.5) (0.5, 2.7) (3.8, 0.4) (5.1, 0.2) (3.0, 21.5)

The location of the minimum squared distance to the five fields is thus determined as (x , y ) 5 (2.2, 1.1). When Coulomb is added to the system, the optimal location should shift down and to the right because the equilibrium position (i.e., center of gravity) of the solution changes, being pulled south and east due to Coulomb, increasing the x-coordinate and decreasing the y-coordinate of the previous result. For Coulomb’s midpoint at approximately (8.0, 22.0), the location of the facility that minimizes the squared distance for all six fields is computed as (x , y ) 5 (3.2, 0.6). The motivation to minimize total distance is to minimize the total flowline and umbilical mileage required since material cost is proportional to distance. Installation cost is related to distance and time but in a complicated manner. A squared distance metric was used instead of distance to enable a simple algebraic solution, but solving a simpler problem does not guarantee a good solution to the problem desired. Using Excel and its solver optimizer, it is easy to show that the point (3.65, 0.40) minimizes the total distance to the five fields with an objective function of 13.53. The squared distance model location (2.18, 1.06) yields a total distance of 14.24, about 0.71 units away from the optimal, or 2.13 mi. If flowlines and umbilicals cost $3 million/mi, this amounts to an extra $12 million due simply to greater material cost.

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A structure may transition to hub status if wet wells are tied back to the platform or if processed oil or gas streams are sent across the facility. Many of the deepwater fixed platforms in the Gulf of Mexico fall into the former category, and several floaters approaching the end of their productive life have remained useful beyond their design life because of tieback service. If a structure cannot serve as a tieback host, it may instead be used as a destination for export pipelines such as the Ship Shoal 332A platform. At service and junction platforms, product pipelines board the structure and compression and pumping stations raise the fluid pressure which is then reinjected into export systems to enable flow onward to shore. Transportation platforms serve as connecting points for oil and gas (export) pipelines to enter the shelf pipeline network and connect to one or more destinations. Operators often put a premium on having multiple routes to different destinations to increase the netback value of their production and reduce the risk of disrupted service. Several of the larger Gulf of Mexico operators have established a robust pipeline network to maximize their operational flexibility.

3.5 HUB PLATFORMS 3.5.1 PROCESS AND EXPORT CAPACITY Hub platforms are described by their oil and gas processing capacity, number of pipeline interconnects, and export capacity. Processing capacity refers to the equipment used to handle, separate, treat, heat, and cool raw hydrocarbons into pipeline quality oil and gas streams and to dispose of water overboard in accord with regulatory requirements. Service and junction platforms do not have processing capacity and are characterized primarily by their pumping and compression capability, slug catching facilities, metering, and dehydration services. Volumes processed and shipped are more relevant factors than nameplate capacity but are not directly observable for most pipelines. For nonhub platforms, oil and gas equipment capacity is a reasonably good indicator of export capacity and pipeline diameter, but for hub platforms export capacity usually greatly exceeds processing capacity.

3.5.2 FIRST-GENERATION HUBS Shell’s Bullwinkle, Enchilada, and Auger developments were the first generation of deepwater hub platforms in the Gulf of Mexico installed in the mid-1990s. The same development formula was applied in each case. After field production began to decline, nearby discoveries (mostly, but not always, from the owners of the platform) out of reach of the platform were tied back to the host. Processing capacity was expanded, if necessary, and the operating life of the facility was extended. Operators are better able to schedule and repurpose their own platforms than soliciting or commercializing production from third parties because of timing and engineering constraints, negotiation uncertainty, and related issues. The deciding factor for operator-owned facilities and tiebacks is strategic and economic, while for third-party operators, economics is usually the deciding factor. Planning, development, and negotiation between parties may take a year or longer, and if the structure is producing the owner(s) will maintain their bargaining position, but once the structure approaches cessation or stops producing altogether, the negotiating power will shift rapidly.

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EXAMPLE: ENCHILADA AND SALSA DEVELOPMENT, 1996
2004 The Enchilada development originally consisted of several fields covering five lease blocks: Garden Banks 83/84 (Elmer), Garden Banks 127/128 (Chimichanga/Enchilada), and Garden Banks 172 (Salsa). In 1994 two nearby subsalt discoveries in GB 127 (Chimichanga) and GB 172 (Salsa) by Shell and Amerada Hess formed the basis of a two-platform codevelopment with Shell as operator (Fig. 3.21).

FIGURE 3.21 Enchilada oil and gas import and export pipelines c.2020. Data from BOEM.

The Enchilada GB 127A platform was installed in 633 ft of water in December 1996. It is a 4-leg, 8-pile structure with 24 slots, 15 of which were allocated for wells, 8 for pipelines, and one for an emergency sump. The Salsa GB 172B platform was installed in 695 ft water depth in November 1997, also a 4-leg, 8-pile structure with 20 slots (15 for wells, 4 for pipelines, and one emergency sump). Salsa production is sent to Enchilada, and the Salsa B platform was designed only for primary separation and testing of the Salsa wells. Processing facilities at Enchilada were initially designed to handle 40 Mbopd of high sulfur oil, 20 Mbopd of low sulfur oil, and 40 MMcfpd of gas. Export pipeline capacities were in the range of 250 Mbopd and 1000 MMcfpd gas.

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In 1997 as part of capacity expansion at Shell’s Auger TLP, a gas pipeline, a gas compressor, and an oil pipeline booster pump station were added to Enchilada. Auger production is not processed on Enchilada but accepts gas where it is measured and reinjected into the 30-in gas export pipeline and accepts oil where it goes through a booster pump station and reinjected down the 20-in sour oil export line. In 2000 the Conger three-well subsea development in GB 215 was flowed back to the Salsa platform. To incorporate Conger fluids into the Enchilada complex, major topsides modifications were required at the Salsa and Enchilada platforms. At Salsa, the facility needed to be occupied, and new quartering and power systems were required. Methanol and chemical storage and injection systems, along with separation and testing equipment, pigging and blowdown equipment was also added. Expansion at Enchilada included slug catchers on both boarding pipelines from Salsa, additional treating capacity and compression. The Sangria one-well subsea development in GC 177 was tied back to the Salsa platform and required the addition of subsea control systems, chemical storage and injection systems, and additional process heat and heat exchangers. In 2002 gas lift was provided to the Cinnamon development in GC 89 to enhance oil recovery. The expansion involved reversing the direction of an existing pipeline between GC 89 and GB 128 and performing topside revisions. Cinnamon production ceased to be economic shortly thereafter, and in 2009 the platform was decommissioned. In 2004 a 16-in gas and a 14-in oil sales pipeline from Conoco’s Magnolia prospect in GB 783 were routed through the Enchilada platform, and another subsea well at Conger was tied back to Salsa. A helicopter refueling station on the Salsa platform was upgraded to service midsize to large helicopters.

3.5.3 SECOND-GENERATION HUBS Second-generation and later hubs were built with greater flexibility and equipment sizes, tying back subsea wells from the start of production, with some designed with excess transportation capacity in addition to production processing. A greater variety of third-party operators also became interested in hub business models in the mid-2000 time period. EXAMPLE: GARDEN BANKS 72 PLATFORM The GB 72 platform (also known as Spectacular Bid) is located in Garden Banks block 72 in 514 ft water depth (Fig. 3.22). The platform was designed and installed by a midstream company to use for off-lease processing and as a junction platform for its pipeline systems (Huff and Heijermans, 2003). The platform originally processed production from several regional fields and served as the anchor portal for the deepwater Stingray gas pipeline and Poseidon oil pipeline systems. The Cameron Highway Oil Pipeline System (CHOPS) designed to move Atlantis, Mad Dog, and Holstein crude from the southern Green Canyon area also cross this platform to markets in Port Arthur and Texas City, Texas.

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FIGURE 3.22 Garden Bank 72 platform, also known as Spectacular Bid. From Genesis Energy, BOEM.

3.5.4 TRANSPORTATION HUBS Transportation platforms generally do not have production capacity to process raw hydrocarbon streams, unless the structure previously served in a field development role, and the equipment is still operable. The fluids boarding transportation platforms have already been processed to pipeline specifications and only need to be pumped or compressed to reach their destination. Ancillary services offered at transportation facilities normally include metering, liquids removal, pig catcher, heating, and cooling. Dehydration facilities and slug catchers are often needed for gas transport. If service structures handle multiple deliveries and departures for different operators, it will likely have several export lines leaving the platform.

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EXAMPLE: SHIP SHOAL 332 PLATFORMS The Ship Shoal 332A platform was installed in 438 ft water depth to develop a gas field (Fig. 3.23). El Paso Energy Partners acquired the structure from Arco in the early 1990s after production ceased to support the Leviathan Offshore Gathering System, the predecessor of the Manta Ray Gathering System. El Paso Energy Partners was required by the Federal Trade Commission to sell the platform to a new company, Atlantis Offshore LLC, a joint venture between El Paso and Manta Ray Offshore Gathering Company LLC, itself a joint venture company owned by Shell Gas Transmission LLC, Marathon Oil Company, and Enterprise Oil Products LP.

FIGURE 3.23 Ship Shoal 332A&B platform hub for the Cameron Highway Oil Pipeline System. From Genesis Energy, BOEM.

In 1995 EPN constructed the Poseidon oil pipeline and in 1999, the Allegheny oil pipeline, which used the SS 332A platform. A new platform SS 332B was constructed adjacent to SS 332A to serve as a transport hub for CHOPS and the interconnection between the Caesar oil pipeline and Cameron Highway.

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BOX 3.2 THREE PIPELINE RULES OF THUMB Flush Volumes and Dead Oil Storage If a subsea well needs to be shut-in, the oil within the pipeline will cool down to ambient (seafloor) temperatures within a few hours and present flow problems if not managed properly. Operational procedures need to be in place to manage such events to avoid flow assurance problems. One strategy employed to avoid oil gelling is to flush the oil from the line before the crude oil reaches its pour point temperature and replace it with ‘dead’ oil or diesel stored at the facility. Example How much oil storage at a platform is required to flush a 10-mi, 8-in diameter pipeline? How long will it take to flush the line if pumping capacity is 30,000 bpd? Recall that 1 bbl 5 5.61 ft3. Solution    2 5280 ft π 8 in Pipeline volume 5 ð10 miÞ 5 18; 421 ft3 5 3284 bbl: mi 4 12 in=ft Flushing time 5

3500 bbl 24 hours U 5 2:6 hours: 30; 000 bpd day

Linefill in Barrels per Mile The linefill of a pipe in barrels per mile is obtained by squaring the inside diameter of the pipe in inches and multiplying by 5.13. Example Estimate the volume of a 25 mi, 6-in schedule 40 flowline. Apply the rule of thumb and derive the 5.13 value. Solution The inside diameter of a 6-in schedule 40 pipe is 6.065 in, yielding: Linefill 5 ð5:13Þ ð25 miÞ ð6:065 inÞ2 5 4718 bbl: The rule of thumb value is derived using conversion factors:      1 bbl ft 2 5280 ft π 5 5:13 Factor 5 5:61 cf 12 in mi 4

Weymouth’s Formula for Gas Flow The flowrate of gas described in cubic feet per day Q is estimated using Weymouth’s formula for input data that include the inside diameter d (in), length of the pipeline L (mi), and starting and ending pressures P1 and P2 (psi): pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 871 2 d 8=3 P21 2 P22 pffiffiffi Q5 : L The answer is reported to have 1% error for every 10 F variation in temperature from 60 F, and 0.75% error for every 0.01 variation in specific gravity from the 0.60 reference conditions for the formula (McAllister, 2014). Example Estimate the flowrate through 4 mi of a 103/4-in quarter-inch wall pipe if the pressure at the wellhead is 485 psi and the pressure at the platform is 285 psi. Solution pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 871 2 ð10:25Þ8=3 5002 2 3002 p ffiffiffi 5 86:4 MMcfpd: Q5 L

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REFERENCES Bai, Y., Bai, Q., 2019. Subsea Engineering Handbook, second ed. Gulf Professional Publishing, Waltham, MA. Bednar, J.M., 1998. Troika subsea production system: an overview. In: OTC 8845. Offshore Technology Conference, Houston, TX, May 4
7. Beltrami, F., Hansen, K., 2016. Truly sustainable building blocks for deepwater field development: the need for strategies re-definition in a persistently low oil price scenario? In: SPE 181707. SPE Annual Technical Conference and Exhibition, Dubai, UAE, September 26
28. Berger, R.K., McMullen, N.D., 2001. Lessons learned from Troika’s flow assurance challenges. In: OTC 13074. Offshore Technology Conference, Houston, TX, April 30
May 3. Brock, V.A., 2000. Auger
an asset in transition. In: OTC 15111. Offshore Technology Conference, Houston, TX, May 5
8. Dekker, M., Reid, D., 2014. Deepwater development strategy. In: OTC 25135. Offshore Technology Conference, Houston, TX, May 5
8. Hjelmeland, M., Reimers, O., Hey, C., Broussard, D., 2017. Qualification and development of the world’s first high pressure subsea boosting system for the Jack and St. Malo field development. In: OTC 27800. Offshore Technology Conference, Houston, TX, May 1
4. Huff, S.S., Heijermans, B., 2003. Cost-effective design and development of hub platforms. In: OTC 15107. Offshore Technology Conference, Houston, TX, May 5
8. Ju, G.T., Littell, J.S., Cook, T.B., Dupre, C.M., Shumilak, C.E., 2010. Perdido development: subsea and flowline systems. In: OTC 20882. Offshore Technology Conference, Houston, TX, May 3
6. Kaiser, M.J., 2017. U.S. Gulf of Mexico deepwater pipeline construction
a review of lessons learned. Mar. Policy. 86 (12), 214
233. Kopp, F., Barry, D.W., 1994. Design and installation of Auger pipelines. In: OTC 7619. Offshore Technology Conference, Houston, TX, May 2
5. Lohr, C., Pena, M., 2017. Stones development: a pioneering management philosophy for enhancing project performance and safety. In: OTC 27674. Offshore Technology Conference, Houston, TX, May 1
4. McAllister, E.W., 2014. Pipeline Rules of Thumb Handbook, eighth ed. Gulf Publishing Company, Waltham, MA. McCain Jr., W.D., 1990. The Properties of Petroleum Fluids, second ed. PennWell, Tulsa, OK. Nielsen, V.B.J., Piedras, J., Stimatz, G.P., Webb, T.R., 2001. Aconcagua, Camden Hills, and King’s Peak fields, Gulf of Mexico employ intelligent completion technology in unique field development scenario. In: SPE 71675. SPE Annual Technical Conference and Exhibition, New Orleans, LA, September 30
October 3. Pattee, F.M., Kopp, F., 2000. Impact of electrically-heated systems on the operation of deep water subsea oil flowlines. In: OTC 11894. Offshore Technology Conference, Houston, TX, May 1
4. Razi, M., Bilinski, P., 2012. Mensa field, deepwater Gulf of Mexico case study. In: SPE 159741. SPE Technology Conference and Exhibition, San Antonio, TX, October 8
10. Reid, D., Dekker, M., 2014. Deepwater development non-technical risks
identification and management. In: SPE 170739. SPE Annual Technical Conference and Exhibition. Amsterdam, The Netherlands, October 27
29. Rijkens, F., Allen, M., Hassold, T., 2003. Overview of the Canyon Express project, business challenges and “industry firsts”. In: OTC 15093. Offshore Technology Conference, Houston, TX, May 5
8. Riley, C., 2016. Perdido: a five year look at the technologies that have enabled ultra-deepwater success. In: SPE 181442. SPE Annual Technical Conference and Exhibition, Dubai, UAE, September 26
28.

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Simms, G.J., Fowler, R., Leontaritis, K.J., Krishnathasan, K., 2012. Subsea Who Dat project
producing light and heavy oil in a deepwater subsea development. In: OTC 23378. Offshore Technology Conference, Houston, TX, April 30
May 3. Smith, C.D., Pilney, D.A., 2003. Enchilada: from border town to cowtown. In: OTC 15110. Offshore Technology Conference, Houston, TX, May 5
8. Willson, S.M., Edwards, S., Heppard, R.D., Li, X., Coltrin, G., Chester, D.K., et al., 2003. Wellbore stability challenges in the deep water, Gulf of Mexico: case history examples from the Pompano field. In: SPE 84266. SPE Technical Conference and Exhibition, Denver, CO, October 5
8.

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4

Pipeline routing on the Gulf of Mexico shelf is relatively simple because the seafloor is flat and featureless, and obstacles such as other pipelines only need to be avoided or crossed. By contrast, deepwater seafloor topography in the region is complex and geohazards are common, which significantly increases the complexity of routing. In this chapter, the manmade hazards, geohazards, and chemosynthetic communities that may be encountered in the deepwater Gulf of Mexico are briefly reviewed. Field development requires understanding the nature, recurrence rate, and magnitude of all geohazards in the region of development. Engineers need to understand the behavior of the geohazards and their interactions with the pipeline at relevant spatial and temporal scales so that the development risk may be characterized and the pipeline routes suitably selected. Seabed conditions and geohazards are interrelated and understanding the history of the site is critical to understand the hazards that are relevant to the engineering timescales involved.

4.1 MANMADE HAZARDS Manmade hazards in the Gulf of Mexico include existing offshore installations, pipelines or cables, shipwrecks, and military dumping grounds, and because the locations are known or discovered via survey and are localized in nature, they are readily incorporated in route selection (Box 4.1). The locations of all existing infrastructure need to be gathered and assessed before fieldwork is performed. The preference is usually to have as few pipeline crossings as possible because they require significant engineering and regulatory work, and, if a crossing is required, it should be as close to right angles as possible to reduce the number of support mattresses. Crossings create diversions in pipeline routes and increase route length, which increases the cost. The presence of ordnance dumping zones, areas of known shipwrecks (Evans and Voisin, 2011; Gearhart, 2011), and shipping fairways imposes additional restrictions on route selection. In an ordnance zone, the pattern of debris is usually of long linear areas, consistent with items being dumped from a slow-moving vessel. Cylinders and rectangular items are commonly identified shapes. Archeological clearance on blocks in Gulf of Mexico shelf waters has been in existence since the 1970s.

4.2 GEOHAZARDS Examples of geohazards that may be encountered in the deepwater Gulf of Mexico include steep slopes, unstable slopes, hard seabed sediments, bedforms, and scarps. Often, these issues are The Offshore Pipeline Construction Industry. DOI: https://doi.org/10.1016/B978-0-12-820288-3.00004-4 © 2020 Elsevier Inc. All rights reserved.

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BOX 4.1 OFFSHORE PIPELINE ROUTE SELECTION Offshore pipeline route selection is based on consideration of bathymetry, seafloor character, seabed geology, geohazards, bioenvironmental issues, and existing infrastructure. A good strategy in routing is to avoid hazards, but this is not always possible, and with every new restriction or avoidance area added, pipeline length increases, which increases the cost. The first step in pipeline construction is to perform a survey of the proposed route and contingency routes collecting bathymetry data and core samples to determine soil characteristics (Haneberg et al., 2013; Tootill et al., 2004). The soil information is used to predict potential span and perform stability checks (Guo et al., 2014). Oil and gas companies typically perform or oversee the route selection process and are involved to varying extents with the engineering, procurement, and construction processes depending on the nature of the project. An economic evaluation is performed on various routes considering the installation and material cost of the pipe, burial footage, water depth, pipeline crossings, and subsea terrain to determine the preliminary route. After preliminary routing studies are completed, a hazard survey is performed, which includes core samples of the bottom conditions and a more detailed overview of the bathymetry, escarpments, outcrops, and related features. If leaseholders along the route have drilling or development plans that would conflict with the route or installation schedule, contingency plans and a contingency around the proposed activity need to be in place. Congested areas and areas with known or expected geohazards require greater planning and review. Pipeline routes are selected to avoid archeological sites or biological resources, and areas of possible landsliding and faulting, mud seeps, undulations, and rocky outcrops. Routes may be selected to avoid difficult terrain, but the added length needs to be compared with the cost to rectify the spans (Wincheski et al., 2002), and in many cases avoidance is not practical or cost-effective.

superimposed upon and interrelated to each other (Hill et al., 2013; Hill and Wood, 2015). Integrated geohazards analysis evaluates the possibilities to allow direct avoidance through a choice of well or field layout, or by an appropriate mitigation of the desired hazard through engineering design.

4.2.1 SLOPE STABILITY Infrastructure located near or on peaks and canyons is at risk if the slope fails during the lifetime of the development. The mechanisms capable of triggering a slope failure are related to changes in the shear stress applied to the soil (Jeanjean et al., 2003). For slope stability issues, the annual probability of occurrence of a failure is commonly estimated, along with the consequences in terms of the debris flows and damage to infrastructure. The probability of failure is very small since the occurrence of events is normally on the order of 10,000 or 100,000 years or more compared to the 50 years or so lifetime of the development, and the footprint of the development is usually small relative to the areal extent of the geohazard(s) encountered, although in pipeline routing a large amount of line may be exposed. The best course of action is often to avoid steep and/or unstable slopes and potential run-offs by setting the route a safe distance from the base of the slope, but it is not always possible to avoid all areas, and avoidance usually comes with increased cost.

4.2 GEOHAZARDS

EXAMPLE: DEBRIS FLOW AND SALT DOMES AT NA KIKA The Na Kika basin in Mississippi Canyon experienced debris flows in geologically recent times (B10,000 years ago) and may be susceptible to future debris flow events (Primez et al., 2004). The lines labeled L1 through Lc6 in Fig. 4.1 represent the paths of the steepest descent in the region, and, presumably, where debris flows will travel if slope failures occur in the future. The paths were identified as the most probable failure areas posing risk for the Na Kika development.

FIGURE 4.1 Location map of the Na Kika Basin and production facility. From Primez, C., Marr, J., Shipp, C., Kopp, F., 2004. Observations and numerical modeling of debris flows in the Na Kika Basin, Gulf of Mexico. In: OTC 16749. Offshore Technology Conference, Houston, TX, May 3 6.

Unit CD, shown in Fig. 4.2 colored light blue, represents the surficial debris flow deposit that overlays with the development and export pipelines, and was used in simulation modeling to develop the best export pipeline route. Pipeline 1 from Thunder Horse, and Pipeline 2, the oil export from Na Kika, both cross the profile. Pipeline 3, the gas export from Na Kika, follows a northerly route and avoids most of the unit. Pipelines 2 and 3 were routed between numerous salt domes on their way to shelf facilities.

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FIGURE 4.2 Bathymetry of Na Kika Basin showing location of surficial and buried debris flow deposits. From Primez, C., Marr, J., Shipp, C., Kopp, F., 2004. Observations and numerical modeling of debris flows in the Na Kika Basin, Gulf of Mexico. In: OTC 16749. Offshore Technology Conference, Houston, TX, May 3 6.

EXAMPLE: SLOPE FAILURE PROBABILITY AT ATLANTIS Atlantis and Mad Dog were the first developments in the Gulf of Mexico located very near, or on, the Sigsbee Escarpment, and presented unique challenges that required an integrated geohazards study to justify the field architectures (Angell et al., 2003; Mannaerts et al., 2005). Siting of facilities in geologically active areas can proceed only if the associated risks are understood and deemed acceptable. At Atlantis, there was clear evidence of numerous past failures of the steep slopes. Each slope failure would have generated a debris flow with some of the larger blocks

4.2 GEOHAZARDS

FIGURE 4.3 Overlay of Houston Astrodome and intact blocks of debris flow at Atlantis Slump A. Modified from Jeanjean, P., Hill, A., Taylor, S., 2003. The challenges of siting facilities along the Sigsbee Escarpment in the southern Green Canyon area of the Gulf of Mexico: framework for integrated studies. In: OTC 15156. Offshore Technology Conference. Houston, TX, May 5 8.

comparable in size with the Houston Astrodome (Fig. 4.3). These debris flows impacted the proposed footprint of the subsea well cluster, as well as the area where the flowlines, umbilicals, and anchors of the production unit was in Green Canyon block 743 (Fig. 4.4). The flowlines and umbilicals from the Atlantis drill centers were routed down the escarpment in areas with failure rates estimated at 10 24 with an annual probability of failure between 10 25 to 1026 (Nadim et al., 2003). Because the subsea wells at Atlantis were located due north of the production unit, the export lines were routed south-southwest of the unit and pass up the escarpment in an area near Mad Dog a few blocks northwest of Atlantis. If the Atlantis production unit was located north of the Sigsbee Escarpment, production from all the subsea wells would have to traverse up the escarpment, which would have significantly increased the complexity of the system.

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FIGURE 4.4 Perspective view of Sigsbee Escarpment near Atlantis development. From BOEM.

EXAMPLE: SLUMP BLOCK AND FAULT AVOIDANCE AT MAD DOG Mooring cluster 2 at Mad Dog in Green Canyon block 782 is composed of four anchor sites situated along the Sigsbee Escarpment within a slump area (Fig. 4.5). There are several small-scale mounds at the seafloor believed to be slump blocks that were transported downslope from the head scarp (Berger et al., 2006; Orange et al., 2003). Hummocky seafloor appears to be the seafloor expression of a buried mass transport deposit. Two main fault lines were avoided in anchor site selection.

4.2 GEOHAZARDS

FIGURE 4.5 Mad Dog spar and mooring layout. From Jeanjean, P., Hill, A., Taylor, S., 2003. The challenges of siting facilities along the Sigsbee Escarpment in the southern Green Canyon area of the Gulf of Mexico: framework for integrated studies. In: OTC 15156. Offshore Technology Conference. Houston, TX, May 5 8.

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BOX 4.2 TWO MOORING LINE EXAMPLES Problem A semisubmersible floating production unit was used in the Who Dat development in Mississippi Canyon (Fig. 3.1). Estimate the length of the FPU mooring lines. What angle does each cluster of mooring lines span and how are they oriented? Solution Lease blocks in the Gulf of Mexico are 3 mi on each side and provides the distance scale. There are 12 mooring lines, three at each corner of the FPU, positioned approximately equally in radial angle 15 degrees from one another, with each approximately 5000 ft horizontal offset. Clusters are oriented about 60 degrees from each other. Problem The Mad Dog mooring lines are arranged in three clusters (Fig. 4.5). Two clusters (Cluster 1 and Cluster 3) are situated along the lower slope of the continental shelf in approximately 4250 and 4400 ft water depth, respectively. Cluster 2 is situated along the escarpment near a slump area in about 5650 ft water depth. Estimate the length of the mooring lines and the depth of the escarpment near Slump 8. Estimate the slope of the GC 782 lease block over the escarpment. Solution The 3 mi lease block provides the distance scale. After measuring the length of the mooring lines, it is determined that Clusters 1, 2, and 3 have horizontal offsets about 5363, 6610, and 5613 ft, respectively. The lengths of the mooring lines can be estimated by multiplying these distances by a factor of 1.2 or 1.3 to account for the catenary shape of the lines through the water column. Escarpment depth at Slump 8 is approximately 1400 ft, which is the difference between the water depths of Clusters 1 and 2. The distance between the anchors at Cluster 1 and Cluster 3 is about 9105 ft, and the water depth difference between these points is 150 ft. Slope is rise/run and equal to approximately 2 degrees which is typical on the Gulf of Mexico slope. Over the escarpment the slope is about 20 degrees.

4.2.2 FURROWS Furrows are longitudinal bedforms formed in cohesive sediments that tend to be aligned parallel to bottom currents. Extensive regions of the seafloor in and around the base of the Sigsbee Escarpment are furrowed, which implies high bottom currents in the area. Some of the furrows can reach 200 ft peak to peak and be up to 30 ft deep, but typical depths vary between 1 and 10 m and widths from 5 to 50 m. Bottom currents impact pipeline routing and the orientation of risers. Risers are typically oriented in the same direction as the current to increase fatigue life. Flowlines across furrow fields are often straked to reduce interaction with the bottom current. Potential pipeline hazards associated with deep-sea furrow fields include unsupported pipeline spans, pipeline shoulder scour, vortexinduced vibrations, and large-scale effects which may cause lateral instability and pipeline movement (Clukey et al., 2007). EXAMPLE: FURROW FIELD AT STONES Current-induced erosion seaward of the continental rise in the area of the Stones field in Walker Ridge has produced an extensive furrow field (Fig. 4.6). The furrows trend southwest to northeast and are up to 18 ft in depth and 170 ft in width (crest to crest), with average depth and width of 7 and 80 ft, respectively (Hadley et al., 2017).

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FIGURE 4.6 Bathymetry map and section exhibiting furrows at Stones. From Hadley, C., Bradford, K., Young, A., Trandafir, A.C., Bruce, B., 2017. Integrated study of a complex seabed for the Stones FPSO. In: OTC 27835. Offshore Technology Conference, Houston, TX, May 1 4.

EXAMPLE: ROUTING ACROSS THE EAST BREAKS SLIDE The Falcon gas field was discovered in April 2001 on East Breaks blocks 579 and 623 in 3450 ft water depth. A two-subsea well tieback to a new host platform called Falcon Nest 33 mi away in Mustang Island A-103 in 389 ft water depth was the development selected (Hall et al., 2004). Shortly before first production, the Harrier discovery was made, and then two additional discoveries (Tomahawk and Raptor) occurred during the Harrier development (Hoffman et al., 2004). The East Breaks slide is a late Pleistocene shelf-slope instability feature in the northwest Gulf of Mexico covering about 350 mi and extending into Alaminos Canyon (Fig. 4.7). The two main factors that had to be addressed in selecting a pipeline route were the irregular seafloor and potential slope instability and its impact on spanning and bottom stability (Fig. 4.8).

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FIGURE 4.7 East Breaks intraslope fans and depocenters. From Hoffman, J.S., Kaluza, M.J., Griffiths, R., McCullough, G., Hall, J., Nguyen, T., 2004. Addressing the challenges in the placement of seafloor infrastructure on the East Breaks Slide a case study: the Falcon Field (EB 579/623), northwestern Gulf of Mexico. In: OTC 16748. Offshore Technology Conference, Houston, TX, May 3 6.

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FIGURE 4.8 Seafloor rendering at East Breaks slide near the Falcon field development. From Hoffman, J.S., Kaluza, M.J., Griffiths, R., McCullough, G., Hall, J., Nguyen, T., 2004. Addressing the challenges in the placement of seafloor infrastructure on the East Breaks Slide a case study: the Falcon Field (EB 579/623), northwestern Gulf of Mexico. In: OTC 16748. Offshore Technology Conference, Houston, TX, May 3 6.

4.2.3 MUDSLIDE REGIONS Mudslide regions offshore the Mississippi River Delta are localized features, on the order of several thousand feet long by hundreds of feet across and up to 100 feet deep. Large hurricane waves can trigger mudslides and both Hurricanes Ivan in 2004 and Katrina in 2005 produced

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mudslides in this area that damaged pipelines, usually in the riser or riser tie-in near the base of platforms (Nodine et al., 2007). The optimal route for a pipeline across mudslide regions is difficult to assess, because the direction of soil movement depends on waves and not bathymetry, making it difficult a priori to know how to orient the pipe. To minimize the impact of mudslide damage, designers minimize the length of pipeline traversing the mudslide prone area and locate pipelines in the deepest waters in the mudslide prone area.

4.2.4 FAULTS AND SCARPS Seafloor faults and scarps create risks for pipeline infrastructure from potential offset at fault crossings. To understand the causative processes and quantitatively evaluate the locations, magnitude, and recurrence potential of displacement events, geologic and geotechnical survey data are used in integrated models (Angell et al., 2003). The south Caspian Sea is one of the most geohazardous producing basins in the world, with active mud volcanoes, shallow gas and shallow water beds, faults and seismicity, excess pore pressures, slope instability, and soft sensitive and reactive soils (Box 4.3).

BOX 4.3 AZERI-CHIRAG-GUNASHLI GEOHAZARDS The Caspian Sea is the largest inland body of water in the world, more than six times the size of Lake Michigan, and approximately 750 mi long and on average about 200 mi wide. There is access by river for only about half the year due to freezing. Sea levels are over 25 m below oceanic levels and are subject to significant irregular variation. Caspian water is brackish with a salinity of 1.2% (12 g/L) compared to 3.5% (35 g/L) for ocean water, and countries bordering the water body are Azerbaijan, Russia, Iran, Turkmenistan, and Kazakhstan. Under and around the Caspian lie major deposits of oil and gas. The supergiant Azeri-Chirag-Gunashli oil field lies in the Azerbaijani sector of the south Caspian Sea and is estimated to have 5.4 Bbbl reserves. The field complex is made up of three individual structural culminations (Azeri, Chirag, and deepwater Gunashli) developed with seven producing platform complexes (Fig. 4.9). The geohazards pose threats to drilling and operations, to pipelines, and foundations supporting jackets and subsea structures. (Dingler et al., 2015; Hill et al., 2015a).

FIGURE 4.9 Azeri-Chirag-Gunashli field architecture, south Caspian Sea c.2015. From Dingler, J., Dingler, A., Hill, A.W., Wood, G.A., Ford, A.J., 2015. Improving the focus of the ACG geohazards image

20 years of data acquisition. In: OTC 25912. Offshore Technology Conference, Houston, TX, May 4 7.

(Continued )

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BOX 4.3 (CONTINUED)

FIGURE 4.10 Bathymetry model of the Azeri-Chirag-Gunashli complex with inset showing mud volcano flows. From Dingler, J., Dingler, A., Hill, A.W., Wood, G.A., Ford, A.J., 2015. Improving the focus of the ACG geohazards image

20 years of data acquisition. In: OTC 25912. Offshore Technology Conference, Houston, TX, May 4 7.

Most Azeri-Chirag-Gunashli infrastructure has been situated on the shallow water shelf, with jackets set back from the escarpment and its 100 m drop (Fig. 4.10), but in the most recent phase of development for the deepwater Gunashli field, two subsea water injection manifolds were located below the escarpment. First oil was delivered in 1997 and full-field development was delivered in three separate phases from 2003 to 2007. Phase I entailed siting the Central Azeri platform complex and export pipelines to shore, Phase II the West Azeri and the East Azeri platforms and related infield and export pipelines, and Phase III the installation of the deepwater Gunashli platform complex and three subsea water injection manifolds. The Chirag Oil Project commenced in 2007 and was completed in 2014. In 2004, production levels were 130,000 bpd, and in 2015 reached 835,000 bpd.

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4.3 CHEMOSYNTHETIC COMMUNITIES Chemosynthetic communities typically occur in clusters in areas where hydrocarbons are present near seabed sediments or where active oil and gas seeps occur. They usually consist of mounds of clams, mussels, and tubeworms tens of feet across and up to 10 feet in height. These communities are protected in the Gulf of Mexico and according to NTL 2000-G20 on deepwater chemosynthetic communities, seafloor disturbances must be avoided within 250 ft of features that could support high-density chemosynthetic communities (Oynes, 2000). If it is uncertain whether chemosynthetic organisms are associated with mounds or related features, piston core samples may be required. The presence of chemosynthetic communities along preferred routes will limit access and restrict options. EXAMPLE: SEA FANS AND SOFT CORAL AT SHENZI The Shenzi field lies in Green Canyon blocks 609, 610, 652, 653, and 654 in 4150 to 4480 ft water depth a few miles northwest of the Sigsbee Escarpment (Fig. 4.11). Numerous fault scarps are visible throughout the region.

FIGURE 4.11 Shenzi layout from three drill centers tied back to a tension leg platform c.2008. From BOEM.

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107

Clusters of seafloor mounds circular in shape and less than five feet high were identified as potential hydrocarbon seeps in the vicinity of the proposed flowlines between drill centers B and G. Piston core samples were obtained and plugs of solid tar were obtained. No evidence of active hydrocarbon seepage was seen and no chemosynthetic organisms observed (Williamson et al., 2008). A marine biologist confirmed that the sea fans and soft coral were not chemosynthetic organisms but a type of soft coral that attached to the tar mounds for hard substrate (Fig. 4.12). The flowline and umbilical routes between the drill centers were nonetheless modified to avoid the sea fans by passing between the tar mounds.

FIGURE 4.12 Sea fans and bush-like soft coral on tar pillow at Shenzi. From BOEM.

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REFERENCES Angell, M.M., Hanson, K., Swan, F.H., Young, R., Abramson, H., 2003. Probabilistic fault displacement hazard assessment for flowlines and export pipelines, Mad Dog and Atlantis field developments, deepwater Gulf of Mexico. In: OTC 15402. Offshore Technology Conference, Houston, TX, May 5 8. Berger, W.J., Lanier, D.L., Jeanjean, P., 2006. Geologic setting of the Mad Dog mooring system. In: OTC 17914. Offshore Technology Conference, Houston, TX, May 1 4. Clukey, E, Israel, K., Jones, C., Ziegler, C.K., 2007. Pipeline risk assessment in deep-sea furrow regions. In: OTC 18939. Offshore Technology Conference, Houston, TX, April 30 May 3. Dingler, J., Dingler, A., Hill, A.W., Wood, G.A., Ford, A.J., 2015. Improving the focus of the ACG geohazards image 20 years of data acquisition. In: OTC 25912. Offshore Technology Conference, Houston, TX, May 4 7. Evans, A.M., Voisin, E.E., 2011. Geophysics, industry, and shipwrecks on the Gulf of Mexico OCS. In: OTC 21697. Offshore Technology Conference, Houston, TX, May 2 5. Gearhart, R.L., 2011. Wooden shipwrecks of the Central and Western Gulf of Mexico. In: OTC 27835. Offshore Technology Conference, Houston, TX, May 2 5. Guo, B., Song, S., Ghalambor, A., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX. Hadley, C., Bradford, K., Young, A., Trandafir, A.C., Bruce, B., 2017. Integrated study of a complex seabed for the Stones FPSO. In: OTC 27835. Offshore Technology Conference, Houston, TX, May 1 4. Hall, J.D., Bullard, D.B., Gray, W.M., Drew, M.C., 2004. Falcon corridor: infrastructure with future marginal fields in mind. In: OTC 16527. Offshore Technology Conference, Houston, TX, May 3 6. Haneberg, W.C., Bruce, B., Drazba, M.C., 2013. Using quantitative slope hazard maps and quantitative probabilistic slope stability models to constrain least-cost pipeline route optimization. In: OTC 23980. Offshore Technology Conference, Houston, TX, May 6 9. Hill, A.W., Hampson, K.M., Hill, A.J., Golightly, C., Wood, G.A., Sweeney, M., et al., 2015a. ACG field geohazards management: unwinding the past, securing the future. In: OTC 25870. Offshore Technology Conference, Houston, TX, May 4 7. Hill, A.J., Hampson, K.M., Prakash, A., Mackenzie, B., Rushton, D., 2015b. Geotechnical challenges in the Caspian Sea. In: OTC 25988. Offshore Technology Conference, Houston, TX, May 4 7. Hill, A.W., Walls, A.H., Romo, L.A., Turnbull, J.B., Rogers, L., 2013. Past, present and future marine geohazard issues: developing processes to address developing industry concerns. In: OTC 24248. Offshore Technology Conference, Houston, TX, May 6 9. Hill, A.W., Wood, G.A., 2015. Managing marine geohazard risks over the full business cycle. In: SPE/IADC 173139. SPE/IADC Drilling Conference and Exhibition, London, UK, March 17 19. Hoffman, J.S., Kaluza, M.J., Griffiths, R., McCullough, G., Hall, J., Nguyen, T., 2004. Addressing the challenges in the placement of seafloor infrastructure on the East Breaks slide a case study, the Falcon field (EB 579/623), northwestern Gulf of Mexico. In: OTC 16748. Offshore Technology Conference, Houston, TX, May 3 6. Jeanjean, P., Hill, A., Taylor, S., 2003. The challenges of siting facilities along the Sigsbee Escarpment in the southern Green Canyon area of the Gulf of Mexico: framework for integrated studies. In: OTC 15156. Offshore Technology Conference, Houston, TX, May 5 8. Mannaerts, H., Oldroyd, J., Williams, M., Fisher, R., Radjef, E., Day, R., et al., 2005. Atlantis, the quest for its stray shallow water flow sands. In: OTC 17658. Offshore Technology Conference, Houston, TX, May 2 5. Nadim, F., Krunic, D., Jeanjean, P., 2003. Reliability method applied to slope stability problem: estimating annual probabilities of failure. In: OTC 15203. Offshore Technology Conference, Houston, TX, May 5 8.

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Nodine, M.C., Gilbert, R.B., Wright, S.G., Cheon, J.Y., Wrzyszczynski, M., 2007. Impact of hurricane-induced mudslides on pipeline. In: OTC 23519. Offshore Technology Conference, Houston, TX, Apr 30 May 3. Orange, D.L., Angell, M.M., Bland, J.R., Thomson, J., Buddin, T., Williams, M., et al., 2003. Geological and shallow salt tectonic setting of the Mad Dog and Atlantis fields: relationship between salt, faults, and seafloor geomorphology. In: OTC 15157. Offshore Technology Conference, Houston, TX, May 5 8. Oynes, C.C., 2000. Deepwater Chemosynthetic Communities, NTL 2000-G20. Department of the Interior, Minerals Management Service, New Orleans, LA. Primez, C., Marr, J., Shipp, C., Kopp, F., 2004. Observations and numerical modeling of debris flows in the Na Kika Basin, Gulf of Mexico. In: OTC 16749. Offshore Technology Conference, Houston, TX, May 3 6. Tootill, N.P., Vandenbossche, M.P., Morrison, M.L., 2004. Advances in deepwater pipeline route selection a Gulf of Mexico case study. In: OTC 16633. Offshore Technology Conference, Houston, TX, May 3 6. Williamson, S.C, Zois, N., Hewitt, A.T., 2008. Integrated site investigation of seafloor features and associated fauna, Shenzi field, deepwater Gulf of Mexico. In: OTC 19356. Offshore Technology Conference, Houston, TX, May 5 8. Wincheski, R., Bertrand, C., Dampman, B., Eisenhauer, D., 2002. Brutus export pipelines improvement opportunities and challenges in deepwater pipeline installation. In: OTC 13994. Offshore Technology Conference, Houston, TX, May 6 9.

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PIPELINE INSTALLATION AND VESSEL SPECIFICATIONS

5

Pipelay vessels range in complexity from traditional moored barges that lay pipe in shallow water to dynamically positioned ship-shaped vessels, which can lay large diameter pipe in ultradeepwater and perform multiple functions including platform and subsea construction. In this chapter, pipelay installation techniques are described, and vessel specifications are defined. The primary physical specifications of pipelay vessels are described by hull type, vessel size, lay system, and station keeping, which determine in part secondary operational characteristics, such as water depth capacity, lay rates, and maximum pipeline diameters. Pipelay vessels are not designed and specified by a single value for any operational characteristic, but rather parameters range over values depending on the specific project and environmental criteria. Key relationships between vessel attributes for the world fleet c.2020 are examined.

5.1 INSTALLATION TECHNIQUES Lay barge construction is by far the most frequently used technique for marine pipeline construction. In S-lay and J-lay systems, sections of pipe are welded together on the deck of the vessel, which is then lowered to the seabed as a continuous string of pipe as the vessel moves forward. In a reel-lay system, the pipeline is assembled onshore and spooled onto the installation vessel. Once on location, the spool is paid out, and the pipeline is guided into the water via a tower or ramp equipped with a straightener and a tensioner. Towing fully assembled pipeline from shore to site has also been employed but is not common.

5.1.1 S-LAY SYSTEM In S-lay systems, tensioners apply a tension force to the pipe near the stern, and the pipe is supported on rollers by a stinger structure where it enters the water (Fig. 5.1). As a pipe is laid, it is first bent in one direction at the stinger (overbend) and then moves through the suspended section and the underbend (sagbend), where it is bent in the reverse direction to the touchdown point. The shape of the overbend is controlled primarily by the stinger, a steel framework that provides support for the overbend, while tension devices serve to control the pipe in the sagbend (Fig. 5.2). The shape of the sagbend depends on the interaction between the applied tension and submerged weight of the pipe (Palmer and King, 2008). If the applied tension is increased, the curvature in the sagbend decreases, and the sagbend becomes longer and flatter and the lift point moves up the

The Offshore Pipeline Construction Industry. DOI: https://doi.org/10.1016/B978-0-12-820288-3.00005-6 © 2020 Elsevier Inc. All rights reserved.

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FIGURE 5.1 S-lay pipeline installation method. From Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

FIGURE 5.2 Diagram of the S-lay system on Allseas Solitaire. Adapted from Allseas.

stinger. Conversely, if the applied tension is reduced, the sagbend curvature increases, and if the bending becomes excessive, the pipe may buckle. The place for a buckle to occur during pipe laying is most likely the sagbend just before touchdown on the seabed.

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Normal installation practice limits the allowable stresses in the overbend and sagbend to about 0.20% and 0.15% strain in the pipe, and from this, the required stinger configuration and pipe tension are calculated (Bianchi and Pulici, 2001). The tension applied to the pipe controls the curvature in the sagbend and reacts on the vessel, which has to maintain its position, suggesting a correlation arises between tension capacity and power requirements of vessels. In S-lay systems, a firing line composed of welding, nondestructive evaluation (NDE), and field joint application stations runs down the length of the vessel and terminates in a stinger that guides the pipeline into the water. Before operations commence, the pipelay stinger is checked above sea water (Fig. 5.3), and after lowering, construction begins. After welded pipe joints from the firing line exit the tunnel (Fig. 5.4), they move over the stinger and into the sea (Fig 5.5).The firing line may run down the center of the vessel or the port or starboard side (Fig. 5.6). On shipshaped vessels, the firing line is often in the center of the vessel to take advantage of extra space in the ship’s bow. Typical lay rates are 2 4 km/day. Pipe is transferred to the vessel on cargo barges to maintain continuous operations (Fig. 5.7). Welding is one of the most critical operations to construction efficiency. Welding procedure specifications must be developed for the pipeline and welders must be qualified on these procedures. Welding procedure specifications specify the type of pipe to be welded (specification, grade, etc.), the type and specification of the pipe joint (bevel(s), angle, shoulder, spacing, etc.), the

FIGURE 5.3 Pipe lay stinger checked above sea water.

FIGURE 5.4 Welded pipeline joints from the firing line before entering water.

FIGURE 5.5 Pipeline exiting tunnel over stinger and into the sea.

FIGURE 5.6 Pipelaying vessel with stinger port side and materials barge with pipe joints waiting to be transferred to vessel starboard.

FIGURE 5.7 Coated line pipe on cargo barge alongside pipe lay vessel ready for transfer.

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FIGURE 5.8 Bevels on pipeline facilitate mating and reliable welding.

FIGURE 5.9 Weld passes for pipeline construction.

material thickness or range of thickness, the type and size of welding rods, the position and direction of the weld, etc. Welding begins with two beveled pipes (Fig. 5.8), with shapes that vary depending on if the pipeline is to be welded from the inside and if automatic or manual welding is to be conducted. The pipes are aligned using internal or external clamps (internal clamps are typical for large diameter pipelines), and the weld area is often preheated to ensure the pipeline is dry before welding. The first and most critical weld is the root pass (Fig. 5.9), which joins the nonbeveled lands or roots of the pipeline, followed by a series of additional passes (Box 5.1).

BOX 5.1 ROOT, HOT, FILLER, AND CAP PASSES The root pass is typically conducted from the outside of the pipeline, but care must be taken to avoid the formation of metal protrusions (sometimes called “icicles”) into the inside (Palmer and King, 2008). The next weld is the hot pass that is applied before the root pass has time to cool. The purpose of the hot pass is to remove deficiencies in the root pass. On completion, the hot pass is cleaned to bare metal and all welding slag removed. Filler passes are frequently conducted by automatic or semiautomatic welding machines (Fig. 5.10), which can rapidly lay down large volumes of weld material. The filler passes fill the gap left by the bevel and are made with a slight weave from side to side, which helps ensure complete fusion of the pipeline walls. Several welding stations are employed throughout the firing line normally manned by four to six individuals (Fig. 5.11). The final weld is the cap pass or cover weld. The cap pass fills the residual groove leaving the weld approximately 1 mm above the pipe surface and with an overlap of the pipe of approximately 1 2 mm. After welding is completed, the weld is tested for defects by X-ray or ultrasonic evaluation. Following this NDE process, a field joint is applied to protect the weld area from corrosion. A heat shrink sleeve is applied around the pipeline’s circumference, and a mold is placed over the pipeline. A polyurethane foam is then pumped into the mold and allowed to harden (Fig. 5.12).

FIGURE 5.10 Operator controlled automatic welding of a pipeline. (Continued )

BOX 5.1 (CONTINUED)

FIGURE 5.11 Pipeline welding station in pipe tunnel and crew.

FIGURE 5.12 Polyurethane foam being pumped into a joint mold. From Nord-Steam.

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In deepwater, S-lay installations become increasingly constrained by the greater weights and tension requirements. Laying deeper implies getting stronger, since the increasing water depth results in an increase in the pipeline spanning the water column, requiring increased holding tensions (Faldini et al., 2014). Stinger length could be increased, but long stingers are vulnerable to wave and current forces. High tension is undesirable because of damage to the pipe coating and greater power requirements to maintain position (Perinet and Frazer, 2007). The angle of the stinger may be adjustable on higher specification vessels. Steep angles are required with greater water depths.

EXAMPLE: PERDIDO S-LAY The Allseas Solitaire installed Perdido’s oil and gas export pipelines using the S-lay method. The 120-km oil line was laid in 27 days, and the 168-km gas line was laid in 33 days (Connelly et al., 2009). The 60-day installation time included installation of four inline structures, two on each line, one pipeline end termination and one pipeline end manifold.

5.1.2 J-LAY SYSTEM In J-lay, the pipe is assembled on a vertical tower, and the pipeline enters the water at a vertical or near vertical angle, hanging like a cable and gently curving toward the horizontal as it approaches the seabed (Fig. 5.13). Tensions are significantly reduced, spans are shorter, and touchdown points

FIGURE 5.13 J-lay installation process. From Guo, B., Song, S., Ghalambor, A., Ranlin, T., 2014. Offshore Pipelines: Design, Installation, and Maintenance, second ed. Gulf Professional Publishing, Houston, TX.

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are not as far behind the installation vessel, which are easier to monitor and position (Springmann and Hebert, 1994). However, because the ramp is high above the sea level (Fig. 5.14), the line-up, welding, field joint application, and other activities are constrained, reducing the weld and lay rate (Cavicchi and Ardavanis, 2003; Faldini, 1998; McDonald et al., 1998). Typical lay rates are 2 3 km/day.

Pipe elevator

Adjuster

Upper tower

Welding station Lower tower Tensioners

Beveling station

Saipem

Thrusters

Crane base

7000

Pipeline

FIGURE 5.14 Schematic of a J-lay system on Saipem 7000. Adapted from Saipem.

J-lay systems are best suited for ultradeep ( . 5000 ft) pipeline installation, and because it has the smallest bottom tension of all methods, it has high flexibility for route layout in congested areas. J-lay systems can typically handle inline appurtenances with relative ease but may not be feasible in shallow water. The first application of J-lay was the 20-in Maui project laid in 1992 in 105 m water depth, west of the North Island of New Zealand in the Tasman Sea, by Heerema’s Balder semisubmersible. The second application of J-lay was in 1993 by McDermott’s DB50 derrick barge, which laid the 12-in Auger pipeline in 870 m of water in the Gulf of Mexico.

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5.1.3 REEL-LAY METHOD The reel method was first used to lay pipeline across the English Channel during World War II (Hartley, 1946) and applied in the offshore oil and gas industry in the 1960s in the Gulf of Mexico when Gurtler Hubert converted a landing-ship hull into a reel barge and laid a 6-in pipe from a vertical axis, horizontal reel (Timmermans, 2000). Reel-lay installation is initiated with an anchor and wire, and the pipeline is reeled off by passing over an aligner and then through the straightener system located on the vessel ramp (or tower). The pipe is reverse bent in the straightener system to remove the residual curvature from the reel (Fig. 5.15). It then passes through tensioners that grip the pipe and apply an upward force to maintain the catenary of the pipeline as it passes down from the vessel to the seabed. Reel-lays are well suited for small diameter lines (,18 in) and small diameter-to-thickness ratios, and if the entire pipeline can be stored on board, a very fast installation campaign can be achieved. If recharging trips to the spooling base are needed to re-load, lay rates will be reduced, and so the capacity of the reel is critical (Fig. 5.16). Concrete coated pipes cannot be reel-laid, but pipe-in-pipe systems can be reel-laid. The technology for reel-lay was acquired by Fluor in the 1970s, and Sante Fe designed and built the reel ship Apache in 1979, which was later acquired by TechnipFMC. Global Industries operated two horizontal reel barges, Chickasaw and Hercules, before being acquired by Technip in 2011 (Smith and Clough, 2010). EXAMPLE: REELED PIPE-IN-PIPE AT CANAPU At the Canapu field offshore Brazil in 1608 m water depth, Technip installed a pipe-in-pipe system using reel-lay to deliver reservoir gas to a FPSO; the gas is then exported to shore (de Azevedo et al., 2009). The pipe-in-pipe system consists of an 8-in inner pipe inserted in a 13-in outer pipe and insulated with an aerogel.

BOX 5.2 YOUTUBE VIDEOS WORTH WATCHING! YouTube videos on pipelay vessels and construction activity opens a world that is otherwise inaccessible and is a great resource for those who want to learn more about the field. The content and quality of videos are highly variable, of course, but a few gems can always be found with enough patience. A random sample follows. Title, Length Nord Stream 2—Concrete weight coating in Kotka and Mukran, 3 min Van Oord flexible pipe vessels, 2 min Flexible subsea pipe systems, 1.5 min Wellstream flexible pipeline, 3.3 min Greystones S-lay carbon steel pipeline, 3.3 min Sailor rations in the 18th century—burgoo, 7.2 min Offshore pipelay, 13.3 min Sapura 3000—offshore pipelay vessel in Brunei, 6.4 min North Sea pipeline documentary, 46.6 min Offshore pipeline construction, 6.2 min (Continued )

BOX 5.2 (CONTINUED) Spoolbase pipeline fabrication, 9.3 min Pioneering Spirit first heavy lift, 21.5 min Derrick Barge 30 mobilization, 4 min Why do big ships float? 4.2 min Why are ships so slow? 7.1 min Derrick lay vessel 2000, 3.3 min Gulfport spoolbase, 2.2 min How do you weigh a ship? 5 min Solitaire pipelaying vessel Parts 1 and 2, 9.4 and 9.4 min Production of seamless and welded precision steel tubes, 11.4 min

FIGURE 5.15 Schematic of a reel-lay system. Adapted from Christiani, E., 2014. Ultra deepwater reel and flexible pipelay vessel for pre-salt field developments. In: OTC 25288. Offshore Technology Conference, Houston, TX, May 5 8.

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FIGURE 5.16 A reel on North Ocean 105. From McDermott.

5.2 VESSEL SPECIFICATIONS Pipelay vessels are a subclass of construction service vessels (CSVs) used primarily, but not exclusively, for pipeline installation. CSVs are a general vessel class used to install pipelines, platforms, subsea equipment, and related field infrastructure and include derrick barges, heavy-lift vessels, pipelay vessels, cargo barges, dive support vessels, and other vessel types.

5.2.1 HULL Three basic hull shapes are used in pipelay vessels. Ship-shaped hulls are the most common hull type in the pipelay fleet and are the easiest to construct. Barge hulls are box shaped and also simple to construct, standard on low-specification legacy vessels, but are no longer commonly built for pipelay activity (Hunt and Butman, 1995). Semisubmersibles are composed of a flat deck supported by columns connected to underwater pontoons. By varying the amount of ballast in the columns, the depth of the pontoons varies, controlling vessel stability. Semisubmersible hulls are common on heavy-lift vessels, and several of these vessels have been fitted with pipelay equipment. The hull is described by length, beam, and depth. Length overall (LOA) is associated with vessel stability and functional capabilities, including the length of the firing line, pipe storage capacity,

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FIGURE 5.17 Size comparison of the pipelay installation vessels Solitaire, FDS2 and Super Chief.

installed power, and other specifications. When naval architects design a vessel, cost is controlled by designing the smallest vessel that can meet the desired design specifications; consequently, length is often considered a reasonable proxy for vessel capability (Paik and Thayamballi, 2007). Most shallow water barges are around 200 ft LOA (Fig. 5.17), and the largest pipelay vessel in the fleet c.2020 is Allseas 1253 ft Pioneering Spirit. Over half of the pipelay vessel fleet c.2020 are between 300 and 500 ft in length, and only a few vessels are greater than 700 ft (Fig. 5.18). Draft, the depth the vessel extends below the waterline, impacts a vessel’s ability to work in shallow water and transition zones and the vessel’s stability (Gerwick, 2007). Barge-type hulls are particularly useful in shallow water due to their low drafts; semis large drafts increase stability. Beam is the width of a vessel, and relative to other ship classes, pipelay vessels typically have large beams for their length. Beam is related to the vessel stability, storage capability, deck space, and other characteristics (Lamb, 2004). Semis have especially large beams because of the functional requirements associated with large deck spaces to hold and move equipment in construction and installation activities.

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FIGURE 5.18 Distribution of lengths of pipelay vessels in the global fleet c.2020. Data from annual reports, company websites, Offshore Magazine.

5.2.2 PIPELAY EQUIPMENT S-lay systems are described principally by the tension capacity, stinger geometry, and the number of welding, repair, NDE, and field joint stations. J-lay systems are described by tension capacity and the length of pipe that can be accommodated on the tower (single, double, triple, or quadruple joints). Reel-lay systems are described by tension machine and tension capacity and the storage capacity (diameter) of the reels. There are only a few vessels that can perform both S-lay and J-lay operations, but many J-lay vessels can also perform reel-lay.

5.2.3 STATION KEEPING Vessels maintain position using mooring systems or dynamic positioning. Station keeping is important during pipelay since sudden unexpected movements may bend the pipeline, which may buckle or kink. In conventional mooring, mooring lines connected to the vessel are used to keep the vessel in position and move the vessel forward along the pipeline route. The mooring lines are typically made of wire rope, and the anchors are conventional drag-embedded anchors.

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FIGURE 5.19 McDermott’s DLV2000, an S-lay vessel with azimuth and tunnel thrusters for DP3. Adapted from McDermott.

Mooring systems range from 4- to 14-point lines and require one or two anchor-handling tug (AHT) vessels to remain on site for the duration of the operation to position and move the anchor system forward. A typical anchored third-generation semisubmersible, such as Allseas Piper, has 14 mooring lines each 3050 m long. If 12 anchors are in operation, each one must be relocated once every 3000 m of progress. If the barge is laying at 6000 m/day, one anchor must be relocated every hour. The number of anchors needed depends on the expected current, wind, sea state, and water depth. Dynamic positioning (DP) is a station-keeping system in which the vessel is held in position or moves using on-board thrusters in conjunction with global positioning technology. A DP system consists of a control, a sensor, a thruster, and a power system. A computer receives input from wave, wind, and current sensors and responds automatically, compensating for movement. DP systems are specified by their redundancy and segregation and may be double (DP2) or triple (DP3) redundant (Fig. 5.19). DP systems increase construction costs and operating expenses

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FIGURE 5.20 Relationship between water depth and vessel length of pipelay vessel fleet c.2020. Data from annual reports, company websites, Offshore Magazine.

relative to moored systems but eliminate the need for AHT vessel support. All deepwater lay vessels require DP2 or DP3 systems.

5.2.4 WATER DEPTH The operating water depth of a pipelay vessel is determined primarily by its station-keeping system, lay system, and tension capacity. S-lay vessels are typically limited to 3000 8000 ft depending on the length and angle of the stinger due to the stresses on the pipeline, while J-lay systems can operate in up to 10,000 ft of water but are usually not feasible in shallow water. In general, larger vessels can operate in deeper water than smaller vessels, but the range is large (Fig. 5.20). DP systems are typically required for water depths over 3000 ft due to limitations in mooring systems.

5.2.5 WORK STATIONS Pipeline construction requires welding joints, evaluating the quality of the joints, repairing weld defects, coating with an anticorrosion protectant, and then laying the line to the seafloor. Work stations are the location on the vessel where welding, NDE, weld repair, and field joint applications are performed. A single work station may be used for welding, NDE, repair, and field joint application, and these tasks may be divided among separate stations to improve work efficiencies.

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EXAMPLE: SAIPEM’S FDS2 WORK STATIONS Saipem’s field development ship FDS2 dedicates different lines to different tasks (Fig. 5.21). Pipe racks and loading areas are located on opposite sides of the vessel, and the firing line runs down the center (Faldini and Chiesa, 2012). A conveyor line is used for the single joint loading, beveling, and anode installation. A middle firing line for quad joints construction has eight working stations for welding and one for nondestructive testing. A firing ramp has a repair line and a second firing line for construction.

FIGURE 5.21 Deck area and working stations for Saipem’s FDS2. Adapted from Saipem.

Welding can be performed manually or automatically with bugs or both. Automatic welding is common. As the number of work stations used for welding increases, the number of welding passes that need to be performed at stations decreases, shortening the amount of time the pipe must remain at a single station, often increasing the lay rate. The total number of stations on S-lay vessels usually ranges from three to eight, with about half of these typically dedicated to welding and the remainder to field joint application and NDE. If the number of effective welding stations (EWS) is defined by the product of the number of welding stations (NWS) and the number of joints permitted per welding station (NJPS), then a positive

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FIGURE 5.22 Vessel length and the effective number of welding stations in the S-lay vessel fleet c.2020. Data from annual reports, company websites, Offshore Magazine.

correlation is observed between vessel length and EWS among the vessel fleet (Fig. 5.22). On Slay vessels, longer vessels typically have more welding stations. On J-lay vessels, work stations are placed on the J-lay tower, and two stations (one for welding and one for NDE, repair, and field joint application) are typical.

5.2.6 TENSIONERS Tensioners hold the pipeline in tension from the point it leaves the vessel to where it is laid on the seafloor and is measured in metric tons or kips, where 1 kip 5 1000 lbs, and 1 mt 5 1000 kg 5 2205 lbs. The weight of the pipeline in the water column and the manner it is installed determines the stresses induced on the vessel and pipeline. The capacity of the tensioning system determines the weight of pipe that can be supported to the seafloor, which determines the size of pipes that may be installed and the water depth limitation. Capacities of 25 100 mt are typical for older, conventionally moored vessels that operate exclusively in shallow waters, and capacities of 100 400 mt are typical for the majority of vessels in the fleet. Several high-specification vessels have tensioner capacities exceeding 400 mt, and the maximum tension capacity in the fleet c.2020 is 2200 mt.

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FIGURE 5.23 Vessel length, maximum water depth, and tensioner capacity for pipelay fleet c.2020. Data from annual reports, company websites, Offshore Magazine.

Larger vessels have higher tensioner capacities, and vessels with higher tensioner capacities can operate in deeper water (Fig. 5.23). Vessels operating in water depth greater than 6000 ft generally have at least 500 kips tensioner capacity.

EXAMPLE: WATER DEPTH AND PIPE WEIGHT RELATIONSHIP AT LEWEK CONSTELLATION The Lewek Constellation is a 585 ft pipelay vessel with a 640 mt tensioning system. The sizes of pipe that can be handled are bound by the minimum reelable wall thickness, the minimum wall thickness to resist collapse, and the maximum static top tension. For wall thicknesses over 25 mm, the maximum water depth of installation decreases as the wall thickness increases due to the increasing pipe weight that must be supported (Fig. 5.24). For wall thickness less than 25 mm, the limits on collapse resistance are controlling, and the relationship is reversed. For example, for an 8-in diameter pipe with a 15 mm wall thickness, the maximum water depth is about 3000 m because the pipe may collapse, but at 20 mm wall thickness, the maximum water depth increases to 4000 m. At a wall thickness of approximately 25 mm, the limiting factor changes from pipe collapse to the capacity of the 640 mt tensioning system, and increasing wall thickness is associated with decreasing maximum water depths (Christiani, 2014).

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FIGURE 5.24 Relationship between wall thickness, outside diameter, and water depth for Lewek Constellation operation. Adapted from Christiani, E., 2014. Ultra deepwater reel and flexible pipelay vessel for pre-salt field developments. In: OTC 25288. Offshore Technology Conference, Houston, TX, May 5 8.

5.2.7 POWER Power is required for tension capacity and station keeping for DP vessels, as well as deck equipment, electrical, utilities, remotely operated vehicle systems, saturation diving systems, and reel deployment systems. For both S-lay and J-lay vessels, the installed power and tension capacities are reasonably correlated (Fig. 5.25). DP vessels require more power than moored vessels, for all other things equal. Circa 2020, installed power on the DP pipelay fleet ranged from 10 to 95 MW and averaged 30 MW; for moored vessels, power requirements ranged from 1 to 5 MW and averaged 2 MW.

EXAMPLE: CASTORONE AND DB30 POWER REQUIREMENTS Saipem’s DP3 class CastorOne has 67 MW of installed power, and McDermott’s DB30 has 3 3 910 kW 1 1 3 1360 kW main generators and 1 3 320 kW emergency generator installed power.

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FIGURE 5.25 Installed power and tension capacity relationship for S-lay and J-lay vessel fleet c.2020. Data from annual reports, company websites, Offshore Magazine.

5.2.8 CRANES Cranes and winches are used to abandon and recover pipes on the seafloor, to transfer pipe from supply vessels, and, on heavy-lift vessels, for other construction activities. Abandonment and recovery operations typically occur at the commencement or end of pipelay operations, and the vessel’s crane must be capable of lifting the pipeline weights supported by the tensioner. Smaller auxiliary cranes are used to load pipe onto the vessel and to move pipe around the deck. For automated systems, the pipe is moved by conveyor from one location to another.

5.2.9 ACCOMMODATIONS Operations are carried out 24 hours a day using crews working 12-hour shifts on a 14, 21, or 28 on/off day cycle. J-lay and S-lay vessels have similar personnel requirements, but the variation in S-lay accommodations is much greater due to the differences in vessel specifications; that is,

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FIGURE 5.26 Number of accommodations by effective welding stations for pipelay fleet c.2020. Data from annual reports, company websites, Offshore Magazine.

several low-spec barges have small accommodation capacity (as low as 25) and a few high-spec vessels maintain large accommodations (up to 700). Reel systems require fewer personnel, normally between 100 and 175, because pipeline fabrication occurs onshore. Accommodation capacity is measured by bed count and is only weakly related to the number of welding stations (Fig. 5.26).

5.2.10 OTHER CAPABILITIES Vessels may be built exclusively for pipelay, or pipelay services may be offered as part of more general construction capabilities. Semis and barges are frequently designed to accommodate other tasks while ship-shaped vessels are more likely to specialize. McDermott’s DB50 and Heerema’s DCV Balder, for example, are general purpose heavy-lift derrick barges that generate a significant portion of their revenue from construction lift operations.

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5.3 CLASSIFICATION AND REGISTRATION Almost every offshore construction vessel, barge, or floating object must have classification and registration certificates of compliance to the rules and regulations as dictated and published by the classification society and country of registration. Classification is normally required for the vessel to qualify for marine insurance, to obtain bank loans, and to comply with the operator’s contract requirements. Classification began as an indication of seaworthiness and vessel condition in the late 1700s in England. Edward Lloyd, proprietor of Lloyds Coffee House in London, started to circulate lists giving details of vessels which might appear for insurance. In 1764, the first register of ships was published by insurers and insurance brokers. As the class movement developed in the nineteenth century, the role of classification societies changed from grading ships to setting the standards to which ships should be built and maintained (Stopford, 2004). Other classification societies were subsequently set up in other countries, such as the American Bureau of Shipping, which was incorporated in 1862. In 1968, the International Association of Classification Societies was established, and in 2020 the major classification societies are American Bureau of Shipping, Bureau Veritas, Der Norske Veritias, Lloyd’s Register, and Nippon Kaiji Kyokei. Classification societies are privately owned for-profit companies that work closely with, but independent of, government bodies. Today, the main job of classification societies is to set the standards for establishing that a vessel is properly constructed and in good condition. Classification societies have no legal authority, however, and they compete with each other to offer services to vessel owners. Rules need continuous updating to reflect changes in marine technology. Societies apply the rules adopted to vessel construction and operations in a three-step procedure: 1. Technical plan review. The plans of the vessel are submitted to the classification society for inspection, and to ensure that the design conforms to the rules. 2. Construction surveys. During construction, surveys are performed to verify the approved plans are implemented and good workmanship practices are employed. 3. Periodic survey. To maintain classification, periodic surveys are performed for the maintenance of class. As vessels grow older, the scope of inspection widens to cover areas that are vulnerable to aging. Registration refers to the country of home port for the vessel. Each country of registry has rules and regulations focused on safety, communication, lifting and cargo gear, pollution, and pollution containment. Each registry has different rules and regulations, and the most popular registries are Panama, Liberia, and the Marshall Islands. The United States, England, Norway, and other industrial countries are not common registries because of their more complicated rules, regulations, and staffing requirements.

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BOX 5.3 PIPE FABRICATION Line pipe are primarily of two different types, seamless and welded.

Seamless Pipe Rolling is the most widely used method of shaping metals. It may be done while the metal is hot (hot rolling) or cold (cold rolling). The process consists of passing the metal between pairs of revolving rollers. Seamless pipe begins as a round billet that is heated in a rotary furnace to make malleable. Billet for pipeline fabrication has round cross section with an area equal to or greater than 16 in2 and width less than five times its thickness. The billet is formed into a pipe by means of a piercer, then goes through a series of finishing steps that are designed to reduce the wall thickness to the specified width, ensure that the outside diameter matches specifications, and ensure circularity. The pipe is heated and cooled at a predetermined rate to relieve the stresses created during the rolling process and obtain the desired steel grain structure, hardness, and strength. Seamless pipe is primarily used for small diameter pipelines and is generally available in diameters up to 16 in.

Welded Pipe Welded pipe is classified based on how it is formed and the type of welding technique used (ICF, 2017).

Shaping Techniques There are five commonly used shaping techniques that accept steel plate and coil as inputs (Fig. 5.27). •

U-O-E forming: A flat plate is first bent into a U-shape using hydraulic presses by pushing down on the center of the plate along the length (Fig. 5.28). The U-shaped plate is then formed into an O-shape in a die that forces the two edges together. The two edges are welded and the pipe is expanded using a mandrel or hydraulic pressure. Heat treatment is the final step to relieve pipe stresses.

Plate

Pyramid rolling pipe mill

SAW/DSAW line pipe

J-C-O rolling pipe mill

SAW/DSAW line pipe

U-O-E rolling pipe mill

SAW/DSAW line pipe

Spiral pipe mill

Spiral SAW/DSAW line pipe

Form rolling pipe mill

ERW line pipe generally